<PAGE>
As filed with the Securities and Exchange Commission on October 7, 1999
Registration No. 333-83815
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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Amendment No. 1
To
FORM S-4
REGISTRATION STATEMENT
Under
The Securities Act of 1933
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CAITHNESS COSO FUNDING CORP.
(Exact name of Registrant as specified in its charter)
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<S> <C> <C>
Delaware 525990 94-3328762
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
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<TABLE>
<S> <C> <C> <C>
Coso Finance Partners California 221119 68-0133679
Coso Energy Developers California 221119 94-3071296
Coso Power Developers California 221119 94-3102796
(Exact names of (State or other (Primary Standard
Registrants as jurisdiction of Industrial (I.R.S. Employer
specified in their incorporation or Classification Code
charters) organization) Number) Identification No.)
</TABLE>
1114 Avenue of the Americas, 41st Floor
New York, New York 10036-7790
(212) 921-9099
(Address, including zip code, and telephone number, including area code, of
Caithness Coso Funding Corp.'s principal executive offices)
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Christopher T. McCallion
Executive Vice President and Chief Financial Officer
Caithness Coso Funding Corp.
1114 Avenue of the Americas, 41st Floor
New York, New York 10036-7790
(212) 921-9099
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
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With a Copy to:
Mitchell S. Cohen, Esq.
Riordan & McKinzie
300 South Grand Avenue, 29th Floor
Los Angeles, California 90071
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Approximate date of commencement of proposed sale to the public: As soon as
practicable after this Registration Statement becomes effective.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance
with General Instruction G, check the following box: [_]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [_]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
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<PAGE>
PROSPECTUS
Caithness Coso Funding Corp.
Offer to Exchange
Any and All Outstanding 6.80% Series A Senior Secured Notes due 2001
for
6.80% Series B Senior Secured Notes due 2001
and
Any and All Outstanding 9.05% Series A Senior Secured Notes due 2009
for
9.05% Series B Senior Secured Notes due 2009
This is an offer to exchange any and all outstanding, unregistered Caithness
Coso Funding Corp. 6.80% Series A Senior Secured Notes due 2001 you now hold
for new, substantially identical 6.80% Series B Senior Secured Notes due 2001
and any and all outstanding, unregistered Caithness Coso Funding Corp. 9.05%
Series A Senior Secured Notes due 2009 you now hold for new, substantially
identical 9.05% Series B Senior Secured Notes due 2009. The 6.80% Series A
Senior Secured Notes due 2001 and the 9.05% Series A Senior Secured Notes due
2009 are called the Series A notes, and the new 6.80% Series B Senior Secured
Notes due 2001 and the new 9.05% Series B Senior Secured Notes due 2009 are
called the Series B notes. As of the date of this prospectus, there is $413.0
million aggregate principal amount of Series A notes outstanding. The Series B
notes will be registered under the Securities Act of 1933 and will therefore be
free of the transfer restrictions that apply to the Series A notes.
This exchange offer will expire at 5:00 p.m., New York City time, on Monday,
November 8, 1999, unless we extend the expiration date. You must tender your
Series A notes before the exchange offer expires to obtain the respective
Series B notes and the liquidity benefits they offer. Only Series B notes due
2001 may be exchanged for tendered Series A notes due 2001, and only Series B
notes due 2009 may be exchanged for tendered Series A notes due 2009. We will
exchange Series A notes only in integral multiples of $1,000.
We agreed with the initial purchaser of the Series A notes to make this
exchange offer and register the issuance of the Series B notes following the
closing of the issuance and sale of the Series A notes to the initial purchaser
of those notes. This exchange offer applies to any and all outstanding Series A
notes tendered before the exchange offer expires.
The Series B notes will not trade on any established exchange. The Series B
notes have the same financial terms and covenants as the Series A notes and are
subject to the same business and financial risks.
A description of those risks begins on page 34.
The terms of the exchange offer will include the following:
. We will exchange any and all outstanding Series A notes that are validly
tendered and not withdrawn before the exchange offer expires;
. You may withdraw your tender of Series A notes at any time before the
exchange offer expires; and
. We will not receive any proceeds from the exchange offer.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.
The date of this prospectus is October 7, 1999.
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TABLE OF CONTENTS
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Page
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Forward-Looking Statements............................................... i
Prospectus Summary....................................................... 1
Risk Factors............................................................. 34
The Exchange Offer....................................................... 50
Capitalization........................................................... 60
Selected Historical and Pro Forma Financial and Operating Data........... 62
Unaudited Pro Forma Financial Data....................................... 67
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 78
Business................................................................. 96
Summary Descriptions of Principal Agreements Relating to the Coso
Projects................................................................ 119
Regulation............................................................... 131
Management............................................................... 136
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Page
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Ownership.................................................................. 142
Certain Relationships and Related Transactions............................. 145
Description of Series B Notes.............................................. 150
Material Federal Income Tax Consequences of the Exchange Offer............. 200
Plan of Distribution....................................................... 201
Legal Matters.............................................................. 201
Change in Independent Accountants.......................................... 202
Experts.................................................................... 202
Available Information...................................................... 203
Index to Financial Statements.............................................. F-1
Exhibit A--Independent Engineer's Report
Exhibit B--Energy Markets Consultant's Report
Exhibit C--Geothermal Consultant's Report
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FORWARD-LOOKING STATEMENTS
This prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical facts
included in this prospectus regarding industry prospects, our prospects and our
financial position are forward-looking statements. Although we believe that our
expectations reflected in these forward-looking statements are reasonable, we
cannot assure you that our expectations will prove to be correct. We have based
these forward-looking statements on our beliefs, assumptions and expectations
and on information currently available to us. These statements involve known
and unknown risks, uncertainties and other important factors that could cause
actual results, performance or achievements to differ materially from the
results, performance or achievements expressed or implied by these statements.
Forward-looking statements are not guarantees of performance.
Under the safe harbor provisions of the Private Securities Litigation Reform
Act of 1995, we have identified some of these risks, uncertainties and other
important factors in "Risk Factors," in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and in the assumptions made
by our independent engineer, our energy markets consultant and our geothermal
consultant in their respective reports, copies of which are included in the
prospectus. You should also consider, among others, the following important
factors:
. general economic and business conditions in the United States;
. changes in governmental regulations affecting us and our affiliates, our
and their businesses and operations and the United States electric power
industry;
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<PAGE>
. general industry trends;
. changes to the competitive environment;
. power costs and resource availability;
. changes in business strategy, development plans or vendor or customer
relationships;
. availability, terms and deployment of capital; and
. availability of qualified personnel.
These forward-looking statements speak only as of the date of this
prospectus. We undertake no obligation to publicly update or revise any
forward-looking statements to reflect events or circumstances after the date of
this prospectus, and we do not assume any responsibility to do so.
ii
<PAGE>
PROSPECTUS SUMMARY
This summary may not contain all of the information that may be important to
you. We encourage you to read this entire prospectus, including the financial
data and the related notes, before deciding to tender your Series A notes in
the exchange offer. Whenever this prospectus uses the terms "we," "us," "our"
"ourselves" or "Funding Corp.," it is referring to Caithness Coso Funding
Corp., the issuer of the Series A notes and the Series B notes. We collectively
call the Series A notes and the Series B notes the senior secured notes.
The Issuer
We are a special purpose corporation and a wholly owned subsidiary of Coso
Finance Partners, which we call the Navy I partnership, Coso Energy Developers,
which we call the BLM partnership, and Coso Power Developers, which we call the
Navy II partnership. We call the Navy I partnership, the BLM partnership and
the Navy II partnership the Coso partnerships. We were formed for the purpose
of issuing the senior secured notes for ourselves and on behalf of the Coso
partnerships. The Coso partnerships have guaranteed our obligations to repay
the senior secured notes.
On May 28, 1999, we and the Coso partnerships completed the following
transactions:
. We sold $110.0 million of our 6.80% Series A Senior Secured Notes due
2001 and $303.0 million of our 9.05% Series A Senior Secured Notes due
2009 to Donaldson, Lufkin & Jenrette Securities Corporation, which we
call the initial purchaser of the Series A notes, under a purchase
agreement, dated May 21, 1999, among the initial purchaser, the Coso
partnerships and us. We call the sale of the Series A notes to the
initial purchaser the Series A notes offering;
. We loaned all of the proceeds from the Series A notes offering to the
Coso partnerships; and
. The Coso partnerships, in turn, caused the net proceeds from the Series A
notes offering, together with cash on their balance sheets and funds from
other sources, to (1) retire all Coso project debt that existed prior to
the Series A notes offering, including the payment of accrued and unpaid
interest and premiums, of approximately $150.7 million, (2) initially
fund the Debt Service Reserve Account established under a Deposit and
Disbursement Agreement dated as of May 28, 1998, which we call the
Depositary Agreement, in the amount of $50.0 million, (3) repay
approximately $216.9 million of short term debt, including accrued
interest, incurred by one of our affiliates to purchase all of the
remaining interests in the Coso projects as described under "--The
Purchase" below and (4) make distributions of the remaining balance to
the owners of the Coso partnerships other than the beneficial owners of
Caithness Energy, LLC, the sponsor of the Coso projects, which we call
Caithness Energy.
Also, concurrently with the closing of the Series A notes offering, Coso
Funding Corp., one of our other affiliates, purchased for cash all of its then
outstanding 8.53% Senior Secured Notes due 1999 and 8.87% Senior Secured Notes
due 2001, which we collectively call the 1992 Notes. The proceeds of the 1992
Notes were originally loaned by Coso Funding Corp. to the Coso partnerships,
and these loans constituted the existing project debt that was retired with a
portion of the proceeds from the Series A notes offering.
We have no material assets, other than the loans we made to the Coso
partnerships, and do not conduct any business, other than issuing the senior
secured notes and making the loans to the Coso partnerships. Our principal
executive offices are located at 1114 Avenue of the Americas, 41st floor, New
York, New York 10036-7790, and our telephone number is (212) 921-9099.
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The Coso Projects
The Coso projects consist of three 80 megawatt (MW) geothermal power plants,
which we call Navy I, BLM and Navy II, and their transmission lines, wells,
gathering system and other related facilities. The Coso projects are located
near one another in the Mojave Desert approximately 150 miles northeast of Los
Angeles, California, and have been generating electricity since the late 1980s.
Unlike fossil fuel-fired power plants, the Coso projects' power plants use
geothermal energy derived from the natural heat of the earth's interior to
generate electricity. Since geothermal power plants have no fossil fuel costs,
we believe our plants enjoy higher and more stable gross operating margins than
fossil fuel-fired power plants with similarly rated capacities.
The Navy I partnership owns Navy I and its related facilities, the BLM
partnership owns BLM and its related facilities and the Navy II partnership
owns Navy II and its related facilities. The Coso partnerships and their
affiliates own the exclusive right to explore, develop and use, currently
without any known interference from any other power developers, a portion of
the Coso Known Geothermal Resource Area. Since 1991, the Coso partnerships have
drilled 56 geothermal wells, approximately 91% of which have contributed to the
commercial production of geothermal energy.
The geothermal power plants, each of which has three separate turbine
generator units, have consistently operated above their nominal capacities, and
the combined average capacity factor for the plants has exceeded 100%, for each
of the last six years. For the six months ended June 30, 1999, the plants
operated at a combined average capacity factor of approximately 101.4%.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Southern California Edison Company, which we call Edison, under three
long-term Standard Offer No. 4 power purchase agreements. Each power purchase
agreement expires after the last maturity date of the senior secured notes.
Edison is one of the largest investor-owned electric utilities in the United
States. As of December 31, 1998, Edison reported in its 1998 annual report
total assets of $16.9 billion and operating revenues of $8.8 billion. Edison is
currently rated A1 by Moody's and A+ by Standard & Poor's.
Under the power purchase agreements, the Coso partnerships receive the
following payments:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the lives of the power
purchase agreements;
. Capacity bonus payments if they are able to produce electricity above a
specified higher level. The maximum capacity bonus payment available is
also fixed throughout the lives of the power purchase agreements; and
. Energy payments which are based on the amount of electricity their
respective plants actually produce.
Energy payments are fixed for the first ten years of "firm operation" under
the power purchase agreements. Firm operation was achieved for each Coso
partnership when Edison and that Coso partnership agreed that each generating
unit at that Coso partnership's plant was a reliable source of generation and
could reasonably be expected to operate continuously at its effective rating.
After the first ten years of firm operation and until a Coso partnership's
power purchase agreement expires,
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Edison makes energy payments to the Coso partnership based on Edison's "avoided
cost of energy." Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the relevant Coso partnership. The Navy I
partnership and the BLM partnership currently receive energy payments from
Edison based on Edison's avoided cost of energy. The Navy II partnership
receives energy payments from Edison based on higher fixed energy prices
provided for in its power purchase agreement and will continue to do so until
at least January 2000.
The Edison power purchase agreements will expire:
. in August 2011 for the Navy I partnership;
. in March 2019 for the BLM partnership; and
. in January 2010 for the Navy II partnership.
In addition to receiving payments under the power purchase agreements, the
Navy I partnership and the BLM partnership currently qualify for and receive
subsidy payments from a special purpose state fund established under California
Assembly Bill 1890, which we call AB1890. The California Energy Commission
administers the fund. AB1890 provides in part for subsidy payments from 1998
through 2001 to power generators using renewable sources of energy, including
geothermal energy, and who are being paid based on an avoided cost of energy
basis. Under AB1890, the Navy I partnership and the BLM partnership are
expected to continue to receive in the future subsidy payments for energy
delivered to Edison by the Navy I partnership or the BLM partnership, as the
case may be, whenever Edison's avoided cost of energy falls below 3.0c per
kilowatt hour (kWh). This subsidy is capped at 1.0c per kWh. We expect the Navy
II partnership to also qualify for these subsidy payments through 2001 once the
fixed energy price period under its power purchase agreement expires.
As of June 30, 1999, the unaudited combined net book value of the property,
plant and equipment of the Coso partnerships was approximately $466.2 million,
including approximately $158.0 million at the Navy I partnership, $161.1
million at the BLM partnership and $147.1 million at the Navy II partnership.
Operating Strategy
The Coso partnerships seek to maximize cash flow at the Coso projects through
active management of the Coso projects' cost structure and the Coso geothermal
resource. As a result of the closing of the purchase described in "--The
Purchase" below:
. The Coso partnerships retained two new operators at the Coso projects:
FPL Energy Operating Services, Inc., which we call FPL Operating, and
Coso Operating Company, LLC, which we call Coso Operating Company. FPL
Operating currently operates and maintains all three plants, the
transmission lines and the geothermal fields at the Coso projects under
three short-term operations and maintenance, or O&M, agreements with the
Coso partnerships. Coso Operating Company, which is one of our
affiliates, currently manages the geothermal resource, including well
drilling, under three additional O&M agreements with the Coso
partnerships. As discussed under "--Recent Developments--Purchase of FPL
Interests; Assignment of FPL O&M Agreements" below, FPL Operating is
currently expected to assign to Coso Operating
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Company all of its rights under FPL Operating's O&M agreements, and Coso
Operating Company is currently expected to assume all of FPL Operating's
duties and obligations under those O&M agreements. Coso Operating Company
will thereby become the sole operator of all of the plants and fields
located at the Coso projects, using substantially all of the same
personnel who are currently employed by FPL Operating and Coso Operating
Company at the Coso projects. Also:
. FPL Operating and Coso Operating Company retained substantially the
same employees who were employed by the prior operator. Approximately
70% of the employees who currently work at the Coso projects' sites
have been employed there since 1992; and
. As a result of the change in operators and the restructuring of
operator fees, the aggregate annual fees to be paid by the Coso
partnerships to FPL Operating and Coso Operating Company under their
respective O&M agreements have been reduced from approximately $7.5
million, which had been paid to the prior operator in 1998, to
approximately $2.0 million. Payment of these reduced operator fees are
subordinated to all payments to be made under the senior secured
notes;
. One of our affiliates, which purchased the managing partners of the Coso
partnerships, has caused any management committee fees payable by each
Coso partnership to its partners to be subordinated to all payments to be
made under the senior secured notes;
. The Coso partnerships expect to reduce annual non-fee related costs at
the Coso projects, including insurance, maintenance and other costs, by
approximately $1.9 million. However, the pro forma financial data
included in this prospectus does not give effect to this cost savings;
and
. The Coso partnerships are expanding a steam sharing program they
previously implemented among the Coso projects to enhance the management,
and to optimize the overall use, of the Coso geothermal resource. As part
of this program, the Coso partnerships plan to conserve the geothermal
resource whenever possible by, among other things:
. Transferring steam between and among the Coso projects and from an
adjoining site, which we call BLM North, rather than drilling new
wells at the Coso projects' sites prematurely; and
. Expanding the flexible field-wide water reinjection program.
Recent Developments
Purchase of FPL Interests; Assignment of FPL O&M Agreements
On October 6, 1999, one of our affiliates, Caithness Acquisition Company,
LLC, which we call Caithness Acquisition, and ESI Geothermal, Inc., an
affiliate of FPL Operating and which we call ESI Geothermal, signed a sale
agreement, which we call the Sale Agreement. Caithness Acquisition is a wholly
owned subsidiary of Caithness Energy. See "--The Sponsor." Under the Sale
Agreement, Caithness Acquisition agreed to purchase all of the indirect
ownership interests held by ESI Geothermal in the Navy I partnership in
exchange for a cash payment of $5.0 million. ESI Geothermal beneficially owns a
5.0% indirect ownership interest in the Navy I partnership. ESI Geothermal also
agreed in the Sale Agreement that, from and after the date of the Sale
Agreement, it
4
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will no longer exercise, with certain limited exceptions, its management rights
with respect to the Navy I partnership. The Sale Agreement also provides for
general mutual releases by Caithness Acquisition, ESI Geothermal and their
respective affiliates. The closing of the purchase by Caithness Acquisition of
ESI Geothermal ownership interests in the Navy I partnership is currently
required by the Sale Agreement to occur on or prior to November 1, 1999.
Following the closing, ESI Geothermal will no longer have any ownership or
other interest in, and Caithness Acquisition will indirectly control, the Navy
I partnership.
As a condition to the closing of the purchase by Caithness Acquisition of ESI
Geothermal's ownership interests in the Navy I partnership, FPL Operating will
assign to Coso Operating Company, the other operator of the Coso projects, all
of its rights under its three separate O&M agreements with the Coso
partnerships, and Coso Operating Company will assume all of FPL Operating's
duties and obligations under these O&M agreements. No other changes to FPL
Operating's O&M agreements are expected to be made. In addition, Coso Operating
Company will be offering employment to substantially all FPL Operating's
employees who have been working at the Coso projects. At the closing, Coso
Operating Company is expected to advance to FPL Operating all of the O&M fees
and reimbursable expenses that have accrued and have not been paid to FPL
Operating under the O&M agreements and, following the closing, Coso Operating
Company, as the successor operator, will be entitled to receive the O&M fees
and reimbursable expenses due under FPL Operating's assigned O&M agreements.
These assignments and assumptions are subject to the prior notification of
certain parties and our receipt of certain third party consents under the
Indenture and the Financing Documents described below. We are currently
notifying the appropriate parties of this pending transaction and expect to
obtain the requisite third party consents to close during the month of October
1999.
If the purchase of ESI Geothermal's ownership interests is completed, Coso
Operating Company will become the sole operator of all of the plants and fields
located at the Coso projects. No one can assure you that we will be able to
obtain the third party consents necessary to complete Caithness Acquisition's
purchase of ESI Geothermal's ownership interests in the Navy I partnership or
that, even if we obtain all of these third party consents, the closing of that
purchase will occur.
Return to Service of Navy I Unit
In January 1999, one of Navy I's three turbine generator units, known as Unit
1, automatically shut down when the stator coils attached to it experienced a
ground fault. The stator coil was repaired, and Unit 1 was scheduled to return
to service in March 1999. However, electrical faults recurred during the start-
up testing stage of Unit 1's generators, and the Navy I partnership postponed
Unit 1's return to service while it repaired the unit. Unit 1 returned to
service prior to June 1, 1999, and is currently in service. The Navy I
partnership had filed a claim in connection with Unit 1's shutdown under its
business interruption and casualty insurance policies. It expects that any
losses resulting from this shutdown will be covered by insurance, subject to a
deductible of $500,000 for property damage and a 25-day deductible for business
interruption. We have included amounts expected to be recovered under these
insurance policies in the Navy I partnership's total revenues for the six
months ended June 30, 1999. See "--Summary Selected Historical and Pro Forma
Financial and Operating Data" and "Business--Overview of the Coso Projects--
Plants--Navy I." The other two turbine generator units at Navy I and the three
generator units at BLM and Navy II are also currently in service.
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The Purchase
In late 1998, CalEnergy Company, Inc., which is now known as MidAmerican
Energy Holdings Company and which we call CalEnergy, announced that it was
planning to merge with MidAmerican Energy. As a consequence of the planned
merger, the Federal Energy Regulatory Commission, which we call FERC, required
CalEnergy to divest itself of at least a portion of its approximately 48%
equity interest in the Coso projects if the Coso projects were to continue to
qualify as "Qualifying Facilities," or QFs, under the Public Utility Regulatory
Policies Act of 1978, which we call PURPA. See "--The Independent Power
Industry." Each Coso partnership is required to operate and maintain its Coso
project as a QF under its power purchase agreement and under the Indenture.
On February 25, 1999, Caithness Acquisition purchased all of CalEnergy's
interests in the Coso projects. The purchase price consisted of $205.0 million
in cash, plus $5.0 million in contingent payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. In order to complete the
purchase, Caithness Acquisition arranged for short-term debt financing in the
principal amount of approximately $211.5 million. Caithness Acquisition used a
portion of the net proceeds from the Series A notes offering that it received
from the Coso partnerships, together with funds from other sources, to repay
all amounts owed under this short-term debt facility.
The Sponsor
Caithness Energy, the principal operating subsidiary of Caithness
Corporation, is a developer and owner of independent power projects and is the
sponsor of the Coso projects. Since 1966, the current owners of Caithness
Corporation have been involved in the development of long-term investment
opportunities involving natural resources. Caithness Corporation is one of the
two original sponsors of the Coso projects and formed Caithness Energy in 1995
to consolidate its ownership of independent power projects.
Caithness Energy believes that it is currently the second largest owner of
geothermal power projects in the United States, based on the total electrical
generating capacity of its power projects. Through its controlled affiliates,
Caithness Energy owns interests in seven geothermal plants, including the Coso
projects, totaling 420 MW. Caithness Energy is also seeking to develop two
additional geothermal power projects with a total potential electrical
generating capacity of over 400 MW, and has interests in other operating power
generating facilities, including solar, wind and natural gas, totaling an
additional 400 MW.
Caithness Energy has historically partnered with strategic investors in its
power project investments. The largest such investors in the Coso projects
currently are:
. ESI Geothermal, which is a subsidiary of FPL Energy, Inc., the
independent power subsidiary of FPL Group, Inc., and which in turn is the
parent company of Florida Power & Light Company, one of the largest
investor-owned utilities in the United States; and
. Dominion Energy, Inc., a subsidiary of Dominion Resources, Inc., which
also is a large investor-owned utility.
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Caithness Acquisition recently entered into a Sale Agreement with ESI
Geothermal to purchase all of ESI Geothermal's indirect ownership interests in
the Navy I partnership. You should read "--Recent Developments--Purchase of FPL
Interests; Assignment of FPL O&M Agreements" for more information regarding the
pending purchase of ESI Geothermal's ownership interests in the Navy I
partnership and certain related transactions.
Caithness Energy is headquartered in New York City and has additional offices
in California, Colorado and Florida.
The Coso Partnerships
Affiliates of Caithness Energy and CalEnergy formed the Coso partnerships
during the 1980s to develop, own and operate Navy I, BLM and Navy II. As we
described in "--The Purchase" above, Caithness Acquisition recently purchased
all of CalEnergy's interests in the Coso projects. Caithness Energy now
indirectly controls the BLM partnership and the Navy II partnership. In
addition, while Caithness Energy and FPL Energy, Inc. currently indirectly
share control of the Navy I partnership, Caithness Acquisition, Caithness
Energy's wholly owned subsidiary, recently entered into a Sale Agreement with
ESI Geothermal, FPL Energy, Inc.'s subsidiary, to purchase all of ESI
Geothermal's indirect ownership interests in the Navy I partnership. Following
the closing of that purchase, Caithness Energy will indirectly control the Navy
I partnership. You should read "--Recent Developments--Purchase of FPL
Interests; Assignment of FPL O&M Agreements" for more information regarding the
pending purchase of ESI Geothermal's ownership interests in the Navy I
partnership and "Management" for more details regarding who manages and
controls the Coso partnerships.
Geothermal Energy
Geothermal energy is:
. an established and generally sustainable source of energy that
releases significantly lower levels of emissions than result when
energy is generated by burning fossil fuels;
. derived from the natural heat of the earth when water comes
sufficiently close to hot molten rock to heat the water to
temperatures of 400 degrees Fahrenheit or more. The heated water then
ascends toward the surface of the earth where, if geological
conditions are suitable, it can be extracted for commercial use by
drilling geothermal wells; and
. a renewable source of energy so long as natural ground water flows and
reinjection of extracted geothermal fluids are adequate over the long
term to replenish the geothermal reservoir after geothermal fluids
have been withdrawn.
Compared to fossil fuel-fired power plants, geothermal energy facilities
typically have higher capital costs, primarily as a result of wellfield
development, but tend to have significantly lower variable operating costs.
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The Independent Power Industry
The Coso projects are part of the growing domestic independent power
industry. Utilities in the United States have been the predominant producers of
electric power since the early 1900s. In 1978, however, Congress enacted PURPA,
which removed regulatory constraints relating to the production and sale of
electricity by certain non-utility power producers. PURPA requires electric
utilities to buy electricity from non-utility power producers that use
renewable energy sources, known as Small Power QFs, or that produce both
electrical energy and useful thermal energy used for industrial, commercial,
heating or cooling purposes, known as Cogeneration QFs. This encouraged
companies other than electric utilities to enter the electric power production
market. Under PURPA, electric utilities are required to comply with state law
guidelines and, in general, must interconnect with and buy capacity and energy
offered by non-utility power producers meeting certain ownership and, in the
case of Small Power QFs, fuel use standards established by FERC if there is a
need for such electricity and if it is priced at or below the utility's avoided
cost of energy at the time of the agreements.
The Coso projects qualify as Small Power QFs under PURPA and the rules and
regulations promulgated under PURPA by FERC. PURPA exempts the Coso projects
from certain federal and state regulations. The Coso projects must continue to
satisfy certain ownership and fuel-use standards to maintain their QF status.
Since their inception, the Coso projects have satisfied these standards and we
expect that they will continue to do so.
8
<PAGE>
SUMMARY OF THE EXCHANGE OFFER
On May 28, 1999, we completed the Series A notes offering. The initial
purchaser subsequently resold the Series A notes in reliance on Rule 144A and
other available exemptions under the Securities Act of 1933, which we call the
Securities Act. As part of the completion of the Series A notes offering, we,
the Coso partnerships and the initial purchaser entered into a registration
rights agreement dated May 28, 1999, which we call the registration rights
agreement, in which we agreed, among other things, to deliver this prospectus
to you and complete an exchange offer for the Series A notes. Set forth below
is a summary of the terms of the exchange offer. See "The Exchange Offer."
The Exchange Offer.......... We are offering to exchange (1) up to $110.0
million aggregate principal amount of our 6.80%
Series B Senior Secured Notes due 2001, which
have been registered under the Securities Act,
for up to $110.0 million aggregate principal
amount of any and all outstanding 6.80% Series A
Senior Secured Notes due 2001 and (2) up to
$303.0 million aggregate principal amount of our
9.05% Series B Senior Secured Notes due 2009,
which have been registered under the Securities
Act, for up to $303.0 million aggregate principal
amount of any and all outstanding 9.05% Series A
Senior Secured Notes due 2009. Only Series B
notes due 2001 may be exchanged for tendered
Series A notes due 2001, and only Series B notes
due 2009 may be exchanged for tendered Series A
notes due 2009. We will exchange Series A notes
only in integral multiples of $1,000. See "The
Exchange Offer--Terms of the Exchange Offer."
In order to be exchanged, the Series A notes must
be properly tendered and accepted. Subject to
certain exceptions, we will accept for exchange
any and all Series A notes that are properly
tendered and not withdrawn before the exchange
offer expires. As of the date of this prospectus,
there is $413.0 million aggregate principal
amount of Series A notes outstanding. We will
issue the Series B notes promptly after the
exchange offer expires.
Expiration Date; Withdrawal
Rights..................... The exchange offer will expire at 5:00 p.m., New
York City time, on Monday, November 8, 1999,
unless we extend the expiration date. You may
withdraw your tender of Series A notes at any
time before the exchange offer expires. If we
terminate this exchange offer and do not accept
for exchange any Series A notes, we will promptly
return tendered Series A notes to their holders.
See "The Exchange Offer--Expiration Date;
Extensions; Termination."
9
<PAGE>
Conditions to the Exchange
Offer...................... The exchange offer is subject to customary
conditions, any or all of which we may waive in
our sole discretion. See "The Exchange Offer--
Conditions to the Exchange Offer."
Accrued Interest on the The Series B notes will bear interest from and
Notes...................... including the date of issuance of the Series A
notes. Accordingly, if you receive Series B notes
in exchange for your tendered Series A notes, you
will forego accrued but unpaid interest on your
exchanged Series A notes for the period from and
including the date of issuance of the Series A
notes to the date of the exchange. Instead, you
will be entitled to such interest under the
Series B notes. See "The Exchange Offer--Terms of
the Exchange Offer."
Procedures for Tendering
Series A Notes............. If you wish to tender your Series A notes for
exchange, one of the following must occur:
. the exchange agent must receive certificates
for the Series A notes along with the letter of
transmittal;
. the exchange agent must receive prior to the
expiration date a timely confirmation of a
book-entry transfer of Series A notes, if that
procedure is available, into the exchange
agent's account at DTC pursuant to the
procedure for book-entry transfer described
below; or
. you must comply with the guaranteed delivery
procedures described below.
See "The Exchange Offer--Procedures for
Tendering."
Material Federal Income Tax
Considerations............. We believe that your exchange of Series A notes
for Series B notes pursuant to the exchange offer
will not result in a taxable event for federal
income tax purposes. See "The Exchange Offer--
Material Federal Income Tax Consequences of the
Exchange Offer."
10
<PAGE>
Rights of Dissenting
Holders..................... Holders of Series A notes do not have any
appraisal or dissenters' rights under Delaware
General Corporation Law in connection with this
exchange offer. See "The Exchange Offer--Terms of
the Exchange Offer."
Exchange Agent.............. U.S. Bank Trust National Association is serving
as the exchange agent for the exchange offer. See
"The Exchange Offer--Exchange Agent."
Use of Proceeds; Expenses... We will not receive any proceeds from the
issuance of Series B notes pursuant to the
exchange offer. We will pay all expenses incident
to the completion of the exchange offer. See "The
Exchange Offer--Payment of Expenses."
Consequences of exchanging Series A notes pursuant to this Exchange Offer
Based on specific interpretive letters issued by the staff of the Securities
and Exchange Commission (SEC) in unrelated transactions, if you exchange your
Series A notes for Series B notes pursuant to this exchange offer, we believe
that you generally may offer for resale, resell or otherwise transfer your
Series B notes without complying with the registration and prospectus delivery
requirements of the Securities Act, provided that (1) you acquired the Series B
notes in the ordinary course of your business, (2) you are not participating,
do not intend to participate and have no arrangement or understanding with any
person to participate, in a distribution of your Series B notes and (3) you are
not our "affiliate" within the meaning of Rule 405 under the Securities Act. If
you are not acquiring the Series B notes in the ordinary course of business,
are engaged in or intend to engage in or have any arrangement or understanding
with any person to participate in the distribution of the Series B notes or are
our affiliate, then (1) you cannot rely on these interpretive letters and (2)
you must comply with the registration requirements of the Securities Act in
connection with any resale transaction. Each broker-dealer that receives Series
B notes for its own account in exchange for Series A notes that were acquired
as a result of market-making or other trading activities must acknowledge that
it will deliver a prospectus in connection with any resale of the Series B
notes. See "Plan of Distribution." In addition, to comply with the securities
laws of specific jurisdictions, if applicable, the Series B notes may not be
offered or sold unless they have been registered or qualified for sale in such
jurisdiction or an exemption from registration or qualification is available
and the conditions thereto have been met.
If you do not exchange your Series A notes for Series B notes according to
this exchange offer, your Series A notes will continue to be subject to the
restrictions on transfer contained in the legend set forth on your Series A
notes. In general, the Series A notes may not be offered or sold, unless
registered under the Securities Act, except pursuant to an exemption from, or
in a transaction not subject to, the Securities Act and applicable state
securities laws. See "The Exchange Offer--Purpose of the Exchange Offer" and
"--Resales of Notes."
11
<PAGE>
Summary of the Terms of the Series B Notes
The form and terms of the Series B notes will be identical in all material
respects to the form and terms of the Series A notes, except that (1) the
Series B notes will have been registered under the Securities Act and,
therefore, will not bear legends restricting the transfer thereof and (2)
holders of the Series B notes will not be and, upon the completion of the
exchange offer, certain holders of Series A notes will no longer be, entitled
to certain rights under the registration rights agreement intended for holders
of transfer restricted notes, except in limited circumstances. The Series B
notes will evidence the same debt as the Series A notes and will be governed by
the Indenture.
Issuer...................... Caithness Coso Funding Corp., a Delaware
corporation.
Guarantors.................. The Navy I partnership, the BLM partnership and
the Navy II partnership. Each Coso partnership is
a California general partnership.
Securities Offered.......... The Series B notes, consisting of the following:
$110.0 million aggregate principal amount of
Series B Senior Secured Notes due 2001; and
$303.0 million aggregate principal amount of
Series B Senior Secured Notes due 2009.
Maturity Dates.............. The Series B notes due 2001 will mature on
December 15, 2001, and the Series B notes due
2009 will mature on December 15, 2009. For more
details, see "Description of Series B Notes--
Principal, Maturity and Interest."
Average Life................ The average life of the Series B notes due 2001
is 1.2 years, and the average life of the Series
B notes due 2009 is 7.2 years.
Interest.................... The Series B notes due 2001 will accrue interest
at the rate of 6.80% per annum. We will pay
interest on these notes semi-annually in arrears
on December 15 and June 15, commencing December
15, 1999, to holders of record on the immediately
preceding December 1 and June 1.
The Series B notes due 2009 will accrue interest
at the rate of 9.05% per annum. We will pay
interest on these notes semi-annually in arrears
on December 15 and June 15, commencing December
15, 1999, to holders of record on the immediately
preceding December 1 and June 1. For more
details, see "Description of Series B Notes--
Principal, Maturity and Interest."
12
<PAGE>
Scheduled Principal
Payments................... We will pay the principal of the Series B notes
due 2001 in semi-annual installments, commencing
December 15, 1999, as follows:
<TABLE>
<CAPTION>
Scheduled Percentage of Principal
Payment Date Amount Payable
<S> <C>
December 15,
1999........... 47.8773%
June 15, 2000... 11.0736%
December 15,
2000........... 16.4427%
June 15, 2001... 10.1900%
December 15,
2001........... 14.4164%
</TABLE>
We will pay the principal of the Series B notes
due 2009 in semi-annual installments, commencing
June 15, 2002, as follows:
<TABLE>
<CAPTION>
Scheduled Percentage of Principal
Payment Date Amount Payable
<S> <C>
June 15, 2002... 2.8743%
December 15,
2002........... 4.3109%
June 15, 2003... 3.6564%
December 15,
2003........... 5.4584%
June 15, 2004... 4.1363%
December 15,
2004........... 6.2043%
June 15, 2005... 4.6838%
December 15,
2005........... 7.0257%
June 15, 2006... 5.0541%
December 15,
2006........... 7.5815%
June 15, 2007... 6.2601%
December 15,
2007........... 9.3898%
June 15, 2008... 6.4927%
December 15,
2008........... 9.7650%
June 15, 2009... 6.8231%
December 15,
2009........... 10.2835%
</TABLE>
Ratings of Senior Secured
Notes...................... The senior secured notes due 2001 have been rated
"Ba1" by Moody's, "BB" by S&P and "BB+" by Duff &
Phelps, and the Series B notes due 2009 have been
rated "Ba2" by Moody's, "BB" by S&P and "BB" by
Duff & Phelps. See "Description of Series B
Notes--Ratings."
Senior Secured Notes
Guarantees................. The Coso partnerships have fully and
unconditionally guaranteed on a joint and several
basis all of our obligations under the Indenture
and the senior secured notes, subject to
fraudulent conveyance limitations. If we cannot
make payments on the senior secured notes when
due, the Coso partnerships must make them
instead.
The Coso partnerships' guarantees are secured by:
. a perfected, first priority lien on
substantially all of the assets of the
Coso partnerships; and
13
<PAGE>
. a perfected, first priority pledge of all
ownership interests in the Coso
partnerships.
For more details, see "Description of Series B
Notes--Brief Description of Series B Notes and
Guarantees."
Senior Secured Notes
Collateral................. The senior secured notes are secured by:
. a perfected, first priority pledge of the
promissory notes, which we call the
project notes, evidencing the Coso
partnerships' obligations to repay the
loans made by us to the Coso partnerships;
. a perfected, first priority lien on the
funds deposited in the accounts which we
established under the Depositary
Agreement; and
. a perfected, first priority pledge of all
of our outstanding capital stock.
In addition, our affiliates (other than the Coso
partnerships) that hold any material assets
related to the Coso projects have provided a lien
on these assets to secure the Series B notes. For
more details, see "Description of Series B
Notes-- Security."
Ranking.....................
The senior secured notes will rank senior in
right of payment to all of our subordinated
indebtedness issued in the future, if any. The
senior secured notes will rank equally in right
of payment with our future senior borrowings, if
any. See "Description of Series B Notes--Brief
Description of the Series B Notes and
Guarantees."
Debt Service Reserve
Account.................... We established a Debt Service Reserve Account for
the benefit of the holders of the senior secured
notes under the Depositary Agreement. We
initially funded the Debt Service Reserve Account
at the closing of the Series A notes offering by
depositing into that account $50.0 million from
the proceeds of the Series A notes offering. The
Depositary Agreement requires us to deposit cash
in and/or post a letter of credit for the Debt
Service Reserve Account in an amount equal to the
aggregate amount of principal and interest due on
the senior secured notes on the next succeeding
semi-annual scheduled payment date. For more
details, see "Description of Series B Notes--Debt
Service Reserve Account."
14
<PAGE>
Capital Expenditure Reserve
Account.................... We established a Capital Expenditure Reserve
Account for the benefit of the holders of senior
secured notes under the Depositary Agreement. The
Capital Expenditure Reserve Account will be
funded from the Coso partnerships' revenues in
accordance with the terms of the Depositary
Agreement and in accordance with the operating
budgets for the Coso projects as approved by
Sandwell Engineering Inc., our independent
engineer. Amounts on deposit in the Capital
Expenditure Reserve Account will be used for
capital expenditures to be made in accordance
with prudent industry practice and as may be
required pursuant to the terms of the Indenture
and each of the three Credit Agreements between
the Coso partnerships and us, respectively. For
more details, see "Description of Series B
Notes--Capital Expenditure Reserve Account."
Optional Redemption......... We may not redeem the Series B notes due 2001.
We may redeem the Series B notes due 2009 at our
option at any time and from time to time, in
whole or in part, upon not less than 30 nor more
than 60 days notice to each holder of these
notes. If we choose to redeem the Series B notes
due 2009, the redemption price will be at par,
plus accrued interest through the date of
redemption, plus a premium calculated to "make
whole" the holder of these notes to comparable
U.S. Treasury securities plus 50 basis points.
For more details, see "Description of Series B
Notes--Optional Redemption."
Mandatory Redemption........ We will be required to redeem the Series B notes
under certain circumstances, in whole or in part,
ratably among each series at a redemption price
equal to the principal amount of the Series B
notes being redeemed plus accrued and unpaid
interest to the redemption date. For more
details, see "Description of Series B Notes--
Mandatory Redemption."
Change of Control........... If a change of control occurs, each holder of
Series B notes would be able to require us to
repurchase its Series B notes, in whole or in
part, at a price equal to 101% of the principal
amount of those notes, plus any accrued and
unpaid interest thereon. See "Description of
Series B Notes--Repurchase at the Option of
Holders upon Change of Control."
15
<PAGE>
Principal Covenants......... The Indenture contains certain restrictive
covenants that, among other things, limit our
ability to:
. incur additional indebtedness;
. release funds from reserve accounts
established under the Depositary
Agreement;
. become liable in connection with
guarantees;
. create liens;
. pay dividends or make distributions;
. take certain actions with respect to the
Credit Agreements; and
. enter into any transaction of merger or
consolidation or change our form of
organization or our business.
For a more detailed description of these
covenants, see "Description of Series B Notes--
Certain Covenants."
Principal Credit Agreement
Covenants.................. The Credit Agreement with each Coso partnership
contains certain restrictive covenants that,
among other things, limit that Coso partnership's
ability to:
. incur additional indebtedness;
. release funds from reserve accounts
established under the Depositary
Agreement;
. create liens;
. sell assets;
. sell partnership interests in the Coso
partnerships;
. pay dividends or make distributions;
. enter into certain transactions with
affiliates;
. take certain actions with respect to the
material agreements to which they are a
party;
. become liable in connection with
guarantees (other than their guarantees of
the Series B notes); and
. enter into any transaction of merger or
consolidation or change their form of
organization or business.
For a more detailed description of these
covenants, see "Description of Credit
Agreements--Certain Covenants" under the heading
"Description of Series B Notes."
16
<PAGE>
Certain Accounts............ In accordance with the Depositary Agreement, we
and the Coso partnerships have established
certain accounts, including:
. the Revenue Account;
. the Principal Account;
. the Interest Account;
. the Debt Service Reserve Account;
. the Capital Expenditure Reserve Account;
. the Operating and Maintenance Fees
Account;
. the Management Fees Account;
. the Distribution Account;
. the Distribution Suspense Account;
. the Loss Proceeds Account; and
. the Redemption Account.
The Coso partnerships have limited rights to
withdraw funds from these accounts in accordance
with the terms and conditions set forth in the
Depositary Agreement. For more information
regarding these accounts, see "Description of
Series B Notes--Flow of Funds."
Absence of Public Market
for Notes.................. There has been no public market for the Series A
notes and no active public market for the Series
B notes is currently anticipated. We currently do
not intend to apply for the listing of the Series
B notes on any securities exchange or to seek
approval for quotation through any automated
quotation system. Donaldson, Lufkin & Jenrette
Securities Corporation, the initial purchaser of
the Series A notes, has advised us that it
currently intends to make a market in the Series
B notes; however, it is not obligated to do so
and it may discontinue any market making at any
time without notice. Accordingly, we cannot
assure you as to the liquidity or the trading
market for the Series B notes.
Risk Factors
The "Risk Factors" section contains a discussion of certain factors that you
should consider in evaluating an investment in the Series B notes.
17
<PAGE>
The Independent Engineer's Report
Exhibit A of this prospectus contains a report prepared by Sandwell
Engineering Inc. dated May 20, 1999. We sometimes call Sandwell Engineering
Inc. our independent engineer. Sandwell Engineering Inc. prepared this report,
which we call the independent engineer's report, in connection with the Series
A notes offering. You should be aware that the independent engineer's report
has not been updated since then. We included the independent engineer's report
to help you understand and evaluate the Coso projects. Sandwell Engineering
Inc. performed an independent engineer's review of the Coso projects. The
independent engineer's report assesses, as of its date, technical,
environmental and economic aspects of the Coso projects, including certain
financial and operational estimates and projections of the Coso projects'
revenue generation capacity and associated costs. These estimates and
projections were prepared by us and are our responsibility. They have not been
examined, compiled or subjected to any procedures by either KPMG LLP, our
independent accountants, or PricewaterhouseCoopers LLP, the former independent
accountants of the Coso projects. Accordingly, neither KPMG LLP nor
PricewaterhouseCoopers LLP expresses any opinion or other form of assurance
with respect to these estimates and projections. The PricewaterhouseCoopers LLP
reports included in this prospectus relate to the Coso partnerships' historical
financial information. The KPMG LLP report included in this prospectus relates
to our historical balance sheet as of April 22, 1999 (our date of inception).
These reports do not extend to the estimates and projections included in the
independent engineer's report and should not be read to do so.
For purposes of preparing the estimates and projections, we relied upon
assumptions about material contingencies and other matters that are not within
our control nor the control of any other person. You should be aware that
actual results will differ, perhaps materially, from those estimated or
projected. No one can assure you that the assumptions used are correct or that
the estimates and projections will match actual results of operations.
Therefore, we do not make, nor intend to make, nor should you infer, any
representation with respect to the likelihood of any future outcome. If actual
results are materially less favorable than those shown or if the assumptions
used in formulating the estimates and projections prove to be incorrect, the
Coso partnerships' ability to make payments to us under their project notes,
our ability to make payments of principal, premium, if any, and interest on the
Series B notes when due, and the Coso partnerships' ability to meet their
obligations under their guarantees could be materially and adversely affected.
You should read "Risk Factors--Uncertainties of Estimates, Projections and
Assumptions" for additional information about the assumptions, estimates and
projections in the independent engineer's report.
We retained Sandwell Engineering Inc. based upon its expertise in industrial
and power plant engineering. It has provided services to the Coso partnerships
for approximately ten years and continues to provide services to the Coso
projects. Sandwell Engineering Inc. has no affiliation with Caithness Energy,
the Coso partnerships or us. We did not impose any limitations on the scope of
the independent engineer's investigation, nor did Caithness Energy or the Coso
partnerships.
On the basis of Sandwell Engineering Inc.'s review of the Coso projects'
facilities, including the plants, wellfields and gathering system, the
information provided to it on our behalf and the assumptions set forth in the
independent engineer's report, Sandwell Engineering Inc. was of the opinion
that:
. The current operations and maintenance practices employed by FPL
Operating as operator of the Coso projects' facilities are reasonable for
operation and maintenance of facilities of this
18
<PAGE>
type, to maintain compliance with all relevant environmental and other
permits and approvals that are required, and to produce the predicted
revenues and cash flow of the facilities.
. FPL Operating, as operator, has the geothermal plant operating experience
and resources necessary to operate the facilities so as to produce the
predicted revenues and cash flow for the Coso projects' facilities.
. The 1999 operating and maintenance financial projections and capital
expenditures forecasts proposed by us or on our behalf for the Coso
projects' facilities are consistent with the operating and maintenance
needs of the facilities, are prudent, and are reasonably designed to
produce the predicted revenues and cash flow of the facilities.
. If the Coso projects' facilities are maintained and operated in
accordance with current practices, and if the quality and quantity of the
geothermal resources for these facilities are as projected by us or on
our behalf, then the eleven-year financial projections of operating and
maintenance expenditures, and of capital expenditures, for these
facilities are consistent with the operating and maintenance needs of
these facilities. Based on these operating assumptions, the projected
revenues and cash flows of these facilities, as shown in the financial
projections, are reasonable.
. All major permits and approvals required from federal, state and local
agencies for current operation of the Coso projects' facilities have been
obtained, and all required environmental reporting is being carried out.
. The management organization for operating the Coso projects is
acceptable. The attention given to safety matters, and the safety
programs being implemented are reasonable and acceptable. The training
and certification program for plant operators and maintenance staff is
acceptable.
. Assuming annual rates of interest of 6.80% for the senior secured notes
due 2001 and of 9.05% for the senior secured notes due 2009, the debt
service coverage ratios, or DSCR, would be:
For the period 1999 through 2001:
<TABLE>
<S> <C> <C>
Navy I partnership: Minimum DSCR 1.32
Average DSCR 1.32
BLM partnership: Minimum DSCR 1.28
Average DSCR 1.32
Navy II partnership: Minimum DSCR 1.32
Average DSCR 1.34
For the period 2002 through 2009:
Navy I partnership: Minimum DSCR 1.50
Average DSCR 1.58
BLM partnership: Minimum DSCR 1.49
Average DSCR 1.58
Navy II partnership: Minimum DSCR 1.53
Average DSCR 1.59
</TABLE>
You should read "Exhibit A--The Independent Engineer's Report" for a more
complete discussion of the methodology used by Sandwell Engineering Inc. and
the assumptions underlying the foregoing opinions as of the date of the report.
19
<PAGE>
At the closing of Caithness Acquisition's purchase of ESI Geothermal's
ownership interests in the Navy I partnership, Coso Operating Company will
assume all of FPL Operating's duties and obligations under FPL Operating's O&M
agreements with the Coso partnerships. Thereafter, Coso Operating Company will
become the sole operator of all of the plants and fields located at the Coso
projects. While Coso Operating Company intends to retain substantially all of
FPL Operating's employees who have been working for FPL Operating at the Coso
projects, it does not have the same level of experience and resources that FPL
Operating has in operating geothermal plants and may or may not employ the same
operations and maintenance practices currently employed by FPL Operating at the
Coso projects. See "Risk Factors--The Coso projects are being managed by new
managing partners and operators" and "Our estimates, projections and
assumptions could prove to be incorrect."
The Energy Markets Consultant's Report
Exhibit B of this prospectus contains a report prepared by Henwood Energy
Services, Inc. dated May 20, 1999. We sometimes call Henwood Energy Services,
Inc. our energy markets consultant. Henwood Energy Services, Inc. prepared this
report, which we call the energy market consultant's report, in connection with
the Series A notes offering. You should be aware that the energy market
consultant's report has not been updated since then. We included the energy
markets consultant's report to help you understand and evaluate the Coso
projects. The energy markets consultant prepared its report to, among other
things, provide:
. an independent forecast of energy prices in the Southern California
market for the period 1999 through 2009,
. an assessment of the competitive position of the Coso projects in the
Southern California market, and
. confirmation of the reasonableness of our AB1890 payment forecasts in our
projections.
The projections used by the energy markets consultant were prepared by us and
are our responsibility. They have not been examined, compiled or subjected to
any procedures by either KPMG LLP or PricewaterhouseCoopers LLP. Accordingly,
neither KPMG LLP nor PricewaterhouseCoopers LLP expresses any opinion or other
form of assurance with respect to these projections. The PricewaterhouseCoopers
LLP reports included in this prospectus relate to the Coso partnerships'
historical financial information. The KPMG LLP report included in this
prospectus relates to our historical balance sheet as of April 22, 1999 (our
date of inception). These reports do not extend to the projections included in
the energy markets consultant's report and should not be read to do so.
The assumptions contained in the projections and evaluated by the energy
markets consultant concern a number of matters that are not within our control
nor the control of any other person. You should be aware that actual results
will differ, perhaps materially, from those projected. No one can assure you
that the assumptions used are correct or that the projections will match actual
results of operations. Therefore, we do not make, nor intend to make, nor
should you infer, any representation with respect to the likelihood of any
future outcome. If actual results are materially less favorable than those
shown or if the assumptions evaluated in the energy markets consultant's report
and utilized in preparing the projections prove to be incorrect, the Coso
partnerships' ability to make payments to us under their project notes, our
ability to make payments of principal, premium, if any, and interest on the
Series B notes when due, and the Coso partnerships' ability to meet their
20
<PAGE>
obligations under their guarantees could be materially and adversely affected.
You should read "Risk Factors--Uncertainties of Estimates, Projections and
Assumptions" for more information.
We retained Henwood Energy Services, Inc. based upon its expertise in power
market price forecasting. It has no affiliation with Caithness Energy, the Coso
partnerships or us. We did not impose any limitations on the scope of the
energy markets consultant's investigation, nor did Caithness Energy or the Coso
partnerships.
Based on its analyses in the energy markets consultant's report, Henwood
Energy Services, Inc. expressed the following major conclusions in its report:
. Henwood Energy Services, Inc.'s market clearing prices forecast indicates
that the Southern California annual average power price will increase
from $26.9 per MW hour (MWh) in 2000 to $44.3/MWh by 2009--which
translates into an average annual rate of increase of approximately 5.7%
over that period (inflation is included in all prices and is equal to
3.0% per year).
. However, there are three distinct periods of price movement. Between 2000
and 2002 in California, which Henwood Energy Services, Inc. calls the
Transition Period, prices increase at an annual average rate of 12.6%.
During the Transition Period, prices bid into the California Power
Exchange reflect short-run marginal fuel costs because most utility-owned
generators receive payments for capacity from "must-run" contracts, if in
California, or through traditional tariffs, if outside of California.
. After the Transition Period ends in March 2002, the California Power
Exchange should cease to behave as a marginal cost pool. This change is
reflected in the forecast. The average market-clearing prices increase
from $34.1/MWh in 2002 to $40.4/MWh by 2005--an average rate of increase
of about 5.7% per year. Price increases in this period reflect attempts
by generators in California to recover at least a portion of fixed
capacity costs through market sales.
. Beyond 2005, prices are forecast to increase gradually but steadily,
about 2.3% per year, which is less than the inflation rate. The growth
rate during the 2005 to 2009 period is influenced largely by the
introduction into the generation market of high efficiency gas-fired
combined cycle plants. These plants are frequently on the margin. That
is, they establish the market-clearing price, and thus are in a position
to push power prices down gradually over time as they replace less
efficient thermal generation plants.
. Based on Henwood Energy Services, Inc.'s long-run natural gas price
forecast and a 3.0% annual inflation rate, the energy markets consultant
estimates Edison's short-run avoided cost of energy prices to be
$31.3/MWh for the remaining months of 1999 (May through December),
$32.4/MWh in 2000 and $33.4/MWh in 2001. These prices are higher than
Henwood Energy Services, Inc.'s forecast of power prices on the
California Power Exchange during the same period.
. The energy markets consultant expects the Coso projects to be a low-cost
producer in all of the years of the study. According to data provided by
us or on our behalf, the annual average operating cost in 2005 is
$10.83/MWh. About 70.0% of the electricity produced in the Western
Systems Coordinating Council in 2005--the first year of full
competition--is generated from units with higher costs. Of all the
generation in the region, only hydro and
21
<PAGE>
wind generators have lower operating costs (hydro and wind power account
for about 24.0% and 1.0%, respectively, of all electric generation in
California).
. The Coso projects' annual average operating costs are about 69.0% below
annual Southern California power prices, averaged over all years of the
forecast. In fact, the Coso partnerships' operating costs are
significantly below even the off-peak market-clearing prices in all
forecasted years.
. The low-cost relationship between Henwood Energy Services, Inc.'s market
clearing prices forecast and our operating costs continues in the Low Gas
Price sensitivity cases set forth in the energy markets consultant's
report. Under the worst-case scenario set forth in the energy markets
consultant's report, Low Gas Price Case 2, the Coso partnerships'
operating costs are, on average, about 58.0% below off-peak prices.
. The energy markets consultant estimates that the Southern California
market clearing prices will be greater than or equal to $19.7/MWh in
about 96.0% of all hours in 2005. This means that the Coso partnerships,
with an average operating cost of $10.8/MWh, will be below the market-
clearing prices in each of those hours and, in the absence of a power
purchase agreement, would be dispatched accordingly.
. The Coso partnerships are eligible to receive AB1890 sponsored renewable
energy subsidies under Tier 3 of the Existing Renewable Energy category.
However, based on the assumptions made by us or on our behalf and by
Henwood Energy Services, Inc., the Transition Period short-run avoided
cost of energy price exceeds 3.0c per kWh (the floor price guaranteed by
AB1890) during most months of 2000 and 2001. Consequently, although
subsidy funds are available, short-run avoided cost of energy prices are
forecast to be sufficiently high that Tier 3 producers will not require a
subsidy in most months. In the event that future short-run avoided cost
of energy prices are lower than forecast in the energy markets
consultant's report, Henwood Energy Services, Inc. believes that the
AB1890 program has ample funds to ensure that Tier 3 producers receive a
minimum of 3.0c per kWh until the end of 2001.
. Henwood Energy Services, Inc. has reviewed the methodology and
assumptions used by us to estimate the AB1890 subsidy payments and it
believes that our assumptions are reasonable and our methodology and
calculations are consistent with and similar to its own procedures.
You should read "Exhibit B--The Energy Markets Consultant's Report" for a
more complete discussion of the conclusions expressed by Henwood Energy
Services, Inc. as of the date of the report.
The Geothermal Consultant's Report
Exhibit C of this prospectus contains a report prepared by GeothermEx, Inc.
dated May 1999. We sometimes call GeothermEx, Inc. our geothermal consultant.
GeothermEx, Inc. prepared this report, which we call the geothermal
consultant's report, in connection with the Series A notes offering. You should
be aware that the geothermal consultant's report has not been updated since
then. We included the geothermal consultant's report to help you understand and
evaluate the Coso projects. The geothermal consultant's work consisted of:
. a review of the status of the steam supply from the geothermal resource,
. a review of resource-related capital and operating costs, and
22
<PAGE>
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs contained in the projections provided by us or
on our behalf.
These projections have not been examined, compiled or subjected to any
procedures by either KPMG LLP or PricewaterhouseCoopers LLP. Accordingly,
neither KPMG LLP nor PricewaterhouseCoopers LLP expresses any opinion or other
form of assurance with respect to these projections. The PricewaterhouseCoopers
LLP reports included in this prospectus relate to the Coso partnerships'
historical financial information. The KPMG LLP report included in this
prospectus relates to our historical balance sheet as of April 22, 1999 (our
date of inception). These reports do not extend to the projections included in
the geothermal consultant's report and should not be read to do so.
We omitted from Exhibit C of this prospectus Appendices A through F of the
geothermal consultant's report. Appendices A through F include the production
histories for Navy I, BLM and Navy II production wells and the injection
histories for Navy I, BLM and Navy II injection wells. You can obtain copies of
Appendices A through F of the geothermal consultant's report from us upon
request (subject to possible confidentiality restrictions). See "Available
Information."
The geothermal consultant's report contains assumptions concerning material
contingencies and other matters that are not within our control or the control
of any other person. You should be aware that actual results will differ,
perhaps materially, from those projected. No one can assure you that these
assumptions are correct or that the conclusions in geothermal consultant's
report will match actual results of operations. Therefore, we do not make, or
intend to make, nor should you infer, any representation with respect to the
likelihood of any future outcome. If actual results are materially less
favorable than those shown or if the assumptions evaluated in the geothermal
consultant's report prove to be incorrect, the Coso partnerships' ability to
make payments to us under their project notes, our ability to make payments of
principal, premium, if any, and interest on the Series B notes when due, and
the Coso partnerships' ability to meet their obligations under their guarantees
could be materially and adversely affected. You should read "Risk Factors--
Uncertainties of Estimates, Projections and Assumptions" for more information.
We retained GeothermEx, Inc. based upon its expertise in the field of
geothermal energy. It has no affiliation with Caithness Energy, the Coso
partnerships or us.
Based upon its review, GeothermEx, Inc. reached the following main
conclusions in its report:
. The resource data supplied to GeothermEx, Inc. by us or on our behalf
appear reasonable based upon GeothermEx, Inc.'s long familiarity with the
Coso projects.
. The Coso geothermal resource has supplied steam to the plants for more
than ten years and has proven to be one of the most reliable geothermal
reservoirs in the United States.
. Geothermal energy reserves at the Coso geothermal resource are more than
sufficient to support the plants for 30 years. However, as in all
geothermal fields, make-up well drilling will be necessary to maintain
power output.
. Development of leaseholds adjacent to the Coso projects' acreage is
unlikely, and the possibility of any impact of offsetting development on
the performance of the Coso geothermal resource is remote.
. The financial projections provided to GeothermEx, Inc. by us or on our
behalf show a combined generation capacity of about 264 MW until year
2006 and declining thereafter. The
23
<PAGE>
forecasts of the generation decline trend after year 2006 made by us are
reasonable and very similar to GeothermEx, Inc.'s forecasts.
. The well drilling and workover programs assumed in the financial
projections provided by us or on our behalf are reasonable and should
result in steam supply sufficient to maintain the generation capacity
forecast in our financial projections.
. Resource-related capital and operating costs assumed in our financial
projections are reasonable and consistent with the historical trend and
industry practice.
You should read "Exhibit C--The Geothermal Consultant's Report" for a more
complete discussion of the conclusions reached by GeothermEx, Inc. as of the
date of the report.
24
<PAGE>
Summary Selected Historical and Pro Forma Financial and Operating Data
Because we were only recently formed, we have no financial or operating
history. The following tables set forth summary selected historical and pro
forma financial and operating data for each of the Coso partnerships on a
stand-alone basis, and summary selected pro forma financial and operating data
for the Coso partnerships on a combined basis, as of and for the periods
presented. The summary selected historical financial data for each of the five
years ended December 31, 1998 is derived from the audited financial statements
of each of the Coso partnerships. The summary selected historical financial
data and the pro forma financial data as of and for the six months ended June
30, 1998 and 1999 is unaudited.
The unaudited statement of operations data for the six months ended June 30,
1998 and the two months ended February 28, 1999, have been prepared on the same
basis as the audited financial statements included elsewhere in this
prospectus. The unaudited statement of operations data for the four months
ended June 30, 1999, has been prepared under a new basis of accounting adopted
by the Coso partnerships in connection with Caithness Acquisition's purchase of
all of CalEnergy's interests in the Coso projects. See "--The Purchase." In the
opinion of management, the unaudited statement of operations data contain all
adjustments, consisting only of normally recurring adjustments, necessary for a
fair presentation of such financial information. The unaudited financial data
set forth below is not necessarily indicative of results to be expected for any
future periods and should be read in conjunction with the historical financial
statements of each of the Coso partnerships, including the related notes
thereto, "Management's Discussion and Analysis of Financial Condition and
Results of Operations," "Unaudited Pro Forma Financial Data" and the other
financial information included elsewhere in this prospectus.
The energy revenues received by the Coso partnerships during the five-year
period ended December 31, 1998 and the six month periods ended June 30, 1998
and 1999, as reflected in the tables below, should not be viewed as an
indicator of energy revenues to be received by the Coso partnerships during any
future periods. During the periods reflected in the tables below, Edison made
energy payments to the Coso partnerships based on the fixed energy prices
provided for in the power purchase agreements, except that, since August 1997,
Edison has been making energy payments to the Navy I partnership based on
Edison's avoided cost of energy and, in March 1999, Edison began making
payments to the BLM partnership based on Edison's avoided cost of energy.
Edison's avoided cost of energy has been and is expected to be in the future
substantially lower than the fixed energy prices received by the Coso
partnerships in the past. Once the fixed energy price period for the Navy II
partnership expires, Edison is also expected to make energy payments to the
Navy II partnership based on Edison's avoided cost of energy. See "Risk
Factors--Impact of Avoid Cost of Energy Pricing" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
25
<PAGE>
Navy I Partnership
(Stand-alone)(a)
<TABLE>
<CAPTION>
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------- December 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $ 87,223 $ 92,797 $103,940 $ 86,586(b) $39,580(b) $39,580
Capacity revenues(f)... 14,258 14,266 14,266 13,845 13,573 13,573
Interest and other
income................ 2,529 2,893 3,286 1,980 585 585
-------- -------- -------- -------- ------- -------
Total revenues....... 104,020 109,956 121,492 102,411 53,738 53,738
Operating expenses..... 36,512 37,145 36,147 33,992 31,894 29,835
-------- -------- -------- -------- ------- -------
Operating income....... $ 67,508 $ 72,811 $ 85,345 $ 68,419 $21,844 $23,903
======== ======== ======== ======== ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 74,516 $ 70,192 $ 83,779 $ 88,540 $32,163
Net cash flows from
investing
activities............ (14,954) (7,922) (3,149) 17,948 (7,728)
Net cash flows from
financing
activities............ (23,499) (55,846) (109,999) (119,324) (27,323)
Ratio of earnings to
fixed charges(g)...... 5.2x 6.4x 9.6x 10.9x 5.0x 1.8x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 79,617 $ 85,581 $ 98,670 $ 81,233 $33,616 $35,259
Capital expenditures... 14,417 6,965 2,294 4,589 6,683 6,683
-------- -------- -------- -------- ------- -------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 65,200 $ 78,616 $ 96,376 $ 76,644 $26,933 $28,576
======== ======== ======== ======== ======= =======
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 6.1x 7.5x 11.1x 13.0x 7.8x 2.6x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 5.0x 6.9x 10.9x 12.2x 6.2x 2.1x
Operating Data:
Operating capacity
factor(j)(k).......... 114.0% 112.1% 112.1% 103.2% 94.6%
kWh produced........... 799,200 785,400 787,688 723,116 662,560
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
-------------------------------------
Two Months Four Months Pro Forma
Six Months Ended Ended Six Months
Ended February 28, June 30, Ended
June 30, 1999 1999 June 30,
1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $19,126 $ 8,098 $ 13,568 $ 21,666 $21,666
Capacity revenues(f)... 4,170 474 3,469 3,943 3,943
Interest and other
income................ 293 824 1,074 1,898 1,898
------- ------- -------- -------- -------
Total revenues....... 23,589 9,396 18,111 27,507 27,507
Operating expenses..... 15,532 5,716 9,673 15,389 15,060
------- ------- -------- -------- -------
Operating income....... $ 8,057 $ 3,680 $ 8,438 $ 12,118 $12,447
======= ======= ======== ======== =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $13,475 $ 6,592 $2,716 $9,308
Net cash flows from
investing
activities............ (2,566) (538) (21,194) (21,732)
Net cash flows from
financing
activities............ (13,013) (1,926) 17,399 15,473
Ratio of earnings to
fixed charges(g)...... 3.6x 5.6x 1.0x(n) 1.5x 1.5x
EBITDA(h).............. $13,968 $ 5,284 $ 9,238 $ 14,522 $14,796
Capital expenditures... 2,566 538 2,057 2,595 2,595
------- ------- -------- -------- -------
EBITDA less capital
expenditures.......... $11,402 $ 4,746 $ 7,181 $ 11,927 $12,201
======= ======= ======== ======== =======
Ratio of EBITDA to
fixed charges(i)...... 6.3x 8.0x 1.6x 2.2x 2.2x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 5.1x 7.2x 1.2x 1.8x 1.8x
Operating Data:
Operating capacity
factor(j)(k).......... 84.3% 73.4% 92.6% 83.0%
kWh produced........... 293,000 83,100 204,312 287,412
</TABLE>
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
26
<PAGE>
BLM Partnership
(Stand-alone)
<TABLE>
<CAPTION>
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------ Dec 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $ 76,134 $ 86,596 $ 87,985 $ 88,929 $ 93,352 $ 93,352
Capacity revenues(f)... 13,929 13,938 13,938 13,939 13,847 13,847
Interest and other
income................ 2,509 2,644 2,520 1,712 1,181 1,181
-------- -------- -------- -------- -------- --------
Total revenues....... 92,572 103,178 104,443 104,580 108,380 108,380
Operating expenses..... 41,289 40,418 40,017 43,193 44,687 40,654
-------- -------- -------- -------- -------- --------
Operating income....... $ 51,283 $ 62,760 $ 64,426 $ 61,387 $ 63,693 $ 67,726
======== ======== ======== ======== ======== ========
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 60,603 $ 63,426 $ 64,335 $ 60,948 $ 75,520
Net cash flows from
investing
activities............ (17,916) (8,480) (5,798) 19,280 (20,302)
Net cash flows from
financing
activities............ (21,194) (46,311) (85,590) (92,521) (56,091)
Ratio of earnings to
fixed charges(g)...... 3.2x 4.2x 4.9x 6.7x 10.2x 6.9x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 63,575 $ 75,930 $ 78,357 $ 75,644 $ 78,001 $ 80,383
Capital expenditures
(reimbursements)...... 17,437 8,425 6,033 3,728 20,302 20,302
-------- -------- -------- -------- -------- --------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 46,138 $ 67,505 $ 72,324 $ 71,916 $ 57,699 $ 60,081
======== ======== ======== ======== ======== ========
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 4.0x 5.0x 6.0x 8.3x 12.4x 8.2x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 2.9x 4.5x 5.5x 7.9x 9.2x 6.1x
Operating Data:
Operating capacity
factor(j)(k).......... 99.5% 107.5% 107.9% 99.6% 104.4%
kWh produced........... 697,000 753,200 758,115 697,794 731,767
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
------------------------------------
Two Months Four Months Pro Forma
Six Months Ended Ended Six Months
Ended February 28, June 30, Ended
June 30, 1999 1999 June 30,
1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $45,121 $16,716 $ 6,793 $23,509 $23,509
Capacity revenues(f)... 4,620 817 3,894 4,711 4,711
Interest and other
income................ 473 78 372 450 450
------- ------- ------- ------- -------
Total revenues....... 50,214 17,611 11,059 28,670 28,670
Operating expenses..... 22,904 8,181 11,282 19,463 18,799
------- ------- ------- ------- -------
Operating income....... $27,310 $ 9,430 $ (223) $ 9,207 $ 9,871
======= ======= ======= ======= =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $31,253 $10,367 $ 8,810 $19,177
Net cash flows from
investing
activities............ (8,742) 120 (15,480) (15,360)
Net cash flows from
financing
activities............ (20,755) 425 3,911 4,336
Ratio of earnings to
fixed charges(g)...... 7.7x 15.3x n/a(n) 1.3x 1.6x
EBITDA(h).............. $34,574 $11,980 $ 3,042 $15,022 $15,419
Capital expenditures
(reimbursements)...... 8,742 (120) 2,396 2,276 2,276
------- ------- ------- ------- -------
EBITDA less capital
expenditures.......... $25,832 $12,100 $ 646 $12,746 $13,143
======= ======= ======= ======= =======
Ratio of EBITDA to
fixed charges(i)...... 9.7x 19.4x 0.6x 2.7x 3.1x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 7.3x 19.6x 0.1x 2.3x 2.7x
Operating Data:
Operating capacity
factor(j)(k).......... 100.3% 109.8% 107.8% 108.8%
kWh produced........... 348,700 124,400 253,203 377,603
</TABLE>
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
27
<PAGE>
Navy II Partnership
(Stand-alone)
<TABLE>
<CAPTION>
Pro Forma
Year Ended December 31, Year Ended
------------------------------------------------- Dec. 31,
1994 1995 1996 1997 1998 1998(c)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $ 81,210 $ 94,372 $101,108 $ 98,778 $105,546 $105,546
Capacity revenues(f)... 14,008 14,018 14,018 14,018 14,018 14,018
Interest and other
income................ 3,072 3,040 3,174 2,187 1,799 1,799
-------- -------- -------- --------- -------- --------
Total revenues....... 98,290 111,430 118,300 114,983 121,363 121,363
Operating expenses..... 31,620 39,168 37,911 37,749 41,120 38,940
-------- -------- -------- --------- -------- --------
Operating income....... $ 66,670 $ 72,262 $ 80,389 $ 77,234 $ 80,243 $ 82,423
======== ======== ======== ========= ======== ========
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 68,432 $ 70,158 $ 74,611 $ 80,660 $ 84,762
Net cash flows from
investing
activities............ (15,091) (6,437) (3,883) 14,399 (6,939)
Net cash flows from
financing
activities............ (29,219) (60,843) (97,316) (112,044) (78,153)
Ratio of earnings to
fixed charges(g)...... 4.5x 5.2x 6.6x 7.3x 9.9x 6.3x
EBITDA before
cumulative effect of
accounting
change(h)............. $ 78,470 $ 85,110 $ 93,443 $ 90,588 $ 93,987 $ 95,937
Capital expenditures... 18,894 6,367 4,333 7,992 6,939 6,939
-------- -------- -------- --------- -------- --------
EBITDA before
cumulative effect of
accounting change
less capital
expenditures.......... $ 59,576 $ 78,743 $ 89,110 $ 82,596 $ 87,048 $ 88,998
======== ======== ======== ========= ======== ========
Ratio of EBITDA before
cumulative effect of
accounting change to
fixed charges(i)...... 5.3x 6.1x 7.7x 8.6x 11.6x 7.3x
Ratio of EBITDA before
cumulative effect of
accounting change
less capital
expenditures to fixed
charges(i)............ 4.0x 5.7x 7.3x 7.8x 10.7x 6.8x
Operating Data:
Operating capacity
factor(j)............. 105.9% 111.3% 110.6% 108.9% 108.6%
kWh produced........... 742,400 779,800 777,243 762,821 760,659
</TABLE>
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
--------------------------------------
Two Months Four Months Pro Forma
Ended Ended Six Months
Six Months February 28, June 30, Ended June
Ended June 1999 1999 30,
30, 1998 (prior basis) (new basis)(d) Total 1999(e)
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $ 49,920 $16,687 $ 31,272 $ 47,959 $47,959
Capacity revenues(f)... 4,738 822 3,916 4,738 4,738
Interest and other
income................ 780 150 733 883 883
-------- ------- --------- -------- -------
Total revenues....... 55,438 17,659 35,921 53,580 53,580
Operating expenses..... 21,086 7,340 13,100 20,440 20,115
-------- ------- --------- -------- -------
Operating income....... $ 34,352 $10,319 $ 22,821 $ 33,140 $33,465
======== ======= ========= ======== =======
Additional Financial
Data:
Net cash flows from
operating
activities............ $ 36,048 $12,016 $ 16,941 $ 28,957
Net cash flows from
investing
activities............ (2,735) (1,126) $ (19,468) (20,594)
Net cash flows from
financing
activities............ (33,212) 1,766 $ 2,075 3,841
Ratio of earnings to
fixed charges(g)...... 7.7x 10.8x 3.2x(n) 4.2x 4.8x
EBITDA(h).............. $ 41,368 $12,658 $ 25,428 $ 38,086 $38,411
Capital expenditures... 2,735 1,126 857 1,983 1,983
-------- ------- --------- -------- -------
EBITDA less capital
expenditures.......... $ 38,633 $11,532 $ 24,571 $ 36,103 $36,428
======== ======= ========= ======== =======
Ratio of EBITDA to
fixed charges(i)...... 9.3x 13.3x 3.9x 5.1x 5.8x
Ratio of EBITDA less
capital expenditures
to fixed charges(i)... 8.7x 12.1x 3.8x 4.9x 5.5x
Operating Data:
Operating capacity
factor(j)............. 106.5% 112.7% 111.9% 112.3%
kWh produced........... 370,000 127,700 247,958 375,658
</TABLE>
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
28
<PAGE>
The Coso Partnerships
(Combined)(l)
<TABLE>
<CAPTION>
Pro Forma
Six
Pro Forma Months
Year Ended Ended
Dec. 31, June 30,
1998(c) 1999(e)
(In thousands,
except ratio data)
<S> <C> <C>
Statement of Operations Data:
Energy revenues.......................................... $238,478 $ 93,134
Capacity revenues(f)..................................... 41,438 13,392
Interest and other income................................ 3,565 3,231
-------- --------
Total revenues......................................... 283,481 109,757
Operating expenses....................................... 109,429 53,974
-------- --------
Operating income......................................... $174,052 $ 55,783
======== ========
Additional Financial Data:
Ratio of earnings to fixed charges(g).................... 4.8x 2.7x
EBITDA before cumulative effect of accounting
change(h)............................................... $211,579 $ 68,626
Capital expenditures..................................... 33,924 6,854
-------- --------
EBITDA before cumulative effect of accounting change
less capital expenditures............................... $177,655 $ 61,772
======== ========
Ratio of EBITDA before cumulative effect of accounting
change to fixed charges(i).............................. 5.8x 3.8x
Ratio of EBITDA before cumulative effect of accounting
change less capital expenditures to fixed charges(i).... 4.9x 3.4x
</TABLE>
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
29
<PAGE>
<TABLE>
<CAPTION>
As of December 31, As of As of
-------------------------------------------- June 30, June 30,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Navy I Partnership (stand-alone)(a)
Cash.................. $ 38,669 $ 45,093 $ 15,724 $ 2,888 $ -- $ 784 $ 3,049
Restricted cash and
investments.......... 27,204 28,161 29,016 6,479 7,524 6,995 26,600
Property, plant and
equipment, net....... 211,453 205,648 194,617 186,392 180,380 183,047 157,953
Power purchase
agreement, net....... -- -- -- -- -- -- 14,284
Total assets.......... 298,684 301,436 264,209 209,390 201,888 205,380 219,013
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $154,432 $127,340 $ 76,056 $ 45,666 $ 40,566 $ 43,116 $ --
Project notes(m)..... -- -- -- -- -- -- 151,550
Partners' capital..... 131,880 164,581 167,834 155,568 149,933 151,446 50,001
-------- -------- -------- -------- -------- -------- --------
Total capitalization.. $286,312 $291,921 $243,890 $201,234 $190,499 $194,562 $201,551
======== ======== ======== ======== ======== ======== ========
BLM Partnership (stand-
alone)
Cash.................. $ 31,584 $ 40,219 $ 13,166 $ 873 $ -- $ 2,629 $ 8,153
Restricted cash and
investments.......... 23,478 23,533 23,298 290 290 290 13,507
Property, plant and
equipment, net....... 220,881 216,136 208,238 197,709 201,600 199,187 161,111
Power purchase
agreement, net....... -- -- -- -- -- -- 20,241
Total assets.......... 298,893 305,106 269,318 224,912 228,087 229,663 220,032
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $155,661 $137,748 $105,990 $ 76,654 $ 37,958 $ 57,306 $ --
Project notes(m)..... -- -- -- -- -- -- 107,900
Partners' capital..... 100,261 119,560 112,666 124,113 163,191 146,460 87,336
-------- -------- -------- -------- -------- -------- --------
Total capitalization.. $255,922 $257,308 $218,656 $200,767 $201,149 $203,766 $195,236
======== ======== ======== ======== ======== ======== ========
Navy II Partnership (stand-alone)
Cash.................. $ 41,843 $ 44,721 $ 18,133 $ 1,148 $ 818 $ 1,249 $ 13,042
Restricted cash and
investments.......... 22,771 22,841 22,391 -- -- -- 18,676
Property, plant and
equipment, net....... 219,047 212,566 203,845 198,483 188,862 194,202 147,056
Power purchase
agreement, net....... -- -- -- -- -- -- 28,750
Total assets.......... 309,212 307,537 270,522 226,949 218,965 224,557 243,326
Project loans:
Existing project
debt, payable to
Coso Funding
Corp. .............. $173,413 $156,043 $124,361 $ 97,267 $ 61,323 $ 79,295 $ --
Project notes(m)..... -- -- -- -- -- -- 153,550
Partners' capital..... 125,161 140,082 126,092 125,413 153,661 140,072 82,917
-------- -------- -------- -------- -------- -------- --------
Total capitalization.. $298,574 $296,125 $250,453 $222,680 $214,984 $219,367 $236,467
======== ======== ======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
As of
June 30,
1999(m)
(In thousands)
<S> <C>
Balance Sheet Data:
The Coso partnerships (combined)(l)
Cash.......................................................... $ 24,244
Restricted cash............................................... 58,783
Property, plant and equipment, net............................ 466,120
Power purchase agreement, net................................. 63,275
Total assets.................................................. 682,371
Project loans:
Existing project debt, payable to Coso Funding Corp. ........ $ --
Project notes(m)............................................. 413,000
Partners' capital............................................. 220,254
--------
Total capitalization.......................................... $633,254
========
</TABLE>
See Footnotes to Summary Selected Historical and Pro Forma Financial and
Operating Data
30
<PAGE>
Footnotes to Summary Selected Historical and Pro Forma Financial and Operating
Data
(a) Reflects the combined financial results of the Navy I partnership and Coso
Finance Partners II, a California general partnership ("CFP II"). The Navy
I partnership and CFP II were first formed as separate entities to
facilitate the initial bank financing for the construction and development
of Navy I. Initially, the Navy I partnership acquired all of the assets
relating to the first turbine generator unit at Navy I and CFP II acquired
all of the assets of Navy I relating to the second and third generator
units at Navy I. In 1988, CFP II assigned all of its rights and interests
in the second and third generator units at Navy I to the Navy I partnership
in return for a 5.0% royalty to be paid based on the Navy I partnership's
steam production. Since the Navy I partnership and CFP II operate under
common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the Series A notes offering.
See Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) The decrease in energy revenues is due to the fact that Edison paid the
Navy I partnership energy payments based on Edison's position that the
fixed energy price period expired for the Navy I partnership in August
1997. Edison has also taken the position that the fixed energy price period
for the BLM partnership expired in March 1999 and will expire for the Navy
II partnership in January 2000. The Coso partnerships believe that under
the power purchase agreements each of the three turbine generator units at
each Coso project has its own ten-year fixed energy price period. This
issue is one of several currently in dispute and subject to an ongoing
lawsuit between, among others, the Coso partnerships and Edison. You should
read "Business--Legal Proceedings" for more information regarding this
issue and the lawsuit.
(c) Pro forma financial information is based upon the historical financial
statements of each of the Coso partnerships on a stand-alone basis or the
Coso partnerships on a combined basis, as the case may be, for the year
ended December 31, 1998, adjusted for (1) a reduction in O&M and management
committee fees, (2) a net reduction in depreciation and amortization
expenses relating to Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects and (3) an increase in interest expense
relating to the offering, as if such transactions had occurred on January
1, 1998. See "Unaudited Pro Forma Financial Data."
(d) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(e) Pro forma financial information is based upon the historical financial
statements of each of the Coso partnerships on a stand-alone basis or the
Coso partnerships on a combined basis, as the case may be, for the six
months ended June 30, 1999, adjusted for (1) a reduction in O&M and
management committee fees, (2) a net reduction in depreciation and
amortization expenses relating to Caithness Acquisition's purchase of all
of CalEnergy's interests in the Coso projects and (3) an increase in
interest expense relating to the offering, as if such transactions had
occurred on January 1, 1999. See "Unaudited Pro Forma Financial Data."
31
<PAGE>
(f) Includes capacity payments and capacity bonus payments paid to the
applicable Coso partnership under its power purchase agreement.
(g) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(h) EBITDA is defined as earnings before interest expense, depreciation and
amortization and the cumulative effect of the accounting change for start-
up costs (for the year ended December 31, 1998 only). The Coso partnerships
are general partnerships and therefore do not pay income taxes. We believe
that EBITDA provides useful information regarding the Coso partnerships'
ability to service its indebtedness, but it should not be considered in
isolation or as a substitute for operating income or cash flow from
operations (in each case as determined in accordance with GAAP), as an
indicator of the Coso partnerships' operating performance or as a measure
of the Coso partnerships' liquidity. Other companies may calculate EBITDA
in a different manner than the Coso partnerships. EBITDA does not take into
consideration substantial costs and cash flows of doing business, such as
interest expense, depreciation, and amortization. EBITDA does not represent
funds available for discretionary use by the Coso partnerships because
those funds are required for debt service, capital expenditures to replace
fixed assets, working capital and other commitments and contingencies.
EBITDA is not an accounting term.
(i) For purposes of computing the ratio of EBITDA before cumulative effect of
accounting change to fixed charges and EBITDA before cumulative effect of
accounting change less capital expenditures to fixed charges, fixed charges
consist of interest expense and amortization of debt issuance costs. We
believe that these ratios provide useful information regarding the Coso
partnerships' ability to service its indebtedness, but they should not be
considered in isolation or as a substitute for operating income or cash
flow from operations (in each case as determined in accordance with GAAP)
or the ratio of earnings to fixed charges, as an indicator of the Coso
partnerships' operating performance or as a measure of the Coso
partnerships' liquidity. Other companies may calculate these ratios in a
different manner than the Coso partnerships. These ratios are not
accounting terms.
(j) Based on a generating capacity of 80 MW.
(k) The reduction in the operating capacity factor for the Navy I partnership
and the increase in the operating capacity factor for the BLM partnership
is due to the transfer of steam from the Navy I partnership to the BLM
partnership and the Navy II partnership under the steam sharing program.
See "Business--Steam Sharing Program" and "Summary Descriptions of
Principal Agreements Relating to the Coso Projects--Steam Exchange and
Cotenancy Agreements."
(l) Reflects the mathematical summation of pro forma financial information of
the Coso partnerships on a combined basis as of and for the year ended
December 31, 1998, and as of and for the six months ended June 30, 1999.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the financial condition or results of operations that
would have occurred had the Coso partnerships constituted a single entity
as of or during the same period. Because the Coso partnerships are under
common management and have jointly and severally guaranteed all of our
obligations under the Indenture and the senior secured notes, such
guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a
perfected, first priority pledge of all of the ownership interests in the
Coso partnerships, the combined financial information of the Coso
partnerships has been presented.
32
<PAGE>
(m) Reflects indebtedness owed to us. We loaned all of the proceeds from the
offering to the Coso partnerships at interest rates and maturities
identical to the interest rates and maturities of the senior secured notes.
(n) The decrease in the ratio of earnings to fixed charges for the four months
ended June 30, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million, $1.4 million and $2.0 million for the
Navy I partnership, BLM partnership and Navy II partnership, respectively,
related to the short-term debt financing associated with Caithness
Acquisition's purchase of CalEnergy's interests in the Coso projects over
the three-month estimated life of the short-term debt and premiums paid to
retire the existing project debt of approximately $2.4 million, $1.8
million and $2.1 million for the Navy I partnership, BLM partnership and
Navy II partnership, respectively. Earnings are inadequate to cover fixed
charges for the Navy II partnership for the four months ended June 30, 1999
by $6.9 million.
33
<PAGE>
RISK FACTORS
In addition to the other information set forth in this prospectus, you
should carefully consider the risks described below before deciding to tender
your Series A notes in the exchange offer. These risks are not the only ones
facing the Coso partnerships and us. Additional risks not presently known to
us or that we deem immaterial may also impair the Coso partnerships'
operations and our ability to make payments to you under the Series B notes.
This prospectus also contains forward-looking statements that involve risks
and uncertainties. Our and the Coso partnerships' actual results could differ
materially from those anticipated in these forward-looking statements as a
result of certain factors, including the risks faced by the Coso partnerships
and us described below and elsewhere in this prospectus. You should read
"Forward-Looking Statements" for more information regarding these forward-
looking statements.
Your failure to exchange your Series A notes for Series B notes could have
adverse consequences to you.
The Series A notes were not registered under the Securities Act or under the
securities laws of any state and may not be resold, offered for resale or
otherwise transferred unless they are subsequently registered or resold
pursuant to an exemption from the registration requirements of the Securities
Act and applicable state securities laws. If you do not exchange your
unregistered Series A notes for registered Series B notes pursuant to the
exchange offer, you will not be able to resell, offer to resell or otherwise
transfer the Series A notes unless they are registered under the Securities
Act or unless you resell them, offer to resell or otherwise transfer them
under an exemption from the registration requirements of, or in a transaction
not subject to, the Securities Act. In addition, we and the Coso partnerships
will not be obligated to register the Series A notes under the Securities Act
after the Exchange Offer except in the limited circumstances provided under
the registration rights agreement. In addition, to the extent that Series A
notes are tendered for exchange and accepted in the exchange offer, the market
for the untendered and tendered but unaccepted Series A notes could be
materially and adversely affected.
Your recourse if a default occurs will be limited to the assets and cash flow
of the Coso projects.
We are a special purpose company formed for the purpose of issuing the
senior secured notes for ourselves and on behalf of the Coso partnerships. At
the closing of the Series A notes offering, we loaned all of the proceeds from
the offering to the Coso partnerships. We do not conduct any business, other
than issuing the senior secured notes and making the loans to the Coso
partnerships. Our ability to make payments to you under the Series B notes
will be entirely dependent on the performance of the Coso partnerships under
their project notes. As is common in non-recourse, project finance structures,
the assets and cash flow of the Coso partnerships are the sole source of
payment under their project notes and guarantees.
The Coso partnerships own no significant assets other than those related to
the ownership and operation of the Coso projects. If a Coso partnership
defaults under its project note, credit agreement or guarantee, our remedies
under the Coso partnerships' project notes, credit agreements and guarantees,
including foreclosure of that Coso partnership's assets, may not provide
sufficient funds to pay that Coso partnership's, or any other Coso
partnership's, obligations under its project notes, credit agreements and
guarantees. None of our shareholders, partners or affiliates (other than the
34
<PAGE>
Coso partnerships), none of the partners or affiliates of the Coso partnerships
(other than the partners of the Coso partnerships solely with respect to their
ownership interests in the Coso partnerships) and none of our, Caithness
Energy's or the Coso partnerships' directors, officers or employees will
guarantee or be in any way liable for payment of the Series B notes, the
project notes or the guarantees. See "Description of Series B Notes--Brief
Description of the Series B Notes and Guarantees."
Our ability to make payments to you under the Series B notes will depend
entirely on the successful operation of the Coso projects.
Our ability to make payments of principal, premium, if any, and interest on
the Series B notes depends entirely on our receipt of payments from the Coso
partnerships under their project notes and guarantees, and their ability to
make payments under their project notes and guarantees depends entirely on the
successful operation of the Coso projects. If one or more Coso partnerships
cannot make payments under their project notes and guarantees, we might not
have sufficient funds to pay you.
Operating the Coso projects involves, among other things, general economic,
financial, competitive, legislative, regulatory and other factors that are
beyond our control. Changes in these factors could make it more expensive for
the Coso partnerships to operate the Coso projects, could require additional
capital expenditures or could reduce certain benefits currently available to
the Coso partnerships. A variety of other risks affect the Coso projects, some
of which are beyond our control, including:
. One or more of the Coso projects could perform below expected levels of
output or efficiency;
. The Coso geothermal resource could be interrupted or unavailable;
. Operating costs could increase;
. Energy prices paid by Edison could decrease;
. Delivery of electrical energy to Edison could be disrupted;
. Environmental problems could arise which could lead to fines or a
shutdown of one or more plants;
. Plant units and equipment have broken down or failed in the past and
could break down or fail in the future;
. The operators of the Coso projects could suffer labor disputes;
. The government could change permit or governmental approval requirements;
. Third parties could fail to perform their contractual obligations to the
Coso partnerships; and
. Catastrophic events, such as fires, earthquakes, explosions, floods,
severe storms or other occurrences, could affect one or more of the Coso
projects or Edison.
No one can assure you that none of these events will happen. For some
information regarding the recent shutdown of Unit 1 at Navy I resulting from
equipment failure, see "Business--Overview of Coso Projects--Plants--Navy I."
35
<PAGE>
Further, no one can assure you that the Coso partnerships' operations will
generate sufficient cash, that currently anticipated cost savings or capital or
other operating improvements will be realized on schedule or that the Coso
partnerships will be successfully operated in the future to enable the Coso
partnerships to make payments under their project notes and guarantees. In
addition, no one can assure you that the Coso partnerships' financial condition
or results of operations in the future will match those of the past.
In addition, the Coso partnerships must meet specified performance
requirements under their power purchase agreements during the months of June
through September to continue to qualify for the maximum capacity and capacity
bonus payments. If one or more of the events listed above occur and
substantially affect the performance of one or more of the plants during these
months, operating revenues would significantly decrease. If operating revenues
decrease, one or more of the Coso partnerships may not be able to make payments
under their project notes and guarantees. This would impair our ability to make
payments to you under the Series B notes.
Future energy payments paid by Edison to the Coso partnerships will most likely
be less than historical energy payments because they will be paid based on
Edison's avoided cost of energy.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Edison under the power purchase agreements. For more information
regarding the power purchase agreements, see "Summary Descriptions of Principal
Agreements Relating to the Coso Projects--Power Purchase Agreements."
Under the power purchase agreements, Edison must pay to the Coso partnerships
capacity payments which are fixed throughout the lives of these agreements.
Edison must also pay capacity bonus payments under the power purchase
agreements. The maximum annual capacity bonus payment available is also fixed
throughout the lives of the power purchase agreements. Edison must also pay to
the Coso partnerships energy payments which are fixed for only the first ten
years of the terms of the power purchase agreements. Thereafter, energy
payments will depend on Edison's avoided cost of energy, as determined under
certain legislation being implemented by the California Public Utilities
Commission. Edison has taken the position that the fixed energy price period
expired in August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. See
"--The Coso partnerships and their managing partners are currently involved in
material litigation with Edison, their sole customer" and "Business--Legal
Proceedings."
Edison has made energy payments to the Navy I partnership since the end of
August 1997 based upon Edison's avoided cost of energy. For the year ended
December 31, 1998, Edison's average avoided cost of energy paid to the Navy I
partnership was 3.0c per kWh, which is substantially below the fixed energy
prices earned by the Navy I partnership prior to August 1997 and by the BLM
partnership and the Navy II partnership in 1998. The BLM partnership is now
receiving energy payments based on Edison's avoided cost of energy and will
likely receive energy payments in the future which are substantially less than
the fixed energy prices it earned in 1998. We also expect that, after the Navy
II partnership's fixed energy price period expires, Edison's avoided cost of
energy payable to the Navy II partnership will be substantially below the fixed
energy prices currently being paid by Edison to the Navy II partnership under
its power purchase agreement. You should read "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for more information
regarding energy payments received by the Coso partnerships.
36
<PAGE>
Although Edison pays the Navy I partnership and the BLM partnership energy
payments based on 100% of its currently published avoided cost of energy, as
determined by a methodology approved by, and subject to change by, the
California Public Utilities Commission (currently based on a formula tied to
the price of natural gas), this will change within the next twelve months.
Under AB1890, the comprehensive restructuring legislation enacted in California
in September 1996, the California Public Utilities Commission is required to
calculate short-term avoided cost of energy for payments made to non-utility
power generators, such as the Coso partnerships, based on the clearing price
paid by the California Power Exchange when certain conditions are met. These
conditions include that (1) the California Public Utilities Commission has
issued an order determining that the California Power Exchange is "functioning
properly" and (2) either:
(a) the fossil-fired generation units owned by the purchasing utility
(such as Edison) are authorized to charge market-based rates and
the variable costs of such units are being recovered solely through
clearing prices being paid by the California Power Exchange or from
contracts with the independent system operator discussed under "--
The operations of the Coso projects could be adversely affected by
an inability to comply with regulatory standards--Changes in
California Electric Market"; or
(b) the purchasing utility has divested ninety percent of its gas-fired
generation facilities that were operated to meet load in 1994 and
1995.
For more information regarding the California Power Exchange, you should read
"--The operations of the Coso projects could be adversely affected by an
inability to comply with regulatory standards--Changes in California Electric
Market" and "Business--Power Sales--Energy Payments." Divestiture of such gas-
fired generation facilities by Edison and the other two large California
utilities is expected to be complete by the end of 1999.
It is likely that within the next twelve months, pursuant to AB1890, Edison's
short-term avoided cost of energy will equal the then-prevailing market
clearing price for wholesale energy at the California Power Exchange. Whether
this pricing will be on an hourly basis, a daily or block average basis
(i.e., a daily average, daily off-peak or daily on-peak time period averages)
or some other variation has not been determined. We note, however, that on July
27, 1999, the CPUC issued a ruling calling for comments on a number of issues
relating to its implementation of the methodology for determining short run
avoided cost ("SRAC") based on the clearing price of the California Power
Exchange. It is expected that the CPUC will resolve these issues no later than
June 2000. We also note that on October 7, 1999, the CPUC is scheduled to
consider a proposed decision that would grant a motion filed by a number of QF
facilities to allow them to elect unilaterally, pursuant to California Public
Utilities Code Section 390, to receive, on an interim basis, SRAC payments
based on the California Power Exchange zonal day-ahead clearing price. The
payments made under this election would be subject to adjustment, depending on
the SRAC methodology ultimately adopted by the CPUC under AB 1890. The market
clearing prices for wholesale energy on the California Power Exchange have
occasionally for brief periods exceeded current energy prices paid by Edison
under the power purchase agreements based on its short-term avoided cost of
energy. This has occurred most often during high load conditions, warm weather
and other daily or seasonal peak periods. At other times, the market clearing
prices have been lower than Edison's short-term avoided cost of energy. No one
can predict the outcome of the final implementation of this change in computing
short-term avoided cost of energy, or the performance of California Power
Exchange clearing prices over time. See "--The operations of the Coso projects
could be adversely affected by an inability to comply with regulatory
standards--Changes in California Electric Market."
37
<PAGE>
In addition, under AB1890, the Navy I partnership has been eligible to
receive since 1998 subsidy payments for energy delivered by it to Edison. Going
forward, the Navy I partnership and the other Coso partnerships should at times
qualify to receive subsidy payments through 2001 for energy delivered to
Edison. Subsidy payments are made if Edison's avoided cost of energy falls
below 3.0c per kWh, subject to a maximum subsidy of 1.0c per kWh. No one can
assure you that the AB1890 fund will have funds sufficient to continue to make
their subsidy payments to the Coso partnerships through 2001. See "Business--
AB1890 Energy Subsidy Payments."
The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time.
Under a Geothermal Power Development Service Contract with the United States
Government acting through the United States Navy (the "Navy"), the Navy I
partnership and the Navy II partnership have exclusive contractual rights to
explore, develop and use, currently without any known interference from any
other power developers, a portion of the Coso Known Geothermal Resource Area at
and around Navy I and Navy II. We call this contract the Navy Contract. The
Navy Contract expires in December 2009, the same month and year in which the
maturity date of the Series B notes due 2009 occurs.
The Navy has the right to terminate the Navy Contract at any time for reasons
of national security, national defense preparedness or national emergency, or
for any other reasons that are in the best interests of the United States
Government. If the Navy were to terminate the Navy Contract, the United States
Government would be obligated to pay the Navy I partnership a maximum amount of
approximately $165.0 million and the Navy II partnership a maximum amount of
approximately $187.5 million, or a maximum aggregate amount of approximately
$352.5 million, to compensate it or them for the unamortized portion of their
exploratory investment and for the investment in their installed power plant
facilities. Such payment would not take into consideration the loss of
anticipated future profits resulting from such termination and may be
insufficient to enable the Coso partnerships to repay their project notes and
guarantees fully. This would materially adversely affect our ability to make
payments to you under the Series B notes. In addition, the Navy would not make
any payments to the BLM partnership, which might not be able to continue to
operate BLM and its facilities following such termination. For more
information, you should read "Summary Descriptions of Principal Agreements
Relating to the Coso Projects--The Navy Contract."
In addition to its right to terminate the Navy Contract, the Navy may, from
time to time, impose certain access and operational restrictions on all three
Coso partnerships for purposes of national security, personnel safety,
protection of property or protection of the environment, and under certain
circumstances may impose emissions standards. The Navy has periodically ordered
all personnel at the Coso projects to evacuate the plant sites and fields.
Evacuation periods have typically continued for three-to-four hours, although
the periods have continued for up to 12 hours. During such evacuation periods,
the plants must be operated via a remote station located at the outskirts of
the Navy base. This station currently utilizes rights of way obtained from the
Bureau of Land Management. These rights of way are still held by CalEnergy, and
CalEnergy has agreed to transfer them to the Coso partnerships once the consent
of the Bureau of Land Management has been obtained. No one can assure you that
this consent will be obtained. Periodic evacuations will likely recur in the
future. We cannot assure you that the Coso partnerships will always be able to
operate the plants from this remote station during evacuation periods. For more
information regarding this station, you should read "Summary Descriptions of
Principal Agreements Relating to the Coso Projects--The Navy Contract."
38
<PAGE>
The Coso partnerships rely on certain contractual arrangements among them
relating to the transfer of steam among the Coso projects, which we call the
steam sharing agreement. Each of the Navy and the Bureau of Land Management has
reserved the right in its sole discretion to suspend or limit the transfer of
steam among the Coso projects under certain circumstances. See "Business--Steam
Sharing Program" and "Summary Description of Principal Agreements Relating to
the Coso Projects--Steam Sharing and Co-Tenancy Agreements."
Our ability to repay the Series B notes will depend on unrelated third parties
fulfilling their commitments to the Coso partnerships.
The viability of the Coso projects, the Coso partnerships' ability to make
payments under their project notes and guarantees, and our ability to make
payments of principal, premium, if any, and interest on the Series B notes when
due, may be materially and adversely affected by the performance of third
parties whom we do not control under commercial agreements to which the Coso
partnerships are parties. These third parties include, among others:
. the Navy under the Navy Contract and the steam sharing agreement;
. the Bureau of Land Management under the BLM lease, the steam sharing
agreement and the leases on which BLM North is located, which we call the
LADWP leases;
. FPL Operating under its O&M agreements with the Coso partnerships; and
. Edison under the power purchase agreements.
We call these commercial agreements, together with the other documents and
agreements relating to the Coso projects, the project documents.
If any of these third parties:
. claim that there was a defect in proceedings with respect to the approval
of their project documents,
. claim that their project documents were not duly authorized by them,
. disavow their obligations under their project documents,
. fail to perform their contractual or other obligations, or
. are excused from performing their obligations because the Coso
partnerships have failed to perform theirs or because an event has
occurred outside of our or their control,
then the Coso partnerships may not be able to obtain alternate customers, goods
or services to cover these third parties' non-performance. In particular, if
Edison fails to fulfill its contractual obligations under any power purchase
agreement, it would have a material adverse effect on the Coso projects'
revenues and would materially and adversely affect the Coso partnerships'
ability to make payments under their project notes and guarantees. This would
materially and adversely affect our ability to make payments of principal,
premium, if any, and interest on the Series B notes when due.
The Coso partnerships depend on Edison's purchases of all electrical energy
generated by the plants for substantially all of their operating revenues. The
payments being made by Edison to the Navy II partnership for energy under its
power purchase agreement currently exceed Edison's actual avoided cost of
energy by a substantial margin. If this situation continues, or if Edison
experiences financial, regulatory or other pressures, Edison could try to amend
the Navy II partnership's power
39
<PAGE>
purchase agreement. Edison could also attempt, as it has in the past, to
terminate the power purchase agreements. The provisions of the power purchase
agreements do not permit Edison to amend or terminate any of the agreements
early without the consent of the applicable Coso partnership, and the Indenture
prohibits the Coso partnerships from giving such consent if the effect on the
holders of the senior secured notes would be materially adverse. Nonetheless,
it is possible that, upon a change in applicable legislation, case law and/or
regulations, a court or governmental authority could order or allow such an
amendment or termination of one or more power purchase agreements. Such an
amendment or termination would materially and adversely affect the revenues of
the affected Coso partnership or partnerships and consequently the cash flow
available to make payments under its or their project notes and guarantees.
This would materially and adversely affect our ability to make payments to you
under the Series B notes. It would probably also constitute an event of default
under the Indenture. See "--The Coso partnerships and their managing partners
are currently involved in material litigation with Edison, their sole customer"
and "Business--Legal Proceedings."
The Coso partnerships and their managing partners are currently involved in
material litigation with Edison, their sole customer.
The Coso partnerships, the Coso partnerships' managing partners and
CalEnergy, which we collectively refer to as the Coso Parties, are involved in
an ongoing lawsuit with Edison. Edison is the Coso partnerships' sole customer.
Edison asserts a number of breach of contract claims that relate to the alleged
surreptitious venting of certain non-condensable gases from unmonitored
reinjection wells located adjacent to the plants. The Coso Parties have filed a
cross-complaint against Edison asserting, among others, breach of contract
claims, violations of state law and of decisions of the California Public
Utilities Commission and that Edison's lawsuit is barred by a settlement
agreement entered into in 1993. In addition, the Coso partnerships have filed a
separate lawsuit against Edison seeking restitution and injunctive relief for
unfair competition and false advertising. You should read "Business--Legal
Proceedings" for a more thorough discussion of the issues and claims in this
lawsuit.
No one can predict at this time whether Edison will prevail on its claims
against any or all of the Coso Parties or whether any or all of the Coso
Parties will prevail on their claims against Edison, in part because pre-trial
discovery has not been completed and in part because of the complexity of the
factual and legal issues involved. While the parties to the lawsuits have
signed a stipulation agreeing to a moratorium on all ongoing activities in the
lawsuit to explore the possibility of a negotiated settlement, no one can
assure you that the parties will be able reach a settlement or, if they do,
what the terms of that settlement would be. The moratorium was originally set
to expire on May 30, 1999. By agreement of the parties, the moratorium was
extended to September 30, 1999, and the parties held a mediation session before
a former California supreme court justice during the week of September 7, 1999.
Subsequent to that mediation session, the parties agreed to extend further the
moratorium through October 28, 1999, to allow the parties to continue their
settlement discussions.
It is possible that the parties will be unable to reach a settlement and
Edison could recover significant damages in the lawsuit. Edison has not yet
provided the Coso Parties with any formal calculation or estimate of its
alleged damages, but the Coso Parties expect Edison to seek damages in an
amount which would be material to the financial condition and results of
operations of the Coso partnerships, either individually or taken as a whole.
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Our substantial debt and our ability to incur additional debt in the future
could adversely affect our financial health and prevent us from satisfying our
obligations under the Series B notes.
We have now and, after this exchange offer, will continue to have a
significant amount of debt and interest expense. As of June 30, 1999, the Coso
partnerships' total aggregate debt was $413.0 million and partners' aggregate
capital was $220.2 million. This results in a total debt to total
capitalization ratio of 0.65x as of June 30, 1999.
Our substantial indebtedness could have important consequences to you. For
example, it could:
. make it more difficult for the Coso partnerships to make payments to
us under their project notes and for us to make payments to you under
the Series B notes;
. increase our vulnerability to general adverse economic and industry
conditions;
. limit our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate; and
. limit, along with the financial and other restrictive covenants in
our debt documents, among other things, our ability to borrow
additional funds.
In addition, failure to comply with covenants in our debt documents could
result in an event of default which, if not cured or waived, could have a
material adverse effect on us.
In addition, we and the Coso partnerships will be able to incur additional
debt from time to time in the future. The terms of the Indenture do not fully
prohibit us or the Coso partnerships from doing so. If new debt is added to our
current debt levels, the related risks that we now face could intensify. See
"Capitalization" and "Selected Historical and Pro Forma Financial and Operating
Data."
Exploring and developing geothermal resources is inherently risky.
Geothermal exploration, development and operations are subject to
uncertainties which vary among different geothermal reservoirs and are similar
to those typically associated with oil and gas exploration and development,
including unproductive wells and uncontrolled releases. The geographic area and
sustainable output thereof can only be estimated and cannot be definitively
established because of the geological complexities of geothermal reservoirs.
Consequently, the Coso partnerships could experience an unexpected decline in
the capacity of their geothermal wells, and the Coso geothermal reservoir might
not be sufficient for the sustained production of steam and electricity
throughout the maturity dates of the Series B notes.
The operations of the Coso projects could be adversely affected by the Coso
partnerships' and their operators' inability to comply with regulatory
standards.
Permitting; Environmental
The Coso partnerships and their operators are required to comply with many
federal, state and local statutory and regulatory standards and to maintain
numerous permits and governmental approvals required to operate the Coso
projects. Some of these permits and governmental approvals contain specific
conditions. Over the years, there have been numerous violations of these
permits, governmental approvals and conditions, as well as of regulations of
governmental authorities charged with enforcing these matters. If any Coso
partnership fails to satisfy applicable permits, governmental
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approval, conditions or regulations, it could be prevented from operating its
Coso project and incur additional costs. No one can assure you that the Coso
partnerships and their operators will be able to operate the Coso projects in
the future in accordance with applicable permits, governmental approvals,
conditions or regulations, or that the conditions contained in these permits or
governmental approvals will not change.
In addition, the Coso partnerships usually have several applications for new
permits and governmental approvals, or renewals of existing permits and
governmental approvals, pending before certain governmental authorities. These
governmental authorities can sometimes take up to several years to approve an
application. No one can assure you that the Coso partnerships will be able to
obtain, renew or maintain the permits and governmental approvals required to
operate the Coso projects through the maturity dates of the Series B notes. If
any Coso partnership fails to obtain, renew or maintain any required permit or
governmental approval or is unable to satisfy any conditions, its operations
could be limited or suspended.
In addition, you can expect that the laws and regulations affecting the Coso
projects, the Coso partnerships and us will change while the Series B notes are
outstanding, and those changes could adversely affect the Coso projects, the
Coso partnerships and us. For example, changes in laws or regulations
(including, but not limited to, taxes and environmental laws) could impose more
stringent or comprehensive requirements on the operation or maintenance of the
Coso projects, resulting in increased compliance costs, the need for additional
capital expenditures or the reduction of certain benefits currently available
to the Coso projects, or could expose the Coso partnerships or us or both to
liabilities for previous actions taken in compliance with laws in effect at the
time or for actions taken by or conditions caused by third parties. In
addition, the Coso partnerships could become liable for the investigation and
removal of hazardous materials that may be found at the Coso projects, no
matter what the source of such hazardous materials. Failure to comply with any
such statutes or regulations or any change in the requirements of such statutes
or regulations could result in civil or criminal liability, imposition of
cleanup liens and fines and large expenditures to bring the Coso projects into
compliance. You should read "Business--Environmental Matters" for more
information regarding environmental requirements.
Qualifying Facility Status
PURPA provides QFs, such as the Coso projects, with certain exemptions from
federal and state law and regulation, including regulation of the rates at
which electricity can be sold. If:
. any Coso project fails to maintain its QF status,
. PURPA is repealed or amendments to PURPA are enacted that substantially
reduce the benefits currently afforded QFs, or
. the requirements for the Coso projects to maintain their status as QFs
are made more burdensome,
then, operations at the Coso projects or compliance with the terms of the power
purchase agreements could be made much more difficult. The Coso partnerships'
ability to make payments under their project notes and guarantees and our
ability to make payments to you under the Series B notes when due may be
materially and adversely affected by any of these events.
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Changes in California Electric Market
The electric industry in California has changed dramatically as a result of
recent decisions by the California Public Utilities Commission and the
enactment of AB1890 in September 1996. The new California electric market
structure, including the independent system operator/power exchange system,
which we call the ISO PX system, began operations on March 31, 1998. The
California Power Exchange portion of the ISO PX system, through which Edison is
required to sell power generated by QFs, is responsible for managing the
transactions for all power auctioned through, and purchased by, market
participants except those bound by contract. The ISO portion of the ISO PX
system is responsible for scheduling, transmission access and operation of the
transmission assets formerly operated by Edison, San Diego Gas & Electric
Company and Pacific Gas & Electric Company. The complex grid operation,
software, forecasting, bidding and market clearing mechanism of the ISO PX
system has a limited operating history. Many elements of the new market
structure present novel regulatory issues that have not yet been resolved, as
well as many practical issues of implementation such as the development of
systems, software and procedures for the California Power Exchange, the ISO and
all of the market participants who will transact with the ISO PX system.
If the still-developing ISO PX system fails or does not operate as
anticipated, electricity generation, transmission and distribution in
California may be materially and adversely affected. Edison's business may also
be materially and adversely affected. Furthermore, since Edison's avoided cost
of energy ultimately will be tied to the clearing price of the California Power
Exchange, the ISO PX system's functionality will have a significant effect on
the Coso partnerships.
When the California Power Exchange began operations on March 31, 1998, the
only available clearing mechanism was for day-ahead bidding. In August 1998,
the California Power Exchange began hour-ahead trading. The limited operating
history of the ISO PX system makes it impossible to predict how the markets or
transmission systems will perform over time with any certainty. During the
summers of 1998 and 1999, spot prices "spiked" in several recently deregulated
markets, including those in California and Illinois, creating short-term
situations in which certain market participants asserted that the markets had
"failed." Both FERC and the California Public Utilities Commission are
reviewing pricing policies and market mechanisms in light of these experiences,
and FERC has authorized the ISO to implement, on an interim basis, price caps
for ancillary transmission services that it procures from generating units.
In addition, a number of substantial issues remain undecided in California
that will require ongoing regulatory involvement by FERC and the California
Public Utilities Commission. One of these issues is the final mechanism for
local reliability contracts and pricing for ancillary services from so-called
"reliability must-run" plants, which are required to operate at certain times
and provide certain services to maintain transmission system reliability. The
Coso projects have not been designated as "reliability must-run" plants.
Furthermore, as part of the California restructuring legislation,
California's investor-owned utilities were permitted to recover certain
authorized transition costs, primarily related to above-market costs associated
with nuclear generation assets and with long-term power purchases, including
from QFs such as the Coso projects, that are currently included in the rates
paid by ratepayers, which we call stranded costs. One of these investor-owned
utilities, San Diego Gas & Electric Company, has recently announced its
intention to eliminate the majority of the charges for stranded costs. These
continuing issues, along with ongoing monitoring by FERC and the California
Public Utilities Commission of the markets and the ISO PX system, leave the
deregulated market subject to potential
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regulatory action and revisions, with concomitant consequences both to Edison
and to the payments received from Edison by the Coso partnerships under their
power purchase agreements. For more information, you should read "--Future
energy payments paid by Edison to the Coso partnerships will most likely be
less than historical energy payments because they will be paid based on
Edison's avoided cost of energy" and "Regulation."
In addition to actions taken by the California Legislature and regulation by
the California Public Utilities Commission, bills have been introduced into the
United States Congress mandating the deregulation of the electric utility
industry on the state level. On April 16, 1999, the Clinton Administration's
latest restructuring plan was introduced. In general, the bills provide for
open competition in the furnishing of electricity to all customers. No one can
predict whether these bills, or any future legislation relating to the
deregulation of the electric industry, will become law or, if they become law,
what their final effect will be. Changes in the existing legal structure
regulating the electric utility industry, particularly in California, will most
likely have an impact on the manner in which electricity is distributed and
payments are collected or on Edison and its business. This may affect Edison's
ability to fulfill its obligations to the Coso partnerships under the power
purchase agreements. For more information, you should read "--Our ability to
repay the Series B notes will depend on unrelated third parties fulfilling
their commitments to the Coso partnerships" and "Regulation--Energy
Regulation--California Deregulation."
Although the Coso partnerships currently maintain insurance, loss proceeds
might not be enough to satisfy our obligations under the Series B notes.
The Coso partnerships currently maintain property, business interruption,
earthquake, catastrophic and general liability insurance for the Coso projects.
If an insurable loss occurs, the proceeds of insurance will be paid to the
Depositary for the Coso partnerships' account and will be applied as required
under the Indenture and the Depositary Agreement. No one can give you any
assurance that this insurance coverage will be available in the future at
commercially reasonable costs or terms or that the amounts for which the Coso
projects are or will be insured will cover all potential losses.
As part of the Series A notes offering, the Coso partnerships obtained title
insurance policies in the aggregate amount of $200.0 million in favor of U.S.
Bank Trust National Association, which we call the Trustee. Primarily because
of the nature of the rights obtained by one or more of the Coso partnerships
from the Navy and the Bureau of Land Management, the insurance coverage
afforded by these policies is narrower, and the exceptions to coverage are
broader, than those which are commonly provided to companies that are engaged
in activities similar to those of the Coso partnerships. No one can assure you
that the title insurer or its reinsurers will be willing or able to satisfy any
claims which may be made under those policies. Also, the coverage amounts under
these policies may not be sufficient to satisfy amounts outstanding under the
senior secured notes at any given time. See "Business--Insurance."
Geothermally active areas, such as the area in which the Coso projects are
located, are subject to frequent low-level seismic disturbances. Serious
seismic disturbances in that area are possible. The Coso partnerships currently
have business interruption and property damage insurance to address certain
losses which may be caused by these disturbances. This insurance coverage
currently includes $200.0 million of earthquake insurance. This amount of
insurance coverage is substantially less than the aggregate principal amount of
the senior secured notes, and no one can assure you that seismic disturbances
of a nature and magnitude so as to cause material damage to Navy I, BLM or Navy
II,
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the transmission lines, wells, gathering system or other related facilities, or
a material change in the nature of the geothermal resource, will not occur.
Also, no one can assure you that insurance proceeds will be adequate to cover
all losses sustained, or that insurance will continue to be available in the
future in the amounts presently carried or other amounts adequate to insure
against losses from seismic disturbances.
The Trustee's ability to foreclose on the Coso partnerships' assets depends on
it being able to obtain the consents of third parties who do not have to
consent and it being able to obtain new permits and governmental approvals.
Certain assets comprising the collateral securing the senior secured notes
require the consent of third parties as a condition to their transfer or
utilization upon or following a foreclosure. Since the Coso projects are
located on Navy and Bureau of Land Management property, this would include
their consents as well. No one can give you any assurance that these third
parties will give their consents or cooperation when asked to facilitate a
transfer of assets or operating rights to the Trustee or any other person upon
or following a foreclosure. Accordingly, although the Coso partnerships'
obligations under their guarantees are secured by a pledge of all of their
ownership interests in the Coso partnerships and liens on all of the material
rights and assets of the Coso partnerships, the Trustee may not have the
ability to foreclose upon all of these pledges and liens without these consents
or, following a foreclosure, to operate or utilize such assets. Further, no one
can assure you that the Navy or the Bureau of Land Management will permit a
receiver to take control of or operate such assets pending foreclosure.
Some of the permits and governmental approvals that serve as collateral for
the senior secured notes are not transferable. In the event of a foreclosure,
the acquiror of the Coso projects would have to apply for new permits and
governmental approvals in order to continue the operations at the Coso
projects. Any delays or inability in obtaining such new permits or appeals
could reduce the proceeds available to the holders of senior secured notes in
the event of a foreclosure.
In addition, contract rights under certain project documents serve as
collateral for the senior secured notes, including rights that stem from
agreements to which the Coso partnerships are parties. If a bankruptcy case
were commenced by or against a Coso partnership, all or part of the project
documents could possibly be rejected by that Coso partnership or a trustee
appointed in a bankruptcy case pursuant to section 365 and section 1123 of the
federal bankruptcy code and, therefore, not be specifically enforceable.
The Coso projects are being managed by new managing partners and operators.
Prior to Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects on February 25, 1999, CalEnergy owned and controlled the
managing partners of the Coso partnerships and operated the Coso projects. As a
result, CalEnergy made most of the day-to-day business decisions relating to
the management and the operations of the Coso projects. Since Caithness
Acquisition purchased CalEnergy's interests in the Coso projects, Caithness
Energy has indirectly owned and controlled the managing partners of the Coso
partnerships, and FPL Operating and Coso Operating Company have been operating
the Coso projects under their respective O&M agreements.
If Caithness Acquisition purchases ESI Geothermal's indirect ownership
interests in the Navy I partnership and FPL Operating assigns all of its rights
under its O&M agreements to Coso Operating Company, Coso Operating Company will
assume FPL Operating's duties and obligations under FPL
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Operating's O&M agreements and become the sole operator of the plants and
fields at the Coso projects. In addition, Caithness Acquisition will control
the management and operations of the Coso projects. FPL Operating is an
experienced geothermal facility operator and has more experience than Coso
Operating Company as an operator of independent power projects. See "Business--
Operations and Maintenance." In addition, Coso Operating Company may or may not
employ the same operations and maintenance practices currently employed by FPL
Operating at the Coso projects. You should be aware of these matters when you
read this prospectus and, in particular, the conclusions of the independent
engineer in its report attached as Exhibit A to this prospectus. In preparing
that report, the independent engineer reviewed the Coso projects based in large
part on FPL Operating's operational control. Also, as we indicated above, the
independent engineer's report, as well as the other two consultants' reports,
have not been updated since they were issued in connection with the Series A
notes offering. If the Coso projects are not managed or operated effectively by
Caithness Acquisition and its affiliates, the financial health of the Coso
partnerships could be materially and adversely affected. You should read "--Our
ability to repay the Series B notes will depend on unrelated third parties
fulfilling their commitments to the Coso partnerships," "Prospectus Summary--
Recent Developments--Purchase of FPL Interests; Assignment of FPL O&M
Agreements" and "Management" for certain related information.
Our estimates, projections and assumptions could prove to be incorrect.
In connection with the issuance of the Series A notes, we prepared certain
estimates, projections and assumptions for the revenue generation capacity of
the Coso partnerships and the associated costs, and provided them to Sandwell
Engineering Inc. and GeothermEx, Inc. Sandwell Engineering Inc. evaluated the
reasonableness of these projections in light of the technical operating
parameters of the Coso projects, the operations and maintenance budgets of the
Coso projects and the related assumptions and forecasts contained therein.
GeothermEx, Inc. evaluated the reasonableness of these projections with respect
to the wellfield capital expenditures and production levels. These evaluations
were based upon an inspection and review of certain technical, environmental,
economic and regulatory aspects at the Coso projects. These projections
incorporated energy payments and AB1890 subsidy payments which were based on
the energy markets consultant's report. Sandwell Engineering Inc.'s report
attached as Exhibit A to this prospectus and GeothermEx, Inc.'s report attached
as Exhibit C to this prospectus contain some discussion of the assumptions and
forecasts used in preparing the projections, which concern the operations and
maintenance budgets of the Coso projects. We urge you to read these reports and
the energy markets consultant's report attached as Exhibit B to this prospectus
but, when you read the independent engineer's report, you should be aware that
FPL Operating will no longer act as an operator of the Coso projects if the
closing of Caithness Acquisition's purchase of ESI Geothermal's ownership
interests in the Navy I partnership is completed. See "Prospectus Summary--
Recent Developments--Purchase of FPL Interests; Assignment of FPL O&M
Agreements." You should also be aware that the three consultant's reports were
prepared in connection with the Series A notes offering and have not been
updated since then.
For purposes of preparing the projections, we made certain assumptions about
general business and economic conditions, such as real property and sales taxes
payable by the Coso partnerships and other persons, and about numerous other
material contingencies and matters that are not within our control or the
control of any other person and the outcome of which cannot be predicted by us
or any other person with any expectation of complete accuracy. We also made
assumptions concerning operations and maintenance costs under the applicable
O&M agreements. You should be aware that assumptions are inherently subject to
significant uncertainties, and actual results will differ, perhaps materially,
from those projected. Accordingly, the projections are not necessarily
indicative of future performance, and neither we nor the Coso partnerships
assume any responsibility for the accuracy of the projections. If, for example,
sales of revenues generated by the Coso projects from sales of electricity to
Edison decline below those assumed in the projections contained in the
independent
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engineer's report, this could impair the Coso partnerships' ability to make
payments under their project notes and guarantees and our ability to make
payments of principal, premium, if any, and interest on the Series B notes when
due.
We do not make, or intend to make, any representation or warranty, nor should
any representation be inferred, about the likely existence of any particular
future set of facts or circumstances, and you should not place undue reliance
on the projections, the independent engineer's report, the energy markets
consultant's report or the geothermal engineer's report. If actual results are
less favorable than those shown or if the estimates and assumptions used in
formulating the projections prove to be incorrect, each Coso partnership's
financial performance may be less favorable than that set forth in the
projections. As a consequence, the Coso partnerships' ability to make payments
under their project notes and guarantees, and our ability to make payments of
principal, premium, if any, and interest on the Series B notes when due could
be materially and adversely affected.
We prepared the projections contained in the independent engineer's report
based on our knowledge at the time of the Series A notes offering and on
certain assumptions we made. The projections have not been examined, compiled
or subjected to any procedures by either KPMG LLP or by PricewaterhouseCoopers
LLP. Accordingly, neither KPMG LLP nor PricewaterhouseCoopers LLP expresses any
opinion or other form of assurance with respect thereto. The
PricewaterhouseCoopers LLP reports included in this prospectus relate solely to
the Coso partnerships' historical financial information. The KPMG LLP report
included in this prospectus relates to an historical balance sheet as of April
22, 1999 (date of inception). Those reports do not extend to the projections
contained in the independent engineer's report and the geothermal engineer's
report and should not be read to do so. Neither we, Sandwell Engineering Inc.
nor GeothermEx, Inc. intend to provide to the holders of the senior secured
notes any projections or to evaluate any projections other than the projections
set forth in the independent engineer's report and the geothermal engineer's
report.
The Coso partnerships could be materially adversely affected by unanticipated
Year 2000 compliance problems.
At the end of 1999, the operations of the Coso partnerships' computer systems
could be disrupted because these systems might interpret the Year 2000 as
"1900", which could result in system failures or miscalculations. This could
cause disruptions of operations at the Coso projects and at Edison, the Coso
partnerships' sole customer. No one can assure you that the Coso partnerships
will not experience material disruptions in their operations as a result of
Year 2000 non-compliance.
The Coso partnerships depend substantially for their operating revenues on
Edison's purchase of all electrical energy generated by the plants. If Edison
fails to fulfill its contractual obligations under the power purchase
agreements because it has failed to resolve its own Year 2000 issues, it could
have a material adverse effect on the Coso partnerships' revenues and ability
to make payments on the senior secured notes and guarantees. The Coso
partnerships have contacted Edison. Edison indicated that its Year 2000 program
will be completed by December 31, 1999. Further, Edison has reported in its
1998 annual report that its informational and operational systems have been
assessed, and detailed plans have been developed to address modifications
required to be completed, tested and operational by December 31, 1999. The Coso
partnerships will continue to work with Edison in an effort to minimize any
potential Year 2000 compliance impact. However, it is not possible to
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guarantee Edison's compliance. Edison and other third parties might fail to
resolve timely their own Year 2000 issues, or might experience delays or
changes in the estimated time it takes to fix these problems. If Edison fails
to fulfill its contractual obligations under the power purchase agreements
because it failed to resolve its own Year 2000 issues, it could have a material
adverse effect on the Coso partnerships' revenues and their ability to make
payments under their project notes and guarantees. While the Coso partnerships
intend to continue to work with Edison and other third parties to minimize any
potential Year 2000 problems, no one can assure you that these issues will be
resolved to the Coso partnerships' satisfaction or that the Coso partnerships
will not experience a material adverse effect to their operations from
unanticipated Year 2000 issues or problems, including failure to resolve Year
2000 issues in a timely manner, or delays or changes in the estimated time of
their compliance. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Year 2000 Issue."
We may not have the funds necessary to finance a change of control offer which
may be required under the Indenture.
If certain specific kinds of change of control events occur, we will be
required under the Indenture to offer to repurchase all outstanding senior
secured notes. No one can assure you that we will have sufficient funds at the
time of a change of control to be able to make the required repurchases of the
senior secured notes, or that restrictions contained in documents governing our
other indebtedness will allow those repurchases. You should note that certain
important corporate events, such as leveraged recapitalizations that would
increase the level of our indebtedness, would not constitute a change of
control under the Indenture. See "Description of Series B Notes-- Repurchase at
the Option of Holders upon a Change of Control."
Federal and state statutes allow courts, under specific circumstances, to void
guarantees and require noteholders to return payments received from guarantors.
One or more Coso partnerships' guarantees could be voided under federal
bankruptcy law and comparable provisions of state law if the guarantees are
deemed to involve a fraudulent conveyance. Under the federal bankruptcy law and
comparable provisions of state fraudulent transfer laws, a guarantee could be
voided, or claims in respect of a guarantee could be subordinated to all other
debts of that guarantor, if, among other things, the guarantor, at the time it
incurred the indebtedness evidenced by its guarantee:
. received less than reasonably equivalent value or fair consideration for
the incurrence of such guarantee and either:
. one, was insolvent or rendered insolvent by reason of such
incurrence; or
. two, was engaged in a business or transaction for which the
guarantor's remaining assets constituted unreasonably small capital;
or
. three, intended to incur, or believed that it would incur, debts
beyond its ability to pay such debts as they mature.
In addition, any payment by that guarantor pursuant to its guarantee could be
voided and required to be returned to the guarantor, or to a fund for the
benefit of the creditors of the guarantor.
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The measures of insolvency for purposes of these fraudulent transfer laws
will vary depending upon the law applied in any proceeding to determine whether
a fraudulent transfer has occurred. Generally, however, a guarantor would be
considered insolvent if:
. the sum of its debts, including contingent liabilities, was greater than
the fair saleable value of all of its assets; or
. if the present fair saleable value of its assets was less than the amount
that would be required to pay its probable liability on its existing
debts, including contingent liabilities, as they become absolute and
mature; or
. it could not pay its debts as they become due.
If one or more Coso partnerships' guarantees were voided, you may be required
to return payments made by the Coso partnerships to you under the guarantees.
There is no established market for the Series B notes and they will not be
listed on any securities exchange.
The Series A notes are eligible for trading in the PORTAL market. The Series
B notes are a new issue of securities with no established trading market and
will not be listed on any securities exchange. The initial purchaser of the
Series A notes has informed us that it intends to make a market in the Series B
notes. However, it may discontinue making a market at any time without notice.
The liquidity of any market for the Series B notes will depend upon the
number of holders of the Series B notes, our performance, the market for
similar securities, the interest of securities dealers in making a market in
the Series B notes and other factors. A liquid trading market may not develop
for the Series B notes.
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THE EXCHANGE OFFER
Purpose of the Exchange Offer
The exchange offer is designed to provide holders of Series A notes with
an opportunity to acquire Series B notes. Unlike the Series A notes, the Series
B notes will be freely tradable at all times, subject to any restrictions on
transfer imposed by state securities or "blue sky" laws, provided that the
holder is not our "affiliate" within the meaning of the Securities Act and
represents that the Series B notes are being acquired in the ordinary course of
the holder's business and the holder is not engaged in, and does not intend to
engage in, a distribution of the Series B notes. The outstanding Series A notes
in the aggregate principal amount of $413.0 million were originally issued and
sold on May 28, 1999 to the initial purchaser. The sale of the Series A notes
to the initial purchaser was not registered under the Securities Act in
reliance upon the exemption provided by Section 4(2) of the Securities Act. The
concurrent resale of the Series A notes to investors was not registered under
the Securities Act in reliance upon the exemption provided by Rule 144A of the
Securities Act. The Series A notes may not be reoffered, resold or transferred
other than pursuant to a registration statement filed under the Securities Act
or unless an exemption from the registration requirements of the Securities Act
is available. Pursuant to Rule 144, Series A notes may generally be resold:
. commencing one year after their original issue date, in an amount up
to, for any three-month period, the greater of 1% of the Series A
notes then outstanding or the average weekly trading volume of the
Series A notes during the four calendar weeks immediately preceding
the filing of the required notice of sale with the commission; or
. commencing two years after the original issue date, in any amount and
otherwise without restriction by a holder who is not, and has not
been for the preceding 90 days, our affiliate.
The Series A notes are eligible for trading in the PORTAL market, and may
be resold to certain qualified institutional buyers pursuant to Rule 144A.
Other exemptions may also be available under other provisions of the federal
securities laws for the resale of the Series A notes.
At the closing of the Series A notes offering, we entered into a
registration rights agreement pursuant under which we agreed to file with the
commission a registration statement covering the exchange of the Series B notes
for the Series A notes. The registration rights agreement provides that:
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will file a registration statement with the SEC
no later than 90 days after the closing date of the Series A notes
offering,
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will use our best efforts to have the
registration statement declared effective by the SEC no later than
180 days after the closing date of the Series A notes offering,
. unless the exchange offer would not be permitted by applicable law or
commission policy, we will commence the exchange offer no later than
30 business days after the date that the exchange offer registration
statement becomes effective, and
. if obligated to file a shelf registration statement covering the
Series B notes, we will use our best efforts to file the shelf
registration statement with the commission no later than 45 days
after such filing obligation arises and use our best efforts to cause
the shelf registration statement to be declared effective by the
commission on or prior to 90 days after the date we are required to
file the shelf registration statement.
50
<PAGE>
We will pay liquidated damages to each holder of transfer restricted
notes, as described below, if any of the following occurs:
. we fail to file any of the registration statements required by the
registration rights agreement on or before the date specified for
such filing,
. the commission does not declare any of the registration statements
effective on or prior to the date specified for effectiveness,
. we fail to consummate this exchange offer within 30 business days
after the date on which the registration statement covering the
exchange of notes for Series A notes is first declared effective, or
. any registration statement filed by us pursuant to the terms of the
registration rights agreement is declared effective but thereafter,
subject to limited exceptions, it ceases to be effective or usable in
connection with resales of transfer restricted notes without being
succeeded immediately by a post-effective amendment that cures such
failure.
We will pay liquidated damages to each holder of transfer restricted
notes, with respect to the first 90-day period immediately following the
occurrence of the first such default in an amount equal to $.05 per week per
$1,000 principal amount of Series A notes. The amount of liquidated damages
will increase by an additional $.05 per week per $1,000 principal amount of
Series A notes with respect to each subsequent 90-day period, or portion
thereof, until all defaults have been cured, up to a maximum amount of
liquidated damages for all defaults of $.25 per week per $1,000 principal
amount of Series A notes. "Transfer restricted notes" means each Series A note
until the earliest to occur of:
. the date on which such Series A note has been exchanged by a person
other than a broker-dealer for a Series B note in the exchange offer,
. following the exchange by a restricted broker-dealer in the offering
of a Series B note for a Series A note, the date on which the Series
B note is sold to a purchaser who receives from such restricted
broker-dealer on or prior to the date of said sale, a copy of this
prospectus,
. the date on which the Series A note has been effectively registered
under the Securities Act and disposed of in accordance with the shelf
registration statement, or
. the date on which the Series A note is distributed to the public
pursuant to Rule 144(k) under the Securities Act.
Terms of the Exchange Offer
Upon the terms and subject to the conditions set forth in this prospectus
and in the accompanying letter of transmittal, we will exchange $1,000
principal amount of Series B notes due 2001 for each $1,000 principal amount of
our outstanding Series A notes due 2001, and $1,000 principal amount of Series
B notes due 2009 for each $1,000 principal amount of Series B notes due
2009. Only Series B notes due 2001 may be exchanged for tendered Series A notes
due 2001, and only Series B notes due 2009 may be exchanged for tendered Series
A notes due 2009. Series B notes will be issued only in integral multiplies of
$1,000 to each tendering holder of Series A notes whose Series A notes are
accepted in this exchange offer.
51
<PAGE>
The Series B notes will bear interest from and including the original
issue date of the Series A notes. Accordingly, if you receive Series B notes in
exchange for your tendered Series A notes, you will forego accrued but unpaid
interest on your exchanged Series A notes for the period from and including the
issue date of the Series A notes to the date of their exchange for Series B
notes, but will be entitled to such interest under the Series B notes.
As of the date of this prospectus, $110.0 million aggregate principal
amount of Series A notes due 2001 were outstanding and $303.0 million aggregate
principal amount of Series A notes due 2009 were outstanding. This prospectus
and the letter of transmittal are being sent to all registered holders of
Series A notes as of that date. You will not be required to pay brokerage
commissions or fees or, subject to the instructions in the letter of
transmittal, transfer taxes with respect to your exchange of Series A notes
pursuant to this exchange offer. We will pay all charges and expenses, other
than specific transfer taxes that may be imposed, in connection with this
exchange offer. See "--Payment of Expenses" below.
As a holder of Series A notes, you do not have any appraisal or
dissenters' rights under the Delaware General Corporation Law in connection
with this exchange offer.
Expiration Date; Extensions; Termination
This exchange offer will expire at 5:00 P.M., New York City time, on
Monday, November 8, 1999 subject to our extension by notice to U.S. Bank Trust
National Association, N.A., the exchange agent. We reserve the right to extend
this exchange offer in our discretion, in which event the expiration date will
be the time and date on which this exchange offer as so extended shall expire.
We will notify the exchange agent of any extension by oral or written notice
and will mail to you an announcement of any extension, each prior to 9:00 A.M.,
New York City time, on the next business day after the previously scheduled
expiration date.
We reserve the right to extend or terminate this exchange offer and not
accept for exchange any Series A notes if any of the events set forth below
under "--Conditions to the Exchange Offer" occur and are not waived by us, by
giving oral or written notice of such delay or termination to the exchange
agent. See "--Conditions to the Exchange Offer." The rights we reserve in this
paragraph are in addition to our rights set forth below under the caption "--
Conditions to the Exchange Offer."
Procedures for Tendering
Your tender of Series A notes pursuant to one of the procedures set forth
below and our acceptance will constitute an agreement between you and us in
accordance with the terms and subject to the conditions set forth in this
prospectus and in the letter of transmittal.
Except as set forth below, if you wish to tender your Series A notes for
exchange pursuant to this exchange offer, you must transmit a properly
completed and duly signed letter of transmittal, and all other documents
required by the letter of transmittal, to the exchange agent at the address set
forth below under "--Exchange Agent" on or prior to the expiration date. In
addition, for a valid exchange to take place, one of the following must occur:
. certificates for your Series A notes must be received by the exchange
agent along with the letter of transmittal;
52
<PAGE>
. a timely confirmation of a book-entry transfer of such Series A
notes, if such procedure is available, into the exchange agent's
account at DTC pursuant to the book-entry transfer procedures
described under "--Book Entry Transfer" below, must be received by
the exchange agent prior to the expiration date; or
. you must comply with the guaranteed delivery procedures described
below.
Letters of transmittal and Series A notes should not be sent to us. We
are not asking you for a proxy and you are requested not to send us a proxy.
Your method of delivery of Series A notes, the letter of transmittal and
the other documents to the exchange agent is at your election and risk. If
delivery is by mail, we suggest that registered mail, properly insured, with
return receipt requested, be used. In all cases, sufficient time should be
allowed to assume timely delivery to the exchange agent before the expiration
date.
Signatures on a letter of transmittal or a notice of withdrawal, as the
case may be, must be guaranteed unless the Series A notes tendered according to
the letter of transmittal are tendered:
. by a registered holder of Series A notes who has not completed the
box entitled "Special Issuance and Delivery Instructions" on the
letter of transmittal, or
. for the account of any firm that is a member of a registered national
securities exchange or a member of the National Association of
Securities Dealers, Inc. or a commercial bank or trust company having
an office in the United States, sometimes referred to as an eligible
institution.
If signatures on a letter of transmittal or a notice of withdrawal, as the case
may be, are required to be guaranteed, the guarantee must be by an eligible
institution.
If the letter of transmittal is signed by a person other than a
registered holder of any Series A note tendered with the letter of transmittal,
such Series A note must be endorsed or accompanied by appropriate bond powers,
in either case signed exactly as the name or names of the registered holder or
holders appear on the Series A note.
If the letter of transmittal or any Series A notes or bond powers are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, such persons should so indicate when signing, and, unless waived by
us, you must submit proper evidence satisfactory of their authority to so act.
We will resolve all questions as to the validity, form, eligibility,
including time of receipt, and acceptance of tendered Series A notes. Our
determination will be final and binding. We reserve the absolute right to
reject any or all tenders that are not in proper form or the acceptance of
which would, in the opinion of our counsel be unlawful. We also reserve the
right to waive any irregularities or conditions of tender as to particular
Series A notes. Our interpretation of the terms and conditions of this exchange
offer, including the instructions in the letter of transmittal, will be
final and binding. Unless waived, any irregularities in connection with tenders
must be cured within such time as we determine. Neither the exchange agent nor
we are under any duty to give notification of defects in such tenders or shall
incur liabilities for failure to give such notification. Tenders of Series A
notes will not be deemed to have been made until such irregularities have been
cured or waived. Any Series A notes received by the exchange agent that are not
properly tendered and as to which the irregularities have not been cured or
waived will be returned by the exchange agent to the tendering holder, unless
otherwise provided in the letter of transmittal, as soon as practicable
following the expiration date.
53
<PAGE>
Upon satisfaction or waiver of all of the conditions to the exchange
offer, we will accept, promptly after the expiration date, all Series A notes
properly tendered and will issue the Series B notes promptly after acceptance
of the Series A notes. See "Conditions to the Exchange Offer" below. For the
purposes of the exchange offer, we will be deemed to have accepted properly
tendered Series A notes for exchange when, as and if we have given oral or
written notice thereof to the exchange agent.
Our acceptance for exchange of Series A notes tendered pursuant to this
exchange offer will constitute a binding agreement between the tendering person
and us upon the terms and subject to the conditions of this exchange offer.
Book-Entry Transfer
The exchange agent will make a request to establish an account with
respect to the Series A notes at DTC for purposes of this exchange offer
promptly after the date of effectiveness of the registration statement of which
this prospectus forms a part. Any financial institution that is a participant
in DTC's systems may make book-entry delivery of Series A notes by causing DTC
to transfer the Series A notes into the exchange agent's account at DTC in
accordance with DTC's procedures for transfer. However, the exchange for the
Series A notes so tendered will only be made after timely confirmation of the
book-entry transfer of Series A notes into the exchange agent's account, and
timely receipt by the exchange agent of an agent's message and any other
documents required by the letter of transmittal. The term "agent's message"
means a message, transmitted by DTC and received by the exchange agent and
forming a part of a book-entry confirmation, which states that DTC has received
an express acknowledgment from a participant tendering Series A notes that are
the subject of such book-entry confirmation that the participant has received
and agrees to be bound by the terms of the letter of transmittal, and that we
may enforce such agreement against the participant. Although delivery of Series
A notes may be effected through book-entry transfer at DTC, the letter of
transmittal (or facsimile thereof), properly completed and duly executed, with
any required signature guarantees and any other required documents must, in any
case, be transmitted to and received by the exchange agent at one of the
addresses set forth below under "-- Exchange Agent" on or prior to the
expiration date, unless an agent's message is transmitted on or prior to the
expiration date in lieu thereof, or the guaranteed delivery procedures
described below must be complied with.
Guaranteed Delivery Procedures
If you are a registered holder of Series A notes and you wish to tender
your Series A notes but your Series A notes are not immediately available, or
you cannot deliver your Series A notes, the letter of transmittal and the other
required documents to the exchange agent prior to the expiration date, or the
procedure for book-entry transfer cannot be completed on a timely basis, you
may effect a tender if:
. your tender is made through an eligible institution;
. prior to the expiration date, the exchange agent receives from the
eligible institution a properly completed and duly executed letter of
transmittal (or a facsimile thereof) and notice of guaranteed
delivery, substantially in the form provided by us, by facsimile
transmission, mail or hand delivery, stating: (1) your name and
address, (2) the certificate number or numbers of your tendered
Series A notes, (3) the principal amount of your Series A notes
tendered, and (4) that the tender is being made through the delivery
and guaranteeing that, within three New York Stock Exchange trading
days after the expiration date, the letter of transmittal or
facsimile thereof together with the
54
<PAGE>
certificate(s) representing the Series A notes, or a book-entry
confirmation, as the case may be, and any other documents required by
the letter of transmittal, will be deposited by the eligible
institution with the exchange agent; and
. such properly completed and executed letter of transmittal or
facsimile thereof, as well as the certificate(s) representing all
your tendered Series A notes, in proper form for transfer, or a book-
entry confirmation, as the case may be, and all other documents
required by the letter of transmittal, are received by the exchange
agent within three New York Stock Exchange trading days after the
expiration date.
Upon request of the exchange agent, a notice of guaranteed delivery will
be sent to you if you wish to tender your Series A notes according to the
guaranteed delivery procedures set forth above.
Conditions to the Exchange Offer
Regardless of any other provisions of this exchange offer, or any
extension of this exchange offer, we will not be required to issue Series B
notes in respect of any properly tendered Series A notes not previously
accepted, and may terminate this exchange offer by oral or written notice to
the exchange agent and the holders, or at our option, modify or otherwise
amend this exchange offer, if any material change occurs that is likely to
affect this exchange offer, including, but not limited to, the following:
. there shall be instituted or threatened any action or proceeding
before any court or governmental agency challenging this exchange
offer or otherwise directly or indirectly relating to this exchange
offer or otherwise affecting us;
. there shall occur any development in any pending action or proceeding
that, in our sole judgment, would or might have an adverse effect on
our business, prohibit, restrict or delay consummation of this
exchange offer, or impair the contemplated benefits of this exchange
offer;
. any statute, rule or regulation shall have been proposed or enacted,
or any action shall have been taken by any governmental authority
which, in our sole judgment, would or might have an adverse effect on
our business, prohibit, restrict or delay consummation of this offer,
or impair the contemplated benefits of this exchange offer; or
. there exists, in our sole judgment, any actual or threatened legal
impediment including a default or prospective default under an
agreement, indenture or other instrument or obligation to which we
are a party or by which we are bound to the consummation of the
transactions contemplated by this exchange offer.
We expressly reserve the right to terminate this exchange offer and not
accept for exchange any Series A notes upon the occurrence of any of the
foregoing conditions. In addition, we may amend this exchange offer at any
time prior to 5:00 P.M., New York City time, on the expiration date if any of
the conditions set forth above occur. Moreover, regardless of whether any of
such conditions has occurred, we may amend the exchange offer in any manner
which, in our good faith judgment, is advantageous to you.
The foregoing conditions are for our sole benefit and may be waived by
us, in whole or in part, in our sole discretion. Any determination we make
concerning an event, development or circumstance described or referred to
above will be final and binding on all parties.
55
<PAGE>
Acceptance of Series A Notes for Exchange; Delivery of Series B Notes
Upon the terms and subject to the conditions of this exchange offer, we
will accept all Series A notes validly tendered prior to 5:00 P.M., New York
City time, on the expiration date. We will deliver Series B notes in exchange
for Series A notes promptly following the expiration date.
For purposes of this exchange offer, we shall be deemed to have accepted
validly tendered Series A notes when, as and if we have given oral or written
notice of the exchange to the exchange agent. The exchange agent will act as
agent for the tendering holders for the purpose of receiving the Series A
notes. Under no circumstances will interest be paid by us or the exchange
agent by reason of any delay in making such payment or delivery.
If any tendered Series A notes are not accepted for exchange because of
an invalid tender, the occurrence of specific other events set forth herein or
otherwise, any such unaccepted Series A notes will be returned, at our
expense, to you as promptly as practicable after the expiration or termination
of this exchange offer.
Withdrawal Rights
Your tenders of Series A notes may be withdrawn at any time prior to the
expiration date.
For a withdrawal to be effective, a written notice of withdrawal must be
received by the exchange agent at the address set forth below under "--
Exchange Agent." Any notice of withdrawal must specify the name of the person
having tendered the Series A notes to be withdrawn, identify the Series A
notes to be withdrawn, including the principal amount of such Series A notes,
and, where certificates for Series A notes have been transmitted, specify the
name in which such Series A notes are registered, if different from that of
the withdrawing holder. If certificates for Series A notes have been delivered
or otherwise identified to the exchange agent, then, prior to the release of
such certificates, the withdrawing holder must also submit the serial numbers
of the particular certificates to be withdrawn and a signed notice of
withdrawal with signatures guaranteed by an eligible institution unless such
holder is an eligible institution. If Series A notes have been tendered
pursuant to the procedure for book-entry transfer described above, any notice
of withdrawal must specify the name and number of the account at DTC to be
credited with the withdrawn Series A notes and otherwise comply with the
procedures of such facility. We will determine all questions as to the
validity, form and eligibility, including time of receipt, of such notices.
Our determination shall be final and binding on all parties.
Any Series A notes so withdrawn will be deemed not to have been validly
tendered for exchange for purposes of this exchange offer. Any Series A notes
that have been tendered for exchange but which are not exchanged for any
reason will be returned to the holder thereof without cost to such holder, or,
in the case of Series A notes tendered by book-entry transfer into the
exchange agent's account at DTC pursuant to the book-entry transfer procedures
described above, such Series A notes will be credited to an account maintained
with DTC for the Series A notes, as soon as practicable after withdrawal,
rejection of tender or termination of the exchange offer. Properly withdrawn
Series A notes may be retendered by following one of the procedures described
under "--Procedures for Tendering" above at any time on or prior to the
expiration date.
Material Federal Income Tax Consequences of the Exchange Offer
The following discussion summarizes the material federal income tax
consequences of this exchange offer. This discussion is not binding on the
Internal Revenue Service or the courts, and we
56
<PAGE>
cannot assure you that the IRS will not take, and that a court would not
sustain, a position contrary to that described below. Moreover, the following
discussion is for general information only and does not constitute
comprehensive tax advice to any particular holder of Series A notes. This
summary is based on the current provisions of the Internal Revenue Code of
1986, as amended, and applicable Treasury regulations, judicial authority and
administrative pronouncements. The tax consequences described below could be
modified by future changes in the relevant law, which could have retroactive
effect. You should consult your own tax adviser as to these and any other
federal income tax consequences of this offer as well as any tax consequences
to it under foreign, state, local or other law.
Exchanges of Series A notes for Series B notes pursuant to this exchange
offer should be treated as a modification of the Series A notes that does not
constitute a material change in their terms, and we intend to treat the
exchanges in that manner. Under that approach, a Series B note is treated as a
continuation of the corresponding Series A note. An exchanging holder's holding
period for a Series B note would include the holder's holding period for the
Series A note. The holder would not recognize any gain or loss, and the
holder's basis in the Series B note would be the same as such holder's basis in
the Series A note. This exchange offer will result in no federal income tax
consequences to a non-exchanging holder. See "Material Federal Income Tax
Considerations of the Exchange Offer."
Exchange Agent
U.S. Bank Trust National Association has been appointed as exchange agent
for this exchange offer. All correspondence in connection with this exchange
offer and the letter of transmittal should be addressed to the exchange agent
as follows:
To: U.S. Bank Trust National Association
<TABLE>
<S> <C> <C>
By Registered or Certified By Overnight Delivery or
Mail: By Hand: Courier:
U.S. Bank Trust National U.S. Bank Trust U.S. Bank Trust National
Association National Association Association
180 East Fifth Street 180 East Fifth Street 180 East Fifth Street
St. Paul, MN 55101 St. Paul, MN 55101 St. Paul, MN 55101
</TABLE>
Attention:
4th Floor Bond Drop Window
Facsimile Transmission Number:
(For Eligible Institutions Only)
(651) 244-1537
Confirm by Telephone:
Bondholder Communications
(800) 934-6802
You may request additional copies of this prospectus or the letter of
transmittal from the exchange agent or us.
Payment of Expenses
We have not retained any dealer-manager or similar agent in connection
with this exchange offer and will not make any payments to brokers, dealers or
others for soliciting acceptances of this
57
<PAGE>
exchange offer. We, however, will pay reasonable and customary fees and
reasonable out-of-pocket expenses to the exchange agent in connection with the
solicitation of acceptances. We will also pay the cash expenses to be incurred
in connection with this exchange offer, including accounting, legal, printing,
and related fees and expenses.
Accounting Treatment
The Series B notes will be recorded at the same carrying value as the
Series A notes, as reflected in our accounting records on the date of the
exchange. Accordingly, no gain or loss for accounting purposes will be
recognized. Our expenses of this exchange offer will be capitalized for
accounting purposes.
Resales of Notes
For resales of Series B notes, based on interpretive letters issued by
the staff of the SEC to unrelated third parties, we believe that a holder of
Series B notes who exchanges Series A notes for Series B notes in the ordinary
course of business and who is not participating, does not intend to
participate, and has no arrangement or understanding with any person to
participate, in a distribution of the Series B notes, will be allowed to resell
the Series B notes to the public without further registration under the
Securities Act and without delivering to the purchasers of the Series B notes a
prospectus that satisfies the requirements of the Securities Act, except for:
. a broker-dealer who purchases Series B notes directly from us to
resell pursuant to Rule 144A or any other available exemption under
the Securities Act, or
. a person who is our "affiliate" within the meaning of Rule 405 under
the Securities Act.
However, a broker-dealer who holds Series A notes that were acquired for
its own account as a result of market-making or other trading activities may be
deemed to be an underwriter within the meaning of the Securities Act and must,
therefore, deliver a prospectus meeting the requirements of the Securities Act.
If any other holder is deemed to be an underwriter within the meaning of the
Securities Act or acquires Series B notes in this exchange offer for the
purpose of distributing or participating in a distribution of the Series B
notes, such holder must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction, unless an exemption from registration is otherwise available. We
have agreed that for a period of 180 days from the expiration date, we will
make this prospectus, as amended or supplemented, available to any broker-
dealer for use in connection with any such resale.
We have not requested or obtained an interpretive letter from the SEC's
staff with respect to this exchange offer. Neither the holders of Series A
notes nor we are entitled to rely on interpretive advice provided by the SEC's
staff to other persons, which advice was based on the facts and conditions
represented in such letters. However, this exchange offer is being conducted in
a manner intended to be consistent with the facts and conditions represented in
such letters. If any holder of Series A notes has any arrangement or
understanding with respect to the distribution of the Series B notes to be
acquired pursuant to this exchange offer, such holder:
. could not rely on the applicable interpretations of the SEC's staff;
and
. must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with any resale
transaction.
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In addition, each broker-dealer who receives Series B notes for its own
account in exchange for Series A notes, where such Series A notes were acquired
by such broker-dealer as a result of market-making activities or other trading
activities, must acknowledge that it will deliver a prospectus in connection
with any resale of such Series B notes. See "Plan of Distribution." By
delivering the letter of transmittal, you will represent and warrant to us that
you are acquiring the Series B notes in the ordinary course of your business
and that your are not engaged in, and do not intend to engage in, a
distribution of the Series B notes. If you are using this exchange offer to
participate in a distribution of the Series B notes, you must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with a secondary resale transaction. If you do not exchange your
Series A notes pursuant to this exchange offer, you will continue to hold
Series A notes that are subject to restrictions on transfer. See "Risk
Factors--Your failure to exchange your Series A notes for Series B notes could
have advance consequences to you."
It is expected that the Series B notes will be freely transferable by the
holders thereof, subject to the limitations described in the immediately
preceding paragraph. Sales of Series B notes acquired in this exchange offer by
holders who are our "affiliates" within the meaning of the Securities Act will
be subject to certain limitations on resale under Rule 144 of the Securities
Act. Such persons will only be entitled to sell Series B notes in compliance
with the volume limitations set forth in Rule 144, and sales of Series B notes
by affiliates will be subject to certain Rule 144 requirements as to the manner
of sale, notice and the availability of our current public information. The
foregoing is a summary only of Rule 144 as it may apply to our affiliates. If
you are an affiliate, you must consult your own legal counsel for advice as to
any restrictions that might apply to the resale of your Series B notes.
The Series B notes otherwise will be substantially identical in all
material respects, including interest rate, maturity, security and restrictive
covenants, to the Series A notes for which they may be exchanged pursuant to
this exchange offer.
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CAPITALIZATION
The following tables set forth, as of June 30, 1999, our cash and cash
equivalents, long-term debt and capitalization and the cash and cash
equivalents, long-term debt and capitalization of each Coso partnership on a
stand-alone and combined basis. This table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements, including the related notes thereto,
found elsewhere in this prospectus.
<TABLE>
<CAPTION>
As of
June 30, 1999
--------------
(In thousands)
Capitalization of Caithness Coso Funding Corp. --------------
<S> <C>
Cash............................................................. $ --
Restricted cash and investments.................................. --
========
Senior secured notes:
6.80% notes due 2001........................................... $110,000
9.05% notes due 2009........................................... 303,000
--------
Total debt..................................................... 413,000
Stockholder's equity............................................. --
--------
Total capitalization........................................... $413,000
========
Capitalization of the Navy I Partnership (stand-alone)(a)
Cash............................................................. $ 3,049
Restricted cash and investments(b)............................... 26,600
========
Project notes, payable to Funding Corp........................... $151,550
Partners' capital................................................ 50,001
--------
Total capitalization........................................... $201,551
========
Capitalization of the BLM Partnership (stand-alone)
Cash............................................................. $ 8,153
Restricted cash and investments.................................. 13,507
========
Project notes, payable to Funding Corp........................... $107,900
Partners' capital................................................ 87,336
--------
Total capitalization........................................... $195,236
========
Capitalization of the Navy II Partnership (stand-alone)
Cash............................................................. $ 13,042
Restricted cash and investments.................................. 18,676
========
Project notes, payable to Funding Corp........................... $153,550
Partners' capital................................................ 82,917
--------
Total capitalization........................................... $236,467
========
</TABLE>
60
<PAGE>
<TABLE>
<CAPTION>
As of
June 30, 1999
------------------
(in thousands)
Actual
<S> <C> <C>
Capitalization of the Navy I Partnership, BLM Partnership
and Navy II Partnership (combined)(c)
Cash....................................................... $ 24,244
Restricted cash and investments............................ 58,783
========
Project notes, payable to Funding Corp..................... $413,000
Partners' capital.......................................... 220,254
--------
Total capitalization..................................... $633,254
========
</TABLE>
- ---------------------
(a) Reflects the combined capitalization of the Navy I partnership and CFP II.
The Navy I partnership and CFP II were first formed as separate entities to
facilitate the initial bank financing for the construction and development
of Navy I. Initially, the Navy I partnership acquired all of the assets
relating to the first turbine generator unit at Navy I and CFP II acquired
all of the assets of Navy I relating to the second and third generator
units at Navy I. In 1988, CFP II assigned all of its rights and interests
in the second and third generator units at Navy I to the Navy I partnership
in return for a 5.0% royalty to be paid based on the Navy I partnership's
steam production. Since the Navy I partnership and CFP II operate under
common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the closing of the Series A
notes offering. See Note 1 to Notes to Combining and Combined Financial
Statements of Coso Finance Partners and Coso Finance Partners II.
(b) Includes funds on deposit in the sinking fund established for the benefit
of the Navy. See "Business--Royalty and Revenue-Sharing Arrangements--Navy
I."
(c) Reflects the mathematical summation of the Coso partnerships on a combined
basis as of June 30, 1999. These combined amounts are unaudited. The
combined presentation does not necessarily reflect the financial position
that would have occurred had the Coso partnerships constituted a single
entity as of June 30, 1999. Because the Coso partnerships are under common
management and are jointly and severally guaranteeing all of Funding
Corp.'s obligations under the Indenture and the senior secured notes, such
guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a
perfected, first priority pledge of all of the ownership interests in the
Coso partnerships, the combined financial information of the Coso
partnerships has been presented.
61
<PAGE>
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
Because we were only recently formed, we have no financial or operating
history. The following tables set forth selected historical financial and
operating data for each of the Coso partnerships on a stand-alone basis as of
and for the periods presented. The selected historical financial data for each
of the five years ended December 31, 1998, is derived from the audited
financial statements of each of the Coso partnerships. The financial and
operating data presented below should be read in conjunction with the financial
statements of each of the Coso partnerships, including the related notes
thereto, "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and the other financial information included elsewhere
in this prospectus.
The selected historical financial and operating data for the six months ended
June 30, 1998 and 1999 is unaudited. The unaudited statement of operations data
and balance sheet data as of and for the six months ended June 30, 1998 and the
unaudited statement of operations data for the two months ended February 28,
1999, have been prepared on the same basis as the audited financial statements
included elsewhere in this prospectus. The unaudited statement of operations
data and balance sheet data as of and for the four months ended June 30, 1999,
has been prepared under a new basis of accounting adopted by the Coso
partnerships after Caithness Acquisition purchased all of CalEnergy's interests
in the Coso projects. In the opinion of management, the unaudited financial
data contains all adjustments, consisting only of normally recurring
adjustments, necessary for a fair presentation of such financial presentation.
The unaudited financial information set forth below is not necessarily
indicative of results to be expected for any future periods.
The energy revenues received by the Coso partnerships during the five-year
period ended December 31, 1998 and the six month periods ended June 30, 1998
and 1999, as reflected in the tables below, should not be viewed as an
indicator of energy revenues to be received by the Coso partnerships during any
future periods. During the periods reflected in the tables below, Edison made
energy payments to the Coso partnerships based on the fixed energy prices
provided for in the power purchase agreements, except that, since August 1997,
Edison has been making energy payments to the Navy I partnership based on
Edison's avoided cost of energy and, in March 1999, Edison began making
payments to the BLM partnership based on Edison's avoided cost of energy.
Edison's avoided cost of energy has been and is expected to be in the future
substantially lower than the fixed energy prices received by the Coso
partnerships in the past. Once the fixed energy price period for the Navy II
partnership expires, Edison is also expected to make energy payments to the
Navy II partnership based on Edison's avoided cost of energy. See "Risk
Factors--Future energy payments paid by Edison to the Coso partnerships will
most likely be less than historical energy payments because they will be paid
based on Edison's avoided cost of energy" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
62
<PAGE>
Navy I Partnership(a)
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
-------------------------------------
Two Months
Six Months Ended Four Months
Year Ended December 31, Ended February 28, Ended June 30,
------------------------------------------------ June 30, 1999 1999
1994 1995 1996 1997 1998 1998 (prior basis) (new basis)(c) Total
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Statement of
Operations Data:
Energy revenues..... $ 87,233 $92,797 $103,940 $ 86,586(b) $39,580(b) $19,126 $8,098 $13,568 $21,666
Capacity
revenues(d)........ 14,258 14,266 14,266 13,845 13,573 4,170 474 3,469 3,943
Interest and other
income............. 2,529 2,893 3,286 1,980 585 293 824 1,074 1,898
-------- ------- -------- -------- ------- ------- ------ ------- -------
Total revenues..... 104,020 109,956 121,492 102,411 53,738 23,589 9,396 18,111 27,507
-------- ------- -------- -------- ------- ------- ------ ------- -------
Plant operations.... 14,007 13,565 11,763 11,329 13,298 7,244 3,125 3,914 7,039
Royalty expense..... 10,396 10,810 11,059 9,849 6,824 2,377 987 2,585 3,572
Depreciation and
amortization....... 12,109 12,770 13,325 12,814 11,772 5,911 1,604 3,174 4,778
-------- ------- -------- -------- ------- ------- ------ ------- -------
Total cost of
operations........ 36,512 37,145 36,147 33,992 31,894 15,532 5,716 9,673 15,389
-------- ------- -------- -------- ------- ------- ------ ------- -------
Operating income.... 67,508 72,811 85,345 68,419 21,844 8,057 3,680 8,438 12,118
Interest expense.... 12,991 11,356 8,868 6,260 4,333 2,232 663 5,952 6,615
Cumulative effect of
accounting change.. -- -- -- -- 923 -- -- -- --
-------- ------- -------- -------- ------- ------- ------ ------- -------
Income before ex-
traordinary item... 54,517 61,455 76,477 62,159 16,588 5,825 3,017 2,486 5,503
Extraordinary item-
loss on extinguish-
ment of debt....... -- -- -- -- -- -- -- 2,374 2,374
-------- ------- -------- -------- ------- ------- ------ ------- -------
Net income.......... $ 54,517 $61,455 $ 76,477 $ 62,159 $16,588 $ 5,825 $3,017 $ 112 $ 3,129
======== ======= ======== ======== ======= ======= ====== ======= =======
Ratio of earnings to
fixed charges(e)... 5.2x 6.4x 9.6x 10.9x 5.0x 3.6x 5.6x 1.0x(f) 1.5x
</TABLE>
<TABLE>
<CAPTION>
As of December 31, As of As of
-------------------------------------------- June 30, June 30,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash--unrestricted.... $ 38,669 $ 45,093 $ 15,724 $ 2,888 $ -- $ 784 $ 3,049
Cash and investments--
restricted........... 27,204 28,161 29,016 6,479 7,524 6,995 26,600
Total assets.......... 298,684 301,436 264,209 209,390 201,888 205,380 219,013
Project loan.......... 154,432 127,340 76,056 45,666 40,566 43,116 151,550
Total liabilities..... 166,804 136,855 96,375 53,822 51,955 53,934 169,012
Total partners'
capital.............. 131,880 164,581 167,834 155,568 149,933 151,446 50,001
</TABLE>
- --------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Initially, the Navy I partnership acquired the
assets of Navy I as they related to first turbine generator unit at Navy I
and CFP II acquired the assets of Navy I as they related to the second and
third generator units at Navy I. In 1988, CFP II assigned all of its rights
and interests in the second and third generator units at Navy I to the
Navy I partnership in return for a 5.0% royalty based on the Navy I
partnership's steam production. Since the Navy I partnership and CFP II
operate under common ownership and management control, the historical
financial statements of the entities have been combined after elimination
of intercompany amounts related to the royalty arrangement. At the Series A
notes closing, CFP II merged with and into the Navy I partnership and the
accrued royalty was extinguished. In addition, the royalty will no longer
accrue from and after the closing of the Series A notes offering. See Note
1 to Notes to Combining and Combined Financial Statements of Coso Finance
Partners and Coso Finance Partners II.
(b) The decrease in energy revenues is due to the fact that Edison paid the
Navy I partnership energy payments based on its position that the fixed
energy period expired in August 1997. Edison has also taken the position
that the fixed energy price period for the BLM partnership expired in March
1999 and will expire for the Navy II partnership in January 2000. The Coso
partnerships believe that under the power purchase agreements each of the
three turbine generator units at each Coso project has its own ten-year
fixed energy price period. This issue is one of several currently in
dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. See "Business--Legal Proceedings."
(c) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
63
<PAGE>
(d) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(e) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(f) The decrease in the ratio of earnings to fixed charges for the four months
ended June 30, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt and premiums paid of approximately $2.4 million
to retire the existing project debt.
64
<PAGE>
BLM Partnership
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
------------------------------------
Two Months Four Months
Ended Ended
Year Ended December 31, Six Months February 28, June 30,
----------------------------------------------- Ended June 1999 1999
1994 1995 1996 1997 1998 30, 1998 (prior basis) (new basis)(b) Total
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $76,134 $ 86,596 $ 87,985 $ 88,929 $ 93,352 $45,121 $16,716 $ 6,793 $23,509
Capacity revenues
(a)................... 13,929 13,938 13,938 13,939 13,847 4,620 817 3,894 4,711
Interest and other
income................ 2,509 2,644 2,520 1,712 1,181 473 78 372 450
------- -------- -------- -------- -------- ------- ------- ------- -------
Total revenues....... 92,572 103,178 104,443 104,580 108,380 50,214 17,611 11,059 28,670
------- -------- -------- -------- -------- ------- ------- ------- -------
Plant operations....... 19,651 17,564 18,266 18,830 19,887 10,815 4,039 5,516 9,555
Royalty expense........ 9,346 9,684 7,820 10,106 10,492 4,825 1,592 679 2,271
Depreciation and
amortization.......... 12,292 13,170 13,931 14,257 14,308 7,264 2,550 5,087 7,637
------- -------- -------- -------- -------- ------- ------- ------- -------
Total cost of opera-
tions............... 41,289 40,418 40,017 43,193 44,687 22,904 8,181 11,282 19,463
------- -------- -------- -------- -------- ------- ------- ------- -------
Operating income....... 51,283 62,760 64,426 61,387 63,693 27,310 9,430 (223) 9,207
Interest expense....... 16,040 15,063 13,162 9,105 6,267 3,556 616 4,864 5,480
Cumulative effect of
accounting change..... -- -- -- -- 953 -- -- -- --
------- -------- -------- -------- -------- ------- ------- ------- -------
Income before
Extraordinary Item.... 35,243 47,697 51,264 52,282 56,473 23,754 8,814 (5,087) 3,727
Extraordinary item-
Loss on
extinguishment of
debt.................. -- -- -- -- -- -- -- 1,822 1,822
------- -------- -------- -------- -------- ------- ------- ------- -------
Net income............. $35,243 $ 47,697 $ 51,264 $ 52,282 $ 56,473 $23,754 $ 8,814 $(6,909) $ 1,905
======= ======== ======== ======== ======== ======= ======= ======= =======
Ratio of earnings to
fixed charges (c)..... 3.2x 4.2x 4.9x 6.7x 10.2x 7.7x 15.3x n/a(d) 1.3x
</TABLE>
<TABLE>
<CAPTION>
As of December 31, As of As of
-------------------------------------------- June 30, June 30,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash--unrestricted...... $ 31,584 $ 40,219 $ 13,166 $ 873 $ -- $ 2,629 $ 8,153
Cash and investments--
restricted............. 23,478 23,533 23,298 290 290 290 13,507
Total assets............ 298,893 305,106 269,318 224,912 228,087 229,663 220,032
Project loan............ 155,661 137,748 105,990 76,654 37,958 57,306 107,900
Total liabilities....... 198,632 185,546 156,652 100,799 64,896 83,203 132,696
Total partners'
capital................ 100,261 119,560 112,666 124,113 163,191 146,460 87,336
</TABLE>
- --------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(d) The decrease in the ratio of earnings to fixed charges for the four months
ended June 30, 1999 is primarily due to the amortization of debt issuance
costs of approximately $1.4 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt and premiums of approximately $1.8 million paid
to retire the existing project debt. Earnings were inadequate to cover
fixed charges for the four months ended June 30, 1999 by $6.9 million.
65
<PAGE>
Navy II Partnership
<TABLE>
<CAPTION>
Six months Ended June 30, 1999
-------------------------------------
Two Months
Ended Four Month
Year Ended December 31, Six Months February 28, Ended June 30,
---------------------------------------------- Ended June 1999 1999
1994 1995 1996 1997 1998 30, 1998 (prior basis) (new basis)(c) Total
(In thousands, except ratio data)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Energy revenues........ $81,210 $94,372 $101,108 $ 98,778 $105,546 $49,920 $16,687 $31,272 $47,959
Capacity revenues
(a)................... 14,008 14,018 14,018 14,018 14,018 4,738 822 3,916 4,738
Interest and other
income................ 3,072 3,040 3,174 2,187 1,799 780 150 733 883
------- ------- -------- -------- -------- ------- ------- ------- -------
Total revenues....... 98,290 111,430 118,300 114,983 121,363 55,438 17,659 35,921 53,580
------- ------- -------- -------- -------- ------- ------- ------- -------
Plant operations....... 15,893 15,179 13,371 13,146 15,508 8,670 3,195 4,410 7,605
Royalty expense........ 3,927 11,141 11,486 11,249 11,868 5,400 1,806 3,936 5,742
Depreciation and
amortization.......... 11,800 12,848 13,054 13,354 13,744 7,016 2,339 4,754 7,093
------- ------- -------- -------- -------- ------- ------- ------- -------
Total cost of
operations.......... 31,620 39,168 37,911 37,749 41,120 21,086 7,340 13,100 20,440
------- ------- -------- -------- -------- ------- ------- ------- -------
Operating income....... 66,670 72,262 80,389 77,234 80,243 34,352 10,319 22,821 33,140
Interest expense....... 14,736 13,868 12,149 10,532 8,122 4,452 953 6,446 7,399
Cumulative effect of
accounting change..... -- -- -- -- 1,664 -- -- -- --
------- ------- -------- -------- -------- ------- ------- ------- -------
Income before
Extraordinary Item.... 51,934 58,394 68,240 66,702 70,457 29,900 9,366 16,375 25,741
Extraordinary item-
Loss on
extinguishment of
debt.................. -- -- -- -- -- -- -- 2,147 2,147
Net income............. $51,934 $58,394 $ 68,240 $ 66,702 $ 70,457 $29,900 $ 9,366 $14,228 $23,594
======= ======= ======== ======== ======== ======= ======= ======= =======
Ratio of earnings to
fixed charges (c)..... 4.5x 5.2x 6.6x 7.3x 9.9x 7.7x 10.8x 3.2x(d) 4.2x
</TABLE>
<TABLE>
<CAPTION>
As of December 31, As of As of
-------------------------------------------- June 30, June 30,
1994 1995 1996 1997 1998 1998 1999
(In thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash--unrestricted..... $ 41,843 $ 44,721 $ 18,133 $ 1,148 $ 818 $ 1,249 $ 13,042
Cash and investments--
restricted............ 22,771 22,841 22,391 -- -- -- 18,676
Total assets........... 309,212 307.537 270.522 226,949 218,965 224,557 243,326
Project loan........... 173,413 156,043 124,361 97,267 61,323 79,295 153,550
Total liabilities...... 184,051 167,455 144,430 101,536 65,304 84,485 160,409
Total partners'
capital............... 125,161 140,082 126,092 125,413 153,661 140,072 82,917
</TABLE>
- --------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) For purposes of computing the ratio of earnings to fixed charges, fixed
charges consist of interest expense and amortization of debt issuance
costs. Earnings used in computing the ratio of earnings to fixed charges
consist of net income plus fixed charges.
(d) The decrease in the ratio of earnings to fixed charges for the four months
ended June 30, 1999 is primarily due to the amortization of debt issuance
costs of approximately $2.0 million related to the short-term debt
financing associated with Caithness Acquisition's purchase of all of
CalEnergy's interests in the Coso projects over the three-month estimated
life of the short-term debt and premiums of approximately $2.1 million paid
to retire the existing project debt.
66
<PAGE>
UNAUDITED PRO FORMA FINANCIAL DATA
The following unaudited pro forma statement of operations for each of the
Coso partnerships and the following unaudited combined pro forma statement of
operations of the Coso partnerships for the year ended December 31, 1998, and
for the six months ended June 30, 1999, give effect to (1) the completion of
the Series A notes offering and the application of the proceeds therefrom,
(2) Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects and (3) certain related adjustments, under the assumptions and
adjustments set forth in the notes accompanying the unaudited pro forma
statements of operations and unaudited combined statements of operations, and
assume that all such transactions occurred at the beginning of the periods
presented. The unaudited pro forma financial data set forth below is based on
the historical financial statements of the Coso partnerships.
The unaudited combined pro forma financial data reflects the mathematical
summation of the Coso partnerships on a combined basis for the six months ended
June 30, 1999 and for the year ended December 31, 1998. Since the Coso
partnerships are under common management and have jointly and severally
guaranteed all of our obligations under the Indenture and the senior secured
notes, such guarantees being secured by (1) a perfected, first priority lien on
substantially all of the assets of the Coso partnerships and (2) a perfected,
first priority pledge of all of the ownership interests in the Coso
partnerships, the combined pro forma financial information of the Coso
partnerships has been presented.
The unaudited combined pro forma financial data does not purport to represent
what the financial position or results of operations of the Coso partnerships
would have been had Caithness Acquisition's purchase of CalEnergy's interests
and the completion of the Series A notes offering occurred on the dates
specified below. Furthermore, the unaudited combined pro forma financial data
does not purport to reflect the financial position or results of operations of
the Coso partnerships as if they constituted a single entity or for any future
period or date. The unaudited combined pro forma financial information should
not be considered in isolation or as a substitute for the pro forma financial
information of each of the Coso partnerships on a stand-alone basis included
herein.
The pro forma adjustments reflected below are based upon currently available
information and certain assumptions that we believe are reasonable under the
circumstances. In our opinion, all adjustments have been made that are
necessary to present fairly the pro forma financial data.
The adjustments contained in the unaudited pro forma financial data do not
give effect to any non-recurring costs directly associated with the Caithness
Acquisition's purchase of CalEnergy's interests in the Coso projects and the
completion of the Series A notes offering. You should read the unaudited pro
forma financial data in conjunction with the historical financial statements of
the Coso partnerships, including the related notes thereto, and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included elsewhere in this prospectus.
67
<PAGE>
THE NAVY I PARTNERSHIP (a)
Unaudited Pro Forma Statement of Operations
for the Navy I Partnership
for the Six Months Ended June 30, 1999
(In thousands)
<TABLE>
<CAPTION>
Pro Forma
Two Months Ended Four Months Ended ------------------------
February 28, 1999 June 30, 1999 Total Adjustments As Adjusted
(prior basis) (new basis)(b)
<S> <C> <C> <C> <C> <C>
Energy revenues......... $8,098 $13,568 $21,666 $ -- $21,666
Capacity revenues (c)... 474 3,469 3,943 -- 3,943
Interest income......... 824 1,074 1,898 -- 1,898
------ ------- ------- ----- -------
Total revenues........ 9,396 18,111 27,507 -- 27,507
Plant operations........ 3,125 3,914 7,039 (274)(d) 6,765
Royalty expense......... 987 2,585 3,572 -- 3,572
Depreciation and
amortization........... 1,604 3,174 4,778 (55)(e) 4,723
------ ------- ------- ----- -------
Total operating
expenses............. 5,716 9,673 15,389 (329) 15,060
Operating income........ 3,680 8,438 12,118 329 12,447
Interest and other
expense................ 663 5,952 6,615 179 (f) 6,794
------ ------- ------- ----- -------
Income from continuing
operations(g).......... $3,017 $ 2,486 $ 5,503 $ 150 $ 5,653
====== ======= ======= ===== =======
</TABLE>
- ---------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Since the Navy I partnership and CFP II operate
under common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after Series A notes offering. See
Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(d) Adjusts for a reduction in O&M and management committee fees of
approximately $274,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management committee fees and
the amounts which are expected to be expensed based on the terms of the new
O&M and management committee fee agreements. See "Summary Descriptions of
Principal Agreements Relating to the Coso Projects" and "Certain
Relationships and Related Transactions--O&M Fees; Reduction in Fees" and
"--Management Committee Fees."
(e) Adjusts for a change in depreciation and amortization expense relating to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy I project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$250,000 based on the lower carrying values of property, plant and
equipment, offset by an increase in amortization expense of approximately
$195,000 based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(f) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on estimated indebtedness of approximately $29.0 million of senior
secured notes due 2001 assuming a rate of interest per annum of 6.80% and
of approximately $122.6 million of senior secured notes due 2009, assuming
a rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of approximately $260,000 is based on estimated
underwriting discounts and commissions and offering expenses of $3.5
million, amortized over the terms of the related project notes.
(g) To retire the existing project debt, the Navy I partnership paid premiums
of approximately $2.2 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income from continuing operations.
68
<PAGE>
THE BLM PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the BLM Partnership
for the Six Months Ended June 30, 1999
(In thousands)
<TABLE>
<CAPTION>
Two Months Ended Four Months Pro forma
February 28, Ended -------------------------
1999 June 30, 1999 Total Adjustments As adjusted
(prior basis) (new basis)(b)
<S> <C> <C> <C> <C> <C>
Energy revenues......... $16,716 $ 6,793 $23,509 $ -- $23,509
Capacity revenues(a).... 817 3,894 4,711 -- 4,711
Interest and other
income................. 78 372 450 -- 450
------- ------- ------- ------ -------
Total revenues...... 17,611 11,059 28,670 -- 28,670
Plant operations........ 4,039 5,516 9,555 (397)(c) 9,158
Royalty expense......... 1,592 679 2,271 -- 2,271
Depreciation and
amortization........... 2,550 5,087 7,637 (267)(d) 7,370
------- ------- ------- ------ -------
Total operating
expenses........... 8,181 11,282 19,463 (664) 18,799
Operating income........ 9,430 (223) 9,207 664 9,871
Interest and other
expense................ 616 4,864 5,480 (572)(e) 4,908
------- ------- ------- ------ -------
Income from continuing
operations(f).......... $ 8,814 $(5,087) $ 3,727 $1,236 $ 4,963
======= ======= ======= ====== =======
</TABLE>
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $397,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management committee fees and
the amounts which are expected to be expensed based on the terms of the new
O&M and management committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the BLM
project. Calculated as if Caithness Acquisition's purchase had occurred on
January 1, 1999, depreciation decreased by approximately $439,000, based on
the lower carrying values of property, plant and equipment, partially
offset by an increase in amortization expense of approximately $172,000
based on the higher carrying value of the power purchase agreement. The
carrying values resulted from the allocation of purchase price to the
portion of assets and liabilities acquired from CalEnergy based on their
fair values, with the amount of fair value of net assets acquired in excess
of the purchase price allocated to long lived assets on a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the use of proceeds from the Series A notes
offering to repay the existing project debt and the acquisition debt,
offset by the interest expense relating to the new project notes and
amortization of deferred financing costs as if the Series A notes offering
had occurred on January 1, 1999. The interest expense related to the senior
secured notes is based on estimated indebtedness of approximately $11.7
million of senior secured notes due 2001 assuming a rate of interest per
annum of 6.80% and of approximately $96.3 million of senior secured notes
due 2009 assuming a rate of interest per annum of 9.05%. The adjustment for
amortization of debt issuance costs of approximately $152,000 is based on
estimated underwriting discounts and commissions and offering expenses of
$2.5 million, amortized over the terms of the related project notes.
(f) To retire the existing project debt, the BLM partnership paid premiums of
approximately $1.7 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income from continuing operations.
69
<PAGE>
THE NAVY II PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the Navy II Partnership
for the Six Months Ended June 30, 1999
(In thousands)
<TABLE>
<CAPTION>
Two Months
Ended Four Months
February 28, Ended June 30, Pro Forma
1999 1999 -------------------------
(prior basis) (new basis)(b) Total Adjustments As Adjusted
<S> <C> <C> <C> <C> <C>
Energy revenues......... $16,687 $31,272 $47,959 $ -- $47,959
Capacity revenues (a)... 822 3,916 4,738 -- 4,738
Interest and other
income................. 150 733 883 -- 883
------- ------- ------- ------ -------
Total revenues........ 17,659 35,921 53,580 -- 53,580
Plant operations........ 3,195 4,410 7,605 (325)(c) 7,280
Royalty expense......... 1,806 3,936 5,742 -- 5,742
Depreciation and
amortization........... 2,339 4,754 7,093 -- (d) 7,093
------- ------- ------- ------ -------
Total operating
expenses............. 7,340 13,100 20,440 (325) 20,115
Operating income........ 10,319 22,821 33,140 325 33,465
Interest and other
expense................ 953 6,446 7,399 (830)(e) 6,569
------- ------- ------- ------ -------
Income from continuing
operations (f)......... $ 9,366 $16,375 $25,741 $1,155 $26,896
======= ======= ======= ====== =======
</TABLE>
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso projects, the Coso partnerships adopted a new
basis of accounting. The purchase price was allocated to the portion of the
assets and liabilities purchased from CalEnergy based on their fair values,
with the amount of fair value of net assets in excess of the purchase price
being allocated to long-lived assets on a pro-rata basis.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $325,000. The adjustment represents the difference between
the amounts previously expensed for O&M and management fees and the amounts
which are expected to be expensed based on the terms of the new O&M and
management committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy II project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$453,000, based on the lower carrying values of property, plant and
equipment, partially offset by an increase in amortization expense of
approximately $453,000 based on the higher carrying value of the power
purchase agreement. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on estimated indebtedness of approximately $69.4 million of senior
secured notes due 2001 assuming a rate of interest per annum of 6.80% and
of approximately $84.2 million of senior secured notes due 2009 assuming a
rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of approximately $400,000 is based on estimated
underwriting discounts and commissions and offering expenses of $3.5
million, amortized over the terms of the related project notes.
(f) To retire the existing project debt, the Navy II partnership paid premiums
of approximately $2.0 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income from continuing operations.
70
<PAGE>
THE COSO PARTNERSHIPS
Unaudited Combined Pro Forma Statement of Operations(a)
for the Coso Partnerships
for the Six Months Ended June 30, 1999
(In thousands)
<TABLE>
<CAPTION>
Two Months Ended Four Months Ended Pro Forma
February 28, 1999 June 30, 1999 -------------------------
(prior basis) (new basis)(b) Total Adjustments As Adjusted
<S> <C> <C> <C> <C> <C>
Energy revenues......... $41,501 $51,633 $ 93,134 $ -- $ 93,134
Capacity revenues (c)... 2,113 11,279 13,392 -- 13,392
Interest and other total
revenues income........ 1,052 2,179 3,231 -- 3,231
------- ------- -------- ------- --------
Total revenues...... 44,666 65,091 109,757 -- 109,757
Plant operations........ 10,359 13,840 24,199 (996)(d) 23,203
Royalty expense......... 4,385 7,200 11,585 -- 11,585
Depreciation and
amortization........... 6,493 13,015 19,508 (322)(e) 19,186
------- ------- -------- ------- --------
Total operating
expenses........... 21,237 34,055 55,292 (1,318) 53,974
Operating income........ 23,429 31,036 54,465 1,318 55,783
Interest and other
expense................ 2,232 17,262 19,494 (1,223)(f) 18,271
------- ------- -------- ------- --------
Income from continuing
operations (g)......... $21,197 $13,774 $ 34,971 $ 2,541 $ 37,512
======= ======= ======== ======= ========
</TABLE>
- ---------------------
(a) Reflects the mathematical summation of financial information of the Coso
partnerships on a combined basis for the six months ended June 30, 1999.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the results of operations that would have occurred had
the Coso partnerships constituted a single entity during the same period.
Because the Coso partnerships are under common management and have jointly
and severally guaranteed all of our obligations under the Indenture and the
senior secured notes, such guarantees being secured by (1) a perfected,
first priority lien on substantially all of the assets of the Coso
partnerships and (2) a perfected, first priority pledge of all of the
ownership interests in the Coso partnerships, the unaudited combined
financial information of the Coso partnerships has been presented.
(b) After Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships adopted a new basis of accounting.
The purchase price was allocated to the portion of the assets and
liabilities purchased from CalEnergy based on their fair values, with the
amount of fair value of net assets in excess of the purchase price being
allocated to long-lived assets on a pro-rata basis.
(c) Includes capacity payments and capacity bonus payments paid to the Coso
partnerships on a combined basis under the power purchase agreements.
(d) Adjusts for a reduction in O&M and management committee fees of
approximately $274,000, $397,000 and $325,000 for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. The
adjustment represents the difference between the amounts previously
expensed for O&M and management committee fees and the amounts which are
expected to be expensed based on the terms of the new O&M and management
committee agreements.
(e) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1999, depreciation decreased by approximately
$250,000 for the Navy I partnership, $439,000 for the BLM partnership and
$453,000 for the Navy II partnership, based on the lower carrying values of
property, plant and equipment, offset or partially offset by an increase in
71
<PAGE>
amortization expense of approximately $195,000 for the Navy I partnership,
$172,000 for the BLM partnership and $453,000 for the Navy II partnership,
based on the higher carrying values of the power purchase agreements. The
carrying values resulted from the allocation of purchase price to the
portion of assets and liabilities acquired from CalEnergy based on their
fair values, with the amount of fair value of net assets acquired in excess
of the purchase price allocated to long lived assets on a pro-rata basis.
(f) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt and the acquisition debt, offset by the
interest expense relating to the new project notes and amortization of
deferred financing costs as if the Series A notes offering had occurred on
January 1, 1999. The interest expense related to the senior secured notes
is based on the following estimated indebtedness from the offering
assuming a rate of interest per annum on the senior secured notes due 2001
of 6.80% and a rate of interest on the senior secured notes due 2009 of
9.05%:
<TABLE>
<CAPTION>
Senior Secured Senior Secured
Notes Due 2001 Notes Due 2009
(In thousands)
<S> <C> <C> <C>
Navy I partnership......................... $ 29,000 $122,550
BLM partnership............................ 11,650 96,250
Navy II partnership........................ 69,350 84,200
-------- --------
$110,000 $303,000
======== ========
</TABLE>
The adjustment for amortization of debt issuance costs of $260,000, $152,000
and $400,000 is based on estimated underwriting discounts and commissions
and offering expenses of $3.5 million, $2.5 million and $3.5 million for the
Navy I partnership, the BLM partnership and the Navy II partnership,
respectively, amortized over the terms of the related project notes.
(g) To retire the existing project debt, premiums were paid of approximately
$2.2 million, $1.7 million and $2.0 million for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. These
premiums are not included in income before cumulative effect of accounting
change on a pro forma basis because the amounts were recorded as an
extraordinary item which is not a component of income from continuing
operations.
72
<PAGE>
THE NAVY I PARTNERSHIP (a)
Unaudited Pro Forma Statement of Operations
for the Navy I Partnership
for the Year Ended December 31, 1998
(In thousands)
<TABLE>
<CAPTION>
Pro Forma
--------------------------
Actual Adjustments As Adjusted
<S> <C> <C> <C>
Energy revenues............................ $39,580 $ -- $39,580
Capacity revenues (b)...................... 13,573 -- 13,573
Interest income............................ 585 -- 585
------- -------- -------
Total revenues........................... 53,738 -- 53,738
Plant operations........................... 13,298 (1,643)(c) 11,655
Royalty expense............................ 6,824 -- 6,824
Depreciation and amortization.............. 11,772 (416)(d) 11,356
------- -------- -------
Total operating expenses................. 31,894 (2,059) 29,835
Operating income........................... 21,844 2,059 23,903
Interest expense........................... 4,333 9,254 (e) 13,587
------- -------- -------
Income before cumulative effect of
accounting change(f)...................... $17,511 $ (7,195) $10,316
======= ======== =======
</TABLE>
- ---------------------
(a) Reflects the combined financial results of the Navy I partnership and CFP
II. The Navy I partnership and CFP II were first formed as separate
entities to facilitate the initial bank financing for the construction and
development of Navy I. Since the Navy I partnership and CFP II operate
under common ownership and management control, the historical financial
statements of the entities have been combined after elimination of
intercompany amounts related to the royalty arrangement. At the closing of
the Series A notes offering, CFP II was merged with and into the Navy I
partnership and the accrued royalty was extinguished. In addition, the
royalty will no longer accrue from and after the Series A notes offering.
See Note 1 to Notes to Combining and Combined Financial Statements of Coso
Finance Partners and Coso Finance Partners II.
(b) Includes capacity payments and capacity bonus payments paid to the Navy I
partnership under its power purchase agreement.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $1.6 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management committee
fees and the amounts which are expected to be expensed based on the terms
of the new O&M and management committee fee agreements. See "Summary
Descriptions of Principal Agreements Relating to the Coso Projects" and
"Certain Relationships and Related Transactions--O&M Fees; Reduction in
Fees" and "--Management Committee Fees."
(d) Adjusts for a change in depreciation and amortization expense relating to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy I project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $1.5
million based on the lower carrying values of property, plant and
equipment, offset by an increase in amortization expense of approximately
$1.1 million based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as if
the Series A notes offering had occurred on January 1, 1998. The interest
expense related to the senior secured notes is based on estimated
indebtedness of approximately $29.0 million of senior secured notes due
2001 assuming a rate of interest per annum of 6.80% and of approximately
$122.6 million of senior secured notes due 2009, assuming a rate of
interest per annum of 9.05%. The adjustment for amortization of debt
issuance costs of $520,000 is based on estimated underwriting discounts and
commissions and offering expenses of $3.5 million, amortized over the terms
of the related project notes.
(f) To retire the existing project debt, the Navy I partnership paid premiums
of approximately $2.2 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income before cumulative effect of accounting change.
73
<PAGE>
THE BLM PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the BLM Partnership
for the Year Ended December 31, 1998
(In thousands)
<TABLE>
<CAPTION>
Pro Forma
-------------------------
Actual Adjustments As Adjusted
<S> <C> <C> <C>
Energy revenues............................. $93,352 $ -- $93,352
Capacity revenues(a)........................ 13,847 -- 13,847
Interest and other income................... 1,181 -- 1,181
------- ------- -------
Total revenues.......................... 108,380 -- 108,380
Plant operations............................ 19,887 (2,382)(b) 17,505
Royalty expense............................. 10,492 -- 10,492
Depreciation and amortization............... 14,308 (1,651)(c) 12,657
------- ------- -------
Total operating expenses................ 44,687 (4,033) 40,654
Operating income............................ 63,693 4,033 67,726
Interest expense............................ 6,267 3,549 (d) 9,816
------- ------- -------
Income before cumulative effect of
accounting change(e)....................... $57,426 $ 484 $57,910
======= ======= =======
</TABLE>
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the BLM
partnership under its power purchase agreement.
(b) Adjusts for a reduction in O&M and management committee fees of
approximately $2.4 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management committee
fees and the amounts which are expected to be expensed based on the terms
of the new O&M and management committee fee agreements.
(c) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the BLM
project. Calculated as if Caithness Acquisition's purchase had occurred on
January 1, 1998, depreciation decreased by approximately $2.6 million,
based on the lower carrying values of property, plant and equipment,
partially offset by an increase in amortization expense of approximately
$900,000 based on the higher carrying value of the power purchase
agreement. The carrying values resulted from the allocation of purchase
price to the portion of assets and liabilities acquired from CalEnergy
based on their fair values, with the amount of fair value of net assets
acquired in excess of the purchase price allocated to long lived assets on
a pro-rata basis.
(d) Adjusts for the elimination of historical interest expense due to the
application of a portion of the use of proceeds from the Series A notes
offering to repay the existing project debt offset by the interest expense
relating to the new project notes and amortization of deferred financing
costs as if the Series A notes offering had occurred on January 1, 1998.
The interest expense related to the senior secured notes is based on
estimated indebtedness of approximately $11.7 million of senior secured
notes due 2001 assuming a rate of interest per annum of 6.80% and of
approximately $96.3 million of senior secured notes due 2009 assuming a
rate of interest per annum of 9.05%. The adjustment for amortization of
debt issuance costs of $305,000 is based on estimated underwriting
discounts and commissions and offering expenses of $2.5 million, amortized
over the terms of the related project notes.
(e) To retire the existing project debt, the BLM partnership paid premiums of
approximately $1.7 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income before cumulative effect of accounting change.
74
<PAGE>
THE NAVY II PARTNERSHIP
Unaudited Pro Forma Statement of Operations
for the Navy II Partnership
for the Year Ended December 31, 1998
(In thousands)
<TABLE>
<CAPTION>
Pro Forma
-------------------------
Actual Adjustments As Adjusted
<S> <C> <C> <C>
Energy revenues............................ $105,546 $ -- $105,546
Capacity revenues (a)...................... 14,018 -- 14,018
Interest and other income.................. 1,799 -- 1,799
-------- ------- --------
Total revenues........................... 121,363 -- 121,363
Plant operations........................... 15,508 (1,950)(b) 13,558
Royalty expense............................ 11,868 -- 11,868
Depreciation and amortization.............. 13,744 (230)(c) 13,514
-------- ------- --------
Total operating expenses................. 41,120 (2,180) 38,940
Operating income........................... 80,243 2,180 82,423
Interest expense........................... 8,122 5,015 (d) 13,137
-------- ------- --------
Income before cumulative effect of
accounting change (e)..................... $ 72,121 $(2,835) $ 69,286
======== ======= ========
</TABLE>
- ---------------------
(a) Includes capacity payments and capacity bonus payments paid to the Navy II
partnership under its power purchase agreement.
(b) Adjusts for a reduction in O&M and management committee fees of
approximately $2.0 million. The adjustment represents the difference
between the amounts previously expensed for O&M and management fees and the
amounts which are expected to be expensed based on the terms of the new O&M
and management committee fee agreements.
(c) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Navy II project. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $2.7
million, based on the lower carrying values of property, plant and
equipment, partially offset by an increase in amortization expense of
approximately $2.5 million based on the higher carrying value of the power
purchase agreement. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
(d) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as if
the Series A notes offering had occurred on January 1, 1998. The interest
expense related to the senior secured notes is based on estimated
indebtedness of approximately $69.4 million of senior secured notes due
2001 assuming a rate of interest per annum of 6.80% and of approximately
$84.2 million of senior secured notes due 2009 assuming a rate of interest
per annum of 9.05%. The adjustment for amortization of debt issuance costs
of $798,000 is based on estimated underwriting discounts and commissions
and offering expenses of $3.5 million, amortized over the terms of the
related project notes.
(e) To retire the existing project debt, the Navy II partnership paid premiums
of approximately $2.0 million. These premiums are not included in income
before cumulative effect of accounting change on a pro forma basis because
the amount was recorded as an extraordinary item which is not a component
of income before cumulative effect of accounting change.
75
<PAGE>
THE COSO PARTNERSHIPS
Unaudited Combined Pro Forma Statement of Operations(a)
for the Coso Partnerships
for the Year Ended December 31, 1998
(In thousands)
<TABLE>
<CAPTION>
Pro Forma
--------------------------
Actual Adjustments As Adjusted
<S> <C> <C> <C>
Energy revenues........................... $238,478 $ -- $238,478
Capacity revenues (b)..................... 41,438 -- 41,438
Interest and other total revenues income.. 3,565 -- 3,565
-------- -------- --------
Total revenues........................ 283,481 -- 283,481
Plant operations.......................... 48,693 (5,975)(c) 42,718
Royalty expense........................... 29,184 -- 29,184
Depreciation and amortization............. 39,824 (2,297)(d) 37,527
-------- -------- --------
Total operating expenses.............. 117,701 (8,272) 109,429
Operating income.......................... 165,780 8,272 174,052
Interest expense.......................... 18,722 17,818(e) 36,540
-------- -------- --------
Income before cumulative effect of
accounting change (f).................... $147,058 $ (9,546) $137,512
======== ======== ========
</TABLE>
- ---------------------
(a) Reflects the mathematical summation of financial information of the Coso
partnerships on a combined basis for the year ended December 31, 1998.
These combined amounts are unaudited. The combined presentation does not
necessarily reflect the results of operations that would have occurred had
the Coso partnerships constituted a single entity during the same period.
Because the Coso partnerships are under common management and have jointly
and severally guaranteed all of our obligations under the Indenture and the
senior secured notes, such guarantees being secured by (1) a perfected,
first priority lien on substantially all of the assets of the Coso
partnerships and (2) a perfected, first priority pledge of all of the
ownership interests in the Coso partnerships, the unaudited combined
financial information of the Coso partnerships has been presented.
(b) Includes capacity payments and capacity bonus payments paid to the Coso
partnerships on a combined basis under the power purchase agreements.
(c) Adjusts for a reduction in O&M and management committee fees of
approximately $1.6 million, $2.4 million and $2.0 million for the Navy I
partnership, the BLM partnership and the Navy II partnership, respectively.
The adjustment represents the difference between the amounts previously
expensed for O&M and management committee fees and the amounts which are
expected to be expensed based on the terms of the new O&M and management
committee fee agreements.
(d) Adjusts for a change in depreciation and amortization expense due to
Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects. Calculated as if Caithness Acquisition's purchase had
occurred on January 1, 1998, depreciation decreased by approximately $1.5
million for the Navy I partnership, $2.6 million for the BLM partnership
and $2.7 million for the Navy II partnership, based on the lower carrying
values of property, plant and equipment, offset or partially offset by an
increase in amortization expense of approximately $1.1 million for the Navy
I partnership, $900,000 for the BLM partnership and $2.5 million for the
Navy II partnership, based on the higher carrying values of the power
purchase agreements. The carrying values resulted from the allocation of
purchase price to the portion of assets and liabilities acquired from
CalEnergy based on their fair values, with the amount of fair value of net
assets acquired in excess of the purchase price allocated to long lived
assets on a pro-rata basis.
76
<PAGE>
(e) Adjusts for the elimination of historical interest expense due to the
application of a portion of the proceeds from the Series A notes offering
to repay the existing project debt offset by the interest expense relating
to the new project notes and amortization of deferred financing costs as
if the Series A notes offering had occurred on January 1, 1998. The
interest expense related to the senior secured notes is based on the
following estimated indebtedness from the offering assuming a rate of
interest per annum on the senior secured notes due 2001 of 6.80% and a
rate of interest on the senior secured notes due 2009 of 9.05%:
<TABLE>
<CAPTION>
Senior Secured Senior Secured
Notes Due 2001 Notes Due 2009
(In thousands)
<S> <C> <C> <C>
Navy I partnership......................... $ 29,000 $122,550
BLM partnership............................ 11,650 96,250
Navy II partnership........................ 69,350 84,200
-------- --------
$110,000 $303,000
======== ========
</TABLE>
The adjustment for amortization of debt issuance costs of $520,000,
$305,000 and $798,000 is based on estimated underwriting discounts and
commissions and offering expenses of $3.5 million, $2.5 million and $3.5
million for the Navy I partnership, the BLM partnership and the Navy II
partnership, respectively, amortized over the terms of the related project
notes.
(f) To retire the existing project debt, premiums were paid of approximately
$2.2 million, $1.7 million and $2.0 million for the Navy I partnership,
the BLM partnership and the Navy II partnership, respectively. These
premiums are not included in income before cumulative effect of accounting
change on a pro forma basis because the amounts were recorded as
extraordinary items which are not components of income before cumulative
effect of accounting change.
77
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis relates to the financial condition and
results of operations of each of the Coso partnerships. It should be read in
conjunction with "Selected Historical Financial and Operating Data" and the
financial statements of each of the Coso partnerships, including the notes
thereto, included elsewhere in this prospectus. Because we were only recently
formed, we have no financial history. Except for the historical financial
information contained herein, this prospectus contains certain forward-looking
statements that involve risks and uncertainties, such as statements of the Coso
partnerships' plans, objectives, expectations and intentions. The Coso
partnerships' actual financial results could differ materially from those
discussed here. Factors that could cause or contribute to such differences
include those discussed under the headings "Forward-Looking Statements" and
"Risk Factors" as well as those discussed elsewhere in this prospectus.
General
The Coso projects consist of three 80 MW geothermal power plants, which we
call Navy I, BLM and Navy II, and their transmission lines, wells, gathering
system and other related facilities. The Coso projects are located near one
another at the United States Naval Air Weapons Center at China Lake,
California. The Navy I partnership owns Navy I and its related facilities. The
BLM partnership owns BLM and its related facilities. The Navy II partnership
owns Navy II and its related facilities. Affiliates of Caithness Corporation
and CalEnergy formed the Coso partnerships in the 1980s to develop, construct,
own and operate the Coso projects. On February 25, 1999, Caithness Acquisition
purchased all of CalEnergy's interests in the Coso projects for $205.0 million
in cash, plus $5.0 million in contingency payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. As of December 31, 1998, the
book values of CalEnergy's interests in the Navy I partnership, the BLM
partnership and the Navy II partnership purchased by Caithness Acquisition were
approximately $71.8 million, $75.3 million and $76.8 million, respectively.
Each Coso partnership sells 100% of the electrical energy generated at its
plant to Edison under a long-term Standard Offer No. 4 power purchase
agreement. Each power purchase agreement expires after the last maturity date
of the senior secured notes. Edison is one of the largest investor-owned
electric utilities in the United States. As of December 31, 1998, Edison
reported in its 1998 annual report total assets of $16.9 billion and operating
revenues of $8.8 billion. Edison is currently rated A1 by Moody's and A+ by
Standard & Poor's.
Each Coso partnership receives the following payments under its power
purchase agreement:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the life of each power
purchase agreement;
. Capacity bonus payments if the Coso partnership is able to produce above
a specified higher level. The maximum annual capacity bonus payment
available is also fixed throughout the life of each power purchase
agreement; and
. Energy payments which are based on the amount of electricity the Coso
partnership's plant actually produces.
Energy payments are fixed for the first ten years of firm operation under
each power purchase agreement. Firm operation was achieved for each Coso
partnership when Edison and that Coso
78
<PAGE>
partnership agreed that each generating unit at that Coso partnership's plant
was a reliable source of generation and could reasonably be expected to operate
continuously at its effective rating. After the first ten years of firm
operation and until a Coso partnership's power purchase agreement expires,
Edison makes energy payments to the Coso partnership based on Edison's avoided
cost of energy. Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the relevant Coso partnership. See "Risk
Factors--Future energy payments paid by Edison to the Coso partnerships will
most likely be less than historical energy payments because they will be paid
based on Edison's avoided cost of energy." The power purchase agreement for the
Navy I partnership will expire in August 2011, the power purchase agreement for
the BLM partnership will expire in March 2019, and the power purchase agreement
for the Navy II partnership will expire in January 2010.
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement as to the outcome of this
or any other dispute with Edison, for purposes of this prospectus only,
including the financial information included herein, we have assumed that the
fixed energy price period expires ten years after the first of the three
turbine generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings--Edison Litigation."
The Coso partnerships have implemented and intend to expand a steam sharing
program which they established under a Coso Geothermal Exchange Agreement they
entered into in 1994. The purpose of the steam sharing program is to enhance
the management of the Coso geothermal resource and to optimize the resource's
overall benefits to the Coso partnerships by transferring steam among the Coso
projects. The Navy I partnership recorded steam transfer revenues from the Navy
II partnership and the BLM partnership of approximately $12.9 million for the
six months ended June 30, 1999, approximately $19.0 million for the year ended
December 31, 1998, approximately $11.1 million for the year ended December 31,
1997 and approximately $4.5 million for the year ended December 31, 1996. The
Navy II partnership recorded steam transfer revenues from the BLM partnership
of zero for the six months ended June 30, 1999, approximately $292,000 for the
year ended December 31, 1998, zero for the year ended December 31, 1997 and
approximately $3.1 million for the year ended December 31, 1996. The BLM
partnership incurred steam transfer revenues in the aggregate to the Navy I
partnership and the Navy II partnership approximately $5.4 million for the six
months ended June 30, 1999, $13.5 million for the year ended December 31, 1998,
$6.0 million for the year ended December 31, 1997 and $7.6 million for the year
ended December 31, 1996, and the Navy II partnership incurred to the Navy I
partnership approximately $7.5 million for the six months ended June 30, 1999,
$5.5 million for the year ended December 31, 1998, $5.1 million for the year
ended December 31, 1997 and zero for the year ended December 31, 1996. See
"Business--Steam Sharing Program" and "Summary Descriptions of Principal
Agreements Relating to the Coso Projects--Steam Sharing and Co-Tenancy
Agreements."
For the six months ended June 30, 1999 and for the year ended December 31,
1998, Edison's average avoided cost of energy paid to the Navy I partnership
was 2.7c and 3.0c per kWh,
79
<PAGE>
respectively, which is substantially below the fixed energy prices earned for
the six months ended June 30, 1998 and for the year ended December 31, 1998 by
the BLM partnership and the Navy II partnership. Edison is now making energy
payments to the BLM partnership based on its avoided cost of energy, which
payments are likely to be substantially less than the fixed energy prices the
BLM partnership earned through February 1999. Estimates of Edison's future
avoided cost of energy vary significantly, and no one can predict the likely
level of avoided cost of energy prices following the end of the fixed energy
price period under the Navy II partnership's power purchase agreement in
January 2000. Edison's avoided cost of energy is currently substantially below
the fixed energy prices previously paid by Edison during the fixed energy price
periods under the power purchase agreement for the Navy I partnership and the
BLM partnership. We expect that Edison's avoided cost of energy will remain so
over at least the near term for the Navy I partnership and the BLM partnership.
The revenues generated by the Coso partnerships will probably decline
significantly after the expiration of the fixed energy price period for the
Navy II partnership. See "Risk Factors-- Future energy payments paid by Edison
to the Coso partnerships will most likely be less than historical energy
payments because they will be paid based on Edison's avoided cost of energy."
Capacity Utilization
For purposes of consistency in financial presentation, the plant capacity
factor for each of the Coso partnerships is based on a nominal capacity amount
of 80 MW (240 MW in the aggregate). The Coso partnerships have a gross
operating margin that allows for the production of electricity in excess of
their nominal capacity amounts. Utilization of this operating margin is based
upon a number of factors and can be expected to vary throughout the year under
normal operating conditions.
The following data includes the operating capacity factor, capacity and
electricity production (in kWh) for each Coso partnership on a stand-alone
basis:
<TABLE>
<CAPTION>
Three months Six months
Year Ended December 31, Ended June 30, Ended June 30,
------------------------- ------------------- -------------------
1996 1997 1998 1999 1998 1999 1998
<S> <C> <C> <C> <C> <C> <C> <C>
Navy I Partnership
(stand-alone)
Operating capacity
factor(a)............ 112.1% 103.2% 94.6%(a) 90.7%(c) 85.5% 83.0%(c) 84.3%
Capacity (MW)
(average)............ 89.92 82.55 75.63(a) 72.53 (c) 68.42 66.41 (c) 67.45
kWh produced (000s)... 787,688 723,116 662,560(a) 158,271 (c) 149,600 287,412 (c) 293,000
BLM Partnership (stand-
alone)
Operating capacity
factor............... 107.9% 99.6% 104.4%(b) 106.8%(b) 102.8% 108.8%(b) 100.3%
Capacity (MW)
(average)............ 86.54 79.66 83.54(b) 85.40 (b) 82.22 87.06 (b) 80.27
kWh produced (000s)... 758,115 697,794 731,767(b) 186,547 (b) 179,000 377,603 (b) 348,700
Navy II Partnership
(stand-alone)
Operating capacity
factor............... 110.6% 108.9% 108.6% 111.9%(d) 102.7% 112.3%(d) 106.5%
Capacity (MW)
(average)............ 88.73 87.08 86.83 89.50 (d) 82.20 89.82 (d) 85.17
kWh produced (000s)... 777,243 762,821 760,659 184,858 (d) 175,282 375,658 (d) 370,000
</TABLE>
- ---------------------
(a) The reduction in the operating capacity factor is due to the transfer of
steam from Navy I to Navy II and indirectly to BLM under the steam sharing
program. See "Business-- Steam Sharing Program" and "Summary Description of
Principal Agreements Relating to the Coso Projects--Steam Exchange and Co-
Tenancy Agreements."
(b) The increase in the operating capacity factor is due to the transfer of
steam from Navy II to BLM under the steam sharing program. See "Business--
Steam Sharing Program."
(c) The reduction in the operating capacity factor is due to the shutdown of
one of Navy I's three turbine generator units, known as Unit 1. See
"Prospectus Summary--Recent Developments--Return to Service of Navy I Unit"
and "Business--Overview of the Coso Projects--Plants--Navy I."
(d) The increase in the operating capacity factor is due to the transfer of
steam from Navy I to Navy II under the steam sharing program. See
"Business--Steam Sharing Program."
80
<PAGE>
Results of Operations for the Three and Six Months Ended June 30, 1999 and 1998
The following discusses the results of operations of the Coso partnerships
for the three and six months ending June 30, 1999 and 1998 (dollar amounts in
tables in thousands, except per kWh data):
Revenue
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
-------------------------------------------------------------- ----------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Operating
Revenues
Navy I partnership..... 12,401 7.8 12,490 8.3 25,609 8.9 23,296 8.0
BLM partnership........ 6,843 3.7 27,013 15.1 28,220 7.4 49,741 14.3
Navy II partnership.... 28,060 15.2 28,009 16.0 52,697 14.0 54,658 14.8
Capacity & Capacity
Bonus
Revenues
Navy I partnership..... 3,232 2.0 3,357 2.2 3,943 1.4 4,170 1.4
BLM partnership........ 3,484 1.9 3,484 1.9 4,711 1.2 4,620 1.3
Navy II partnership.... 3,504 1.9 3,504 2.0 4,738 1.3 4,738 1.3
Energy Revenues
Navy I partnership..... 9,169 5.8 9,133 6.1 21,666 7.5 19,126 6.5
BLM partnership........ 3,359 1.8 23,529 13.1 23,509 6.2 45,121 12.9
Navy II partnership.... 24,556 13.3 24,505 14.0 47,959 12.8 49,920 13.5
</TABLE>
Total operating revenues for the Navy I partnership, which consist of
capacity payments, capacity bonus payments and energy payments made by Edison,
were $12.4 million and $25.6 million for the three and six months ended June
30, 1999, respectively, as compared to $12.5 million and $23.3 million for the
comparable periods in 1998, respectively, a decrease of .8% and an increase of
9.9%, respectively. The Navy I partnership's energy revenues increased to $9.2
million and $21.7 million for the three and six months ended June 30, 1999,
respectively, as compared to $9.1 million and $19.1 million for the comparable
periods in 1998, increases of 1.1% and 13.6%, respectively. The increase for
the six month period ended June 30, 1999 was due to the Navy I partnership's
ability to transfer geothermal steam to the BLM partnership and the Navy II
partnership, both of which were still receiving higher fixed energy prices
under their respective power purchase agreements (the BLM partnership stopped
receiving these higher fixed energy prices in March 1999). For the three and
six months ended June 30, 1999, the Navy I partnership recorded steam transfer
revenues of approximately $3.5 million and $5.4 million, respectively, from the
BLM partnership and $5.0 million and $7.5 million, respectively, from the Navy
II partnership.
Total operating revenues for the BLM partnership were $6.8 million and $28.2
million for the three and six months ended June 30, 1999, respectively, as
compared to $27.0 million and $49.7 million for the comparable periods in 1998,
decreases of 74.8% and 43.3%, respectively. The BLM partnership's energy
revenues decreased to $3.4 million and $23.5 million for the three and six
months ended June 30, 1999, respectively, as compared to $23.5 million and
$45.1 million for the comparable periods in 1998, decreases of 85.5% and 47.9%,
respectively. These significant decreases were due to the expiration of the
fixed energy price period under the BLM partnership's power purchase agreement
in March 1999 and the receipt of energy payments based on Edison's avoided cost
of energy since that time. Until March 1999 and during 1998, the BLM
partnership received approximately 14.6 cents per kWh for energy delivered.
Under the avoided cost of energy formula,
81
<PAGE>
the BLM partnership has been receiving an average of approximately 3.0 cents
per kWh for energy delivered.
Total operating revenues for the Navy II partnership were $28.1 million and
$52.7 million for the three and six months ended June 30, 1999, respectively,
as compared to $28.0 million and $54.7 million for the comparable periods in
1998, an increase of .4% and a decrease of 3.7%, respectively. The Navy II
partnership's energy revenues were $24.6 million and $48.0 million for the
three and six months ended June 30, 1999, respectively, as compared to $24.5
million and $49.9 million for the comparable periods in 1998, an increase of
.4% and a decrease of 3.8%, respectively. The decrease for the six month period
ended June 30, 1999 as compared to 1998, despite a 1.5% increase in kWh
produced over the same period, was due to increased steam transfers from the
Navy I partnership.
Interest and Other Income
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
---------------------------------------------------------------------------------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 247 0.2 157 0.1 1,898 0.7 293 0.1
BLM partnership......... 254 0.1 256 0.1 450 0.1 473 0.1
Navy II partnership..... 577 0.3 461 0.3 883 0.2 780 0.2
</TABLE>
The Navy I partnership's interest and other income were $247,000 and $1.9
million for the three and six months ended June 30, 1999, respectively, as
compared to $157,000 and $293,000 for the comparable periods in 1998. The
increase for the six months ended June 30, 1999 is attributable to the
recording of a $1.6 million business loss insurance recovery during the first
quarter of 1999 in connection with the shutdown of one of the Navy I
partnership's turbine generators units. That unit returned to service in May
1999. See "Prospectus Summary--Recent Developments--Return to Service of Navy I
Unit." The BLM partnership's interest and other income was $254,000 and
$450,000 for the three and six month periods ending June 30, 1999,
respectively, as compared to $256,000 and $473,000 for the same periods in
1998. The Navy II partnership's interest and other income was $577,000 and
$883,000 for the three and six month periods ending June 30, 1999,
respectively, as compared to $461,000 and $780,000 for the same periods in
1998.
Operating Expenses
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
-----------------------------------------------------------------------------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 2,456 1.6 3,673 2.5 7,039 2.4 7,244 2.5
BLM partnership......... 3,912 2.1 5,298 3.0 9,555 2.5 10,815 3.1
Navy II partnership..... 3,117 1.7 4,314 2.5 7,605 2.0 8,670 2.3
</TABLE>
The Navy I partnership's operating expenses, including operating and general
and administrative expenses, were $2.5 million and $7.0 million for the three
and six months ended June 30, 1999, respectively, as compared to $3.7 million
and $7.2 million for the comparable periods in 1998, decreases of 32.4% and
2.8%, respectively. The BLM partnership's operating expenses, including
operating and general and administrative expenses, were $3.9 million and $9.6
million for the three and six months ended June 30, 1999, respectively, as
compared to $5.3 million and $10.8 million for
82
<PAGE>
the comparable periods in 1998, decreases of 26.5% and 11.1%, respectively. The
Navy II partnership's operating expenses, including operating and general and
administrative expenses, were $3.1 million and $7.6 million for the three and
six months ended June 30, 1999, respectively, as compared to $4.3 million and
$8.7 million for the comparable periods in 1998, decreases of 27.9% and 12.6%,
respectively. The decreases for each partnership for the three months and six
months ended June 30, 1999 as compared to 1998 was due in large part to a
significant reduction in operator and management committee fees due to the
replacement of the Coso projects prior operator and managing partner.
Royalty Expenses
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
---------------------------------------------------------------------------------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 2,134 1.3 1,482 1.0 3,572 1.2 2,377 0.8
BLM partnership......... 332 0.2 2,724 1.5 2,271 0.6 4,825 1.4
Navy II partnership..... 2,872 1.6 2,620 1.5 5,742 1.5 5,400 1.5
</TABLE>
The Navy I partnership's royalty expenses were $2.1 million and $3.6 million
for the three and six months ended June 30, 1999, respectively, as compared to
$1.5 million and $2.4 million for the comparable periods in 1998, increases of
40.0% and 50.0%, respectively. These increases were due to the combination of
increased steam sharing revenues over the same period, and a scheduled increase
in the royalty rate paid to the Navy in November 1998 from 10% to 15%. The BLM
partnership's royalty expenses, were $332,000 and $2.3 million for the three
and six months ended June 30, 1999, respectively as compared to $2.7 million
and $4.8 million for the comparable periods in 1998, decreases of 87.7% and
52.1%, respectively. This decrease was due to a reduction in BLM partnership
revenues caused by the expiration of the fixed energy price period under the
BLM
partnership's power purchase agreement in March 1999 and the receipt of energy
payments under Edison's avoided cost of energy since that time. The Navy II
partnership's royalty expense were $2.9 million and $5.7 million for the three
and six months ended June 30, 1999, respectively, as compared to $2.6 million
and $5.4 million for the comparable periods in 1998 increases of 11.5% and
5.6%, respectively. These increases were due to increased purchases of steam
sales from the Navy I partnership over the period.
Depreciation and Amortization
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Six Months
June 30, June 30, Ended June 30, Ended June 30,
------------------------------------------------------------- ---------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 2,391 1.5 2.954 2.0 4,778 1.7 5,911 2.0
BLM partnership......... 3,912 2.1 3,640 2.0 7,637 2.0 7,264 2.1
Navy II partnership..... 3,566 1.9 3,523 2.0 7,093 1.9 7,016 1.9
</TABLE>
The Navy I partnership's depreciation and amortization expense was $2.4
million and $4.8 million for the three and six months ended June 30, 1999,
respectively, as compared to $3.0 million and $5.9 million for the comparable
periods in 1998, decreases of 20.0% and 18.6%, respectively. These decreases
were primarily due to the cessation of depreciation expenses for certain wells
which became fully depreciated during these periods. The BLM partnership's
depreciation and amortization expense was $3.9 million and $7.6 million for the
three and six months ended June 30, 1999, respectively as compared to $3.6
million and $7.3 million for the comparable periods in 1998.
83
<PAGE>
The Navy II partnership's depreciation and amortization expense was $3.6
million and $7.1 million for the three and six months ended June 30, 1999 as
compared to $3.5 million and $7.0 million for the comparable periods in 1998.
The changes in depreciation and amortization expense for each of the BLM
partnership and Navy II Partnership are insignificant over the two periods.
Operating Income
<TABLE>
<CAPTION>
Three Months Ended Three Months Ended Six Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
--------------------------------------------------------------- ----------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 5,667 3.6 4,538 3.0 12,118 4.2 8,057 2.7
BLM partnership......... (1,059) -0.6 15,607 8.7 9,207 2.4 27,310 7.8
Navy II partnership..... 19,082 10.3 18,013 10.3 33,140 8.8 34,352 9.3
</TABLE>
The Navy I partnership's operating income was $5.6 million and $12.1 million
for the three and six months ended June 30, 1999, respectively, as compared to
$4.5 million and $8.1 million for the comparable periods in 1998, increases of
24.4% and 49.4%, respectively. These increases were due to the combination of
increased interest and other income, and decreased plant operations and
depreciation and amortization costs, somewhat offset by increased royalty
expenses. The BLM partnership's operating loss was $1.0 million and operating
income was $9.2 million for the three and six months ended June 30, 1999,
respectively as compared to operating income of $15.6 million and $27.3 million
for the comparable periods in 1998, decreases of 106.4% and 66.3%,
respectively. These decreases were mainly due to a reduction in energy revenues
due to the expiration of the fixed energy price period under the BLM
partnership's power purchase agreement. The Navy II partnership's operating
income was $19.1 million and $33.1 million for the three and six months ended
June 30, 1999, respectively as compared to $18.0 million and $34.4 million for
the comparable periods in 1998, an increase of 6.1% and a decrease of 3.8%,
respectively. This increase in operating income for the three months ended
June 30, 1999 was due to an increase in interest and other income and a
reduction in operating expenses.
Interest and Other Expense
<TABLE>
<CAPTION>
Three months Three months Six months Six months
Ended June 30, Ended June 30, Ended June 30, Ended June 30,
--------------- --------------- --------------- ---------------
1999 1998 1999 1998
$ c per kWh $ c per kWh $ c per kWh $ c per kWh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Navy I partnership...... 4,322 2.7 1,108 0.7 6,615 1.9 2,232 0.8
BLM partnership......... 3,631 1.9 1,770 1.0 5,480 1.8 3,556 1.0
Navy II partnership..... 4,654 2.5 2,217 1.3 7,399 2.0 4,452 1.2
</TABLE>
The Navy I partnership's interest expense, was $1.6 million and $2.6 million
for the three and six months ended June 30, 1999 respectively, as compared to
$1.1 million and $2.2 million for the comparable periods in 1998, increases of
45.5% and 18.2%, respectively. These increases were due to higher outstanding
debt balances resulting from the $413 million senior secured financing which
closed on May 28, 1999. The BLM partnership's interest expense, was $1.6
million and $2.5 million for the three and six months ended June 30, 1999,
respectively as compared to $1.8 million and $3.6 million for the comparable
periods in 1998, decreases of 11.1% and 30.6% for the three and six months
ended June 30, 1999. The Navy II partnership's interest expense was $1.9
million and $3.3 million for the three and six months ended June 30, 1999,
respectively, as compared to $2.2 million and $4.5 million for the comparable
periods in 1998, decreases of 13.6% and 26.6%, respectively. The decreases in
BLM and Navy II were primarily due to the lower average outstanding debt
balance.
84
<PAGE>
The Navy I, BLM and Navy II partnerships incurred interest expense on the
acquisition debt of $1.3 million, $1.0 million and $1.4 million, respectively
for the three months ended June 30, 1999 and $2.0 million, $1.4 million, and
$2.0 million, respectively, for the six months ended June 30, 1999. This
interest expense related to acquisition debt in the amount of $211.5 million
incurred on February 25, 1999 to acquire the interests of CalEnergy in the Coso
partnerships. This acquisition debt was repaid with the proceeds of the $413.0
million senior secured financing on May 28, 1999.
The Navy I, BLM and Navy II partnerships incurred other expenses related to
the acquisition debt of $1.4 million, $1.1 million and $1.4 million,
respectively, for the three months ended June 30, 1999 and $2.0 million, $1.5
million and $2.1 million, respectively for the six months ended June 30, 1999.
These other expenses, which consist primarily of lending, legal and other fees,
related to the acquisition debt in the amount of $211.5 million incurred on
February 25, 1999 to acquire the interests of CalEnergy in the Coso
partnerships. This acquisition debt was repaid with the proceeds of the $413.0
million senior secured financing on May 28, 1999.
Extraordinary Item--Loss on Early Extinguishment of Debt
The Navy I partnership, the BLM partnership and the Navy II partnership
recorded losses on the early extinguishment of previous debt in the amounts of
$2.4 million, $1.8 million and $2.1 million, respectively, for the six months
ended June 30, 1999. This loss was due to a premium and other costs incurred to
pay the existing senior secured debt of the Coso partnerships before its
scheduled maturity date. These costs included tender premiums paid to the
holders of the previous debt and the write off of the remaining balance of
deferred financing costs related to the issuance of the previous debt. The
previous debt was repaid with the proceeds from the Series A notes offering.
Results of Operations for the Years Ended December 31, 1996, 1997 and 1998
Total Operating Revenues
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership...... $118,206 15.0c $100,431 13.9c $ 53,153 8.0c
BLM partnership......... 101,923 13.4 102,868 14.7 107,199 14.6
Navy II partnership..... 115,126 14.8 112,796 14.8 119,564 15.7
</TABLE>
Capacity and Capacity Bonus Revenues
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.... $14,266 1.8c $13,845 1.9c $13,573 2.0c
BLM partnership....... 13,938 1.8 13,939 2.0 13,847 1.9
Navy II partnership... 14,018 1.8 14,018 1.8 14,018 1.8
</TABLE>
Energy Revenues
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.. $103,940 13.2c $86,586 12.0c $ 39,580 6.0c
BLM partnership..... 87,985 11.6 88,929 12.7 93,352 12.8
Navy II partnership. 101,108 13.0 98,778 12.9 105,546 13.9
</TABLE>
85
<PAGE>
Total operating revenues for the Navy I partnership, which consist of
capacity payments, capacity bonus payments and energy payments made by Edison,
decreased to $53.2 million for the year ended December 31, 1998, from $100.4
million in 1997, a decrease of 47.1%. The Navy I partnership's energy revenues
decreased to $39.6 million for the year ended December 31, 1998, from $86.6
million in 1997, a decrease of 54.3%. These decreases were attributable to the
expiration of the fixed energy price period under the Navy I partnership's
power purchase agreement and are the result of a full year of energy payments
based upon Edison's avoided cost of energy after the fixed energy price period
expired in August 1997. During the final year of its fixed energy price period,
the Navy I partnership received approximately 14.6c per kWh for energy
delivered. Under the avoided cost of energy formula, since August 1997, the
Navy I partnership has been receiving an average of approximately 3.0c per kWh
for energy delivered. This significant decrease in energy payments was
partially offset by the Navy I partnership's ability to transfer geothermal
steam to the BLM partnership and the Navy II partnership, both of which were
still receiving fixed energy payments under their respective power purchase
agreements through December 31, 1998. For the year ended December 31, 1998, as
a result of its transfers of steam under the steam sharing program, the Navy I
partnership received steam transfer payments of approximately $13.5 million
from the BLM partnership and $5.5 million from the Navy II partnership.
The BLM partnership's total operating revenues increased to $107.2 million
for the year ended December 31, 1998, from $102.9 million in 1997, an increase
of 4.2%. The BLM partnership's energy revenues increased to $93.4 million for
the year ended December 31, 1998, from $88.9 million in 1997, an increase of
5.0%. These increases were due to a 1.0c per kWh increase in the rate paid by
Edison under the BLM partnership's power purchase agreement. In addition, kWh
produced increased, primarily due to increased steam transfers from the Navy I
partnership. However, the impact from such increased production was offset by
steam sharing payments paid by the BLM partnership to the Navy I partnership.
The Navy II partnership's total operating revenues increased to $119.6
million for the year ended December 31, 1998, from $112.8 million in 1997, an
increase of 6.0%. The Navy II partnership's energy revenues increased to $105.5
million for the year ended December 31, 1998, from $98.8 million in 1997, an
increase of 6.9%. These increases were due primarily to an increase in the rate
paid by Edison under the Navy II partnership's power purchase agreement. The
Navy II partnership was paid 14.6c per kWh in 1998 for the energy component of
the electricity it sold to Edison, up from 13.6c per kWh in 1997.
Total operating revenues for the Navy I partnership decreased to $100.4
million for the year ended December 31, 1997, from $118.2 million in 1996, a
decrease of 15.0%. The Navy I partnership's energy revenues decreased to $86.6
million for the year ended December 31, 1997, from $103.9 million in 1996, a
decrease of 16.7%. These decreases were attributable to Edison's cessation of
energy payments based on the fixed energy price period under the Navy I
partnership's power purchase agreement and are the result of a partial year of
energy payments based upon Edison's avoided cost of energy, rather than the
fixed energy price, since August 1997. In 1997, prior to the end of the fixed
energy price period, the Navy I partnership received approximately 14.6c per
kWh for its energy production. Under the avoided cost of energy formula, the
Navy I partnership received an average of approximately 3.0c per kWh of energy
delivered. This drop in energy prices was partially offset by the Navy I
partnership's ability to transfer steam to the BLM partnership and the Navy II
partnership under the steam sharing program, both of which were still being
paid fixed energy prices under their respective power purchase agreements
during the remainder of 1997. For
86
<PAGE>
the year ended December 31, 1997, the Navy I partnership received steam
transfer payments of approximately $6.0 million from the BLM partnership and
approximately $5.1 million from the Navy II partnership.
The BLM partnership's total operating revenues increased slightly to $102.9
million for the year ended December 31, 1997, from $101.9 million in 1996, an
increase of 0.9%. The BLM partnership's energy revenues increased slightly to
$88.9 million for the year ended December 31, 1997, from $88.0 million in 1996,
an increase of 1.1%. Total operating revenues and energy revenues increased
despite an 8.0% decrease in kWh produced due to a 1.0c per kWh increase in the
rate paid by Edison under the BLM partnership's power purchase agreement.
The Navy II partnership's total operating revenues decreased to $112.8
million for the year ended December 31, 1997, from $115.1 million in 1996, a
decrease of 2.0%. The Navy II partnership's energy revenues decreased to $98.8
million for the year ended December 31, 1997, from $101.1 million in 1996, a
decrease of 2.3%. The decreases in the Navy II partnership's total operating
revenues and energy revenues were due to a 1.9% decrease in kWh produced by the
Navy II partnership over the same period and increased steam sharing payments
to the Navy I partnership, partially offset by a 1.0c per kWh increase in the
rate paid by Edison under the Navy II partnership's power purchase agreement.
Interest Income
<TABLE>
<CAPTION>
Year Ended December
31,
--------------------
1996 1997 1998
(in thousands)
<S> <C> <C> <C>
Navy I partnership...................................... $3,286 $1,980 $ 585
BLM partnership......................................... 2,520 1,712 1,181
Navy II partnership..................................... 3,174 2,187 1,799
</TABLE>
The Navy I partnership's interest income decreased to $585,000 for the year
ended December 31, 1998, from $2.0 million in 1997, a decrease of 70.5%. The
BLM partnership's interest income decreased to $1.2 million for the year ended
December 31, 1998, from $1.7 million in 1997, a decrease of 31.0%. The Navy II
partnership's interest income decreased to $1.8 million for the year ended
December 31, 1998, from $2.2 million in 1997, a decrease of 17.7%. These
decreases were due to the replacement of a cash funded debt service reserve
fund with a letter of credit in 1997 and to a generally lower interest rate
environment.
The Navy I partnership's interest income decreased to $2.0 million for the
year ended December 31, 1997, from $3.3 million in 1996, a decrease of 39.7%.
The BLM partnership's interest income decreased to $1.7 million for the year
ended December 31, 1997, from $2.5 million in 1996, a decrease of 32.1%. The
Navy II partnership's interest income decreased to $2.2 million for the year
ended December 31, 1997, from $3.2 million in 1996, a decrease of 31.1%. These
decreases were due to the replacement of a cash funded debt reserve fund with a
letter of credit in 1997.
Operating Expenses
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.... $11,763 1.5c $11,329 1.6c $13,298 2.0c
BLM partnership....... 18,266 2.4 18,830 2.7 19,887 2.7
Navy II partnership... 13,371 1.7 13,146 1.7 15,508 2.0
</TABLE>
87
<PAGE>
The Navy I partnership's operating expenses, including operating and general
and administrative expenses, increased to $13.3 million for the year ended
December 31, 1998, from $11.3 million in 1997, an increase of 17.4%. The BLM
partnership's operating expenses, including operating and general and
administrative expenses, increased to $19.9 million for the year ended December
31, 1998, from $18.8 million in 1997, an increase of 5.6%. The Navy II
partnership's operating expenses, including operating and general and
administrative expenses, increased to $15.5 million for the year ended December
31, 1998, from $13.1 million in 1997, an increase of 18.0%. These increases
were due primarily to legal expenses incurred by each of the Coso partnerships
in connection with the Edison litigation described in "Business--Legal
Proceedings." The Navy I partnership's operating expenses, exclusive of these
legal expenses, decreased to $10.3 million for the year ended December 31,
1998, from $11.3 million in 1997, a decrease of 8.8%. The BLM partnership's
operating expenses, exclusive of these legal expenses, decreased to $16.9
million for the year ended December 31, 1998, from $18.2 million in 1997, a
decrease of 6.9%. The Navy II partnership's operating expenses, exclusive of
these legal expenses, decreased to $12.6 million for the year ended December
31, 1998, from $13.1 million in 1997, a decrease of 4.5%. The decreases in
operating expenses, exclusive of the legal expenses incurred in connection with
the Edison litigation, were due in large part to a favorable property tax
appeal and settlement with Inyo County.
Following Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Coso partnerships retained FPL Operating and Coso
Operating Company to operate and maintain the Coso projects. As a result of the
change in operators and the restructuring of operator fees, the aggregate
annual fees to be paid by the Coso partnerships to FPL Operating and Coso
Operating Company under their respective O&M agreements have been reduced from
approximately $7.5 million, which had been paid to the prior operator in 1998,
to $2.0 million. Payment of these reduced operator fees are subordinated to all
payments to be made under the senior secured notes. See "Business--Operating
Strategy." As discussed under "Prospectus Summary--Recent Developments--
Purchase of FPL Interests; Assignment of FPL O&M Agreements," FPL Operating is
currently expected to assign to Coso Operating Company all of its rights under
FPL Operating's O&M agreements, and Coso Operating Company is currently
expected to assume all of FPL Operating's duties and obligations under those
O&M agreements. Coso Operating Company will thereby become the sole operator of
all of the plants and fields located at the Coso projects and will be entitled
to receive from and after the assignments, as the successor operator, the O&M
fees due under the FPL Operating O&M agreements. See "Business--Operations and
Maintenance."
The Navy I partnership's operating expenses, exclusive of the legal expenses
incurred in connection with the Edison litigation, decreased slightly to $11.3
million for the year ended December 31, 1997, from $11.8 million in 1996, a
decrease of 3.7%. The BLM partnership's operating expenses, exclusive of these
legal expenses, decreased to $18.2 million for the year ended December 31,
1997, from $18.3 million in 1996, a decrease of 0.5%. The Navy II partnership's
operating expenses, exclusive of these legal expenses, decreased to $13.1
million for the year ended December 31, 1997, from $13.4 million in 1996, a
decrease of 1.7%.
Royalty Expenses
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.... $11,059 1.4c $ 9,849 1.4c $ 6,824 1.0c
BLM partnership....... 7,820 1.0 10,106 1.4 10,492 1.4
Navy II partnership... 11,486 1.5 11,249 1.5 11,868 1.6
</TABLE>
88
<PAGE>
The Navy I partnership's royalty expense decreased to $6.8 million for the
year ended December 31, 1998, from $9.8 million in 1997, a 30.7% decrease. This
decrease was due to the Navy I partnership's decrease in revenues over the same
period. The BLM partnership's royalty expense increased to $10.5 million for
the year ended December 31, 1998, from $10.1 million in 1997, a 3.8% increase.
This was due to the increased revenues generated by the BLM partnership over
the period. The BLM partnership's royalty expenses for the year ended December
31, 1998 includes $3.1 million of royalties payable to Coso Land Company. The
BLM partnership's royalty expenses for the year ended December 31, 1997
includes $3.2 million of royalties payable to Coso Land Company. Coso Land
Company is one of our affiliates. The royalties payable by the BLM partnership
to Coso Land Company were $20.7 million as of December 31, 1998 and $17.7
million as of December 31, 1997. No portion of the royalties that are payable
to Coso Land Company has been paid. The royalties owed by the BLM partnership
to the Coso Land Company are subordinated to all payments to be made under the
senior secured notes. The Navy II partnership's royalty expenses increased to
$11.9 million for the year ended December 31, 1998, from $11.2 million in 1997,
an increase of 5.5%. This increase was due to a similar increase in revenues
generated by the Navy II partnership.
The Navy I partnership's royalty expenses decreased to $9.8 million for the
year ended December 31, 1997, from $11.1 million in 1996, a 10.9% decrease.
This was due to the Navy I partnership's decrease in total operating revenues
in 1997. The BLM partnership's royalty expenses increased to $10.1 million for
the year ended December 31, 1997, from $7.8 million in 1996, a 29.2% increase.
This increase was due to the settlement with the Bureau of Land Management in
1996 over the calculation of past royalties. The Navy II partnership's royalty
expenses decreased to $11.2 million for the year ended December 31, 1997, from
$11.5 million in 1996, a 2.1% decrease. This decrease was caused by a similar
decrease in the Navy II partnership's total operating revenues in 1997.
Depreciation and Amortization
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.... $13,325 1.7c $12,814 1.8c $11,772 1.8c
BLM partnership....... 13,931 1.8 14,257 2.0 14,308 2.0
Navy II partnership... 13,054 1.7 13,354 1.8 13,744 1.8
</TABLE>
The Navy I partnership's depreciation and amortization expenses decreased to
$11.8 million for the year ended December 31, 1998, from $12.8 million in 1997,
a decrease of 8.1%. This decrease was primarily due to the cessation of
depreciation expense for certain wells which became fully depreciated during
these periods. The BLM partnership's depreciation and amortization expenses
increased to $14.3 million for the year ended December 31, 1998, from $14.3
million for the year ended December 31, 1997, an increase of 0.4%. The Navy II
partnership's depreciation and amortization expenses increased to $13.7 million
for the year ended December 31, 1998, from $13.4 million in 1997, an increase
of 2.9%.
The Navy I partnership's depreciation and amortization expenses decreased to
$12.8 million for the year ended December 31, 1997, from $13.3 million in 1996,
a decrease of 3.8%. The BLM partnership's depreciation and amortization
expenses increased to $14.3 million for the year ended December 31, 1997, from
$13.9 million in 1996, an increase of 2.3%. The Navy II partnership's
depreciation and amortization expenses increased to $13.4 million for the year
ended December 31, 1997, from $13.1 million in 1996, an increase of 2.3%.
89
<PAGE>
Interest Expense
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership...... $ 8,868 1.1c $ 6,260 0.9c $4,333 0.7c
BLM partnership......... 13,162 1.7 9,105 1.3 6,267 0.9
Navy II partnership..... 12,149 1.6 10,532 1.4 8,122 1.1
</TABLE>
The Navy I partnership's interest expenses decreased to $4.3 million for the
year ended December 31, 1998, from $6.3 million in 1997, a decrease of 30.8%.
The BLM partnership's interest expenses decreased to $6.3 million for the year
ended December 31, 1998, from $9.1 million in 1997, a decrease of 31.2%. The
Navy II partnership's interest expenses decreased to $8.1 million for the year
ended December 31, 1998, from $10.5 million in 1997, a decrease of 22.9%. These
decreases were due to a decrease in the amounts owed under the then existing
project debt that was repaid at the closing of the Series A notes offering. See
"Prospectus Summary--Recent Developments."
The Navy I partnership's interest expenses decreased to $6.3 million for the
year ended December 31, 1997, from $8.9 million in 1996, a decrease of 29.4%.
The BLM partnership's interest expenses decreased to $9.1 million for the year
ended December 31, 1997, from $13.2 million in 1996, a decrease of 30.8%. The
Navy II partnership's interest expenses decreased to $10.5 million for the year
ended December 31, 1997, from $12.1 million in 1996, a decrease of 13.3%. These
decreases were due to a decrease in the amounts owed under the then existing
project debt that was repaid at the Series A notes offering. See "Prospectus
Summary--Recent Developments."
Net Income
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1996 1997 1998
$ c per kWh $ c per kWh $ c per kWh
(In thousands, except for per kWh data)
<S> <C> <C> <C> <C> <C> <C>
Navy I partnership.... $76,477 9.7c $62,159 8.6c $16,588 2.5c
BLM partnership....... 51,264 6.8 52,282 7.5 56,473 7.7
Navy II partnership... 68,240 8.8 66,702 8.7 70,457 9.3
</TABLE>
The Navy I partnership's net income decreased significantly to $16.6 million
for the year ended December 31, 1998, from $62.2 million in 1997, a decrease of
73.3%. The Navy I partnership's net income decreased significantly to $62.2
million for the year ended December 31, 1997, from $76.5 million in 1996, a
decrease of 18.7%. The decreases in net income for these periods are due to the
expiration of the fixed energy price period under the Navy I partnership's
power purchase agreement in August 1997. See "Risk Factors--The Coso
partnerships and their managing partners are currently involved in material
litigation with Edison, their sole customer" and "Business--Legal Proceedings."
The BLM partnership's net income increased to $56.5 million for the year
ended December 31, 1998, from $52.3 million in 1997, an increase of 8.0%. The
BLM partnership's net income increased to $52.3 million for the year ended
December 31, 1997, from $51.3 million in 1996, an increase of 2.0%. The
increases in net income for these periods are due primarily to increases in the
BLM partnership's total operating revenues during these periods.
90
<PAGE>
The Navy II partnership's net income increased to $70.5 million for the year
ended December 31, 1998, from $66.7 million in 1997, an increase of 5.6%. The
increase in net income for this period is due primarily to increases in the
Navy II partnership's total operating revenues during this period. The Navy II
partnership's net income decreased to $66.7 million for the year ended December
31, 1997, from $68.2 million in 1996, a decrease of 2.3%. The decrease in net
income for this period is due primarily to a decrease in the Navy II
partnership's total operating revenues during this period.
Liquidity and Capital Resources
Each of the Navy I partnership, the BLM partnership and the Navy II
partnership derive substantially all of its cash flow from Edison under their
respective power purchase agreements and from interest income earned on funds
on deposit. The Coso partnerships have used their cash primarily for capital
expenditures for power plant improvements, resource and development costs,
distributions to partners and payments with respect to the project debt.
The following table sets forth a summary of each Coso partnership's cash
flows for the six months ended June 30, 1999 and June 30, 1998.
<TABLE>
<CAPTION>
Six Months Ended
June 30,
--------------------
1999 1998
<S> <C> <C>
Navy I partnership (stand alone)
Net cash provided by operating activities............... $ 9,308 $ 13,475
Net cash used in investing activities................... $ (21,732) $ (2,566)
Net cash provided (used) by financing activities........ $ 15,473 $ (13,013)
--------- ---------
Net change in cash and cash equivalents............... $ 3,049 $ (2,104)
BLM partnership (stand alone)
Net cash provided by operating activities............... $ 19,177 $ 31,253
Net cash used in investing activities................... $ (15,360) $ (8,742)
Net cash provided (used) by financing activities........ $ 4,336 $ (20,755)
--------- ---------
Net change in cash and cash equivalents............... $ 8,153 $ 1,756
Navy II partnership (stand alone)
Net cash provided by operating activities............... $ 28,957 $ 36,048
Net cash used in investing activities................... $ (20,594) $ (2,735)
Net cash provided (used) by financing activities........ $ 3,841 $ (33,212)
--------- ---------
Net change in cash and cash equivalents............... $ 12,204 $ 101
</TABLE>
The Navy I partnership's net cash flows from operating activities decreased
from the six months ended June 30, 1998 to June 30, 1999 by approximately $4.2
million, primarily due to financial costs associated with the short term debt
obtained to complete the purchase of CalEnergy's interest in the Navy I
partnership.
Cash flows from investing activities at the Navy I partnership decreased from
the six months ended June 30, 1998 to June 30, 1999 by approximately $19.2
million, primarily due to the increase in restricted cash associated with the
project loan made by us.
The Navy I partnership's cash flows from financing activities have fluctuated
as a result of the project loan made by us and increased distributions to
partners.
The BLM partnership's net cash flows from operating activities decreased from
six months ended June 30, 1998 to June 30, 1999 by approximately $12.1 million,
primarily due to financing
91
<PAGE>
costs associated with the short term debt obtained to complete the purchase of
CalEnergy's interest in the BLM partnership and a decrease in the trade
receivables due to the switch to avoided cost.
Cash flows from the investing activities at the BLM partnership increased
from the six months ended June 30, 1998 to June 30, 1999 by approximately $6.6
million primarily due to the increase in restricted cash associated with the
project loan made by us.
The BLM partnership's cash flows from financing activities have fluctuated as
a result of the project loan made by us and increased distributions to
partners.
The Navy II partnership's net cash flows from operating activities decreased
from the six months ended June 30, 1998 to June 30, 1999 by approximately $7.1
million, primarily due to financing costs associated with the short term debt
obtained to complete the purchase of CalEnergy's interest in the Navy II
partnership and a write off of related party receivables due to Caithness
Acquisition purchase of CalEnergy's interest.
Cash flows from investing activities at the Navy II partnership increased
from the six months ended June 30, 1998 to June 30, 1999 by approximately $17.8
million primarily due to the increase in restricted cash associated with the
project loan from us.
The Navy II partnership's cash flows from financing activities have
fluctuated as a result of the project loan made by us and increased
distributions to partners.
The following table sets forth a summary of each Coso partnership's cash
flows for the years ended December 31, 1996, 1997 and 1998:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
<S> <C> <C> <C>
Navy I partnership (stand-alone)
Net cash flows from operating activities... $ 83,779 $ 88,540 $ 32,163
Net cash flows from investing activities... (3,149) 17,948 (7,728)
Net cash flows from financing activities... (109,999) (119,324) (27,323)
--------- --------- --------
Net change in cash......................... $ (29,369) $ (12,836) $ (2,888)
========= ========= ========
<CAPTION>
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
<S> <C> <C> <C>
BLM partnership (stand-alone)
Net cash flows from operating activities... $ 64,335 $ 60,948 $ 75,520
Net cash flows from investing activities... (5,798) 19,280 (20,302)
Net cash flows from financing activities... (85,590) (92,521) (56,091)
--------- --------- --------
Net change in cash......................... $ (27,053) $ (12,293) $ (873)
========= ========= ========
<CAPTION>
Year Ended December 31,
------------------------------
1996 1997 1998
(In thousands)
<S> <C> <C> <C>
Navy II partnership (stand-alone)
Net cash flows from operating activities... $ 74,611 $ 80,660 $ 84,762
Net cash flows from investing activities... (3,883) 14,399 (6,939)
Net cash flows from financing activities... (97,316) (112,044) (78,153)
--------- --------- --------
Net change in cash......................... $ (26,588) $ (16,985) $ (330)
========= ========= ========
</TABLE>
92
<PAGE>
The Navy I partnership's net cash flows from operating activities decreased
by approximately $56.4 million from 1997 to 1998. This decrease was primarily
due to a decrease in revenues for the Navy I partnership in 1998 in which the
Navy I partnership received a full year of energy payments from Edison based
upon Edison's avoided cost of energy. Edison has taken the position that the
fixed energy price period expired in August 1997 for the Navy I partnership and
in March 1999 for the BLM partnership, and will expire in January 2000 for the
Navy II partnership. See "Risk Factors--The Coso partnerships and their
managing partners are currently involved in material litigation with Edison,
their sole customer," "--General" and "Business--Legal Proceedings." The
expiration of the fixed energy price period for the BLM partnership and the
Navy II partnership and the concomitant switch to payments by Edison based upon
its avoided cost of energy is likely to have a material adverse effect on net
cash flows from operating activities of those two Coso partnerships as well.
However, future cash flows from operating activities generated from revenues
under the Coso partnerships' power purchase agreements, plus any subsidy
payments that the Coso partnerships may receive under AB1890 through 2001 are
expected to be sufficient to fund operating expenses, royalty expenses
(including the Navy I partnership's obligations to make payments to the Navy
sinking fund), payments of interest and principal on the senior secured notes
and capital expenditures.
Cash flows from investing activities at the Navy I partnership decreased from
1997 to 1998 by approximately $25.7 million, primarily due to the release in
1997 of approximately $22.5 million, held in a debt service reserve fund, and
further decreased by an increase in capital expenditures in 1998 as compared to
1997. The increase from 1996 to 1997 in cash flows from investing activities of
approximately $21.1 million is due to the same factors.
Cash flows from investing activities at the BLM partnership decreased from
1997 to 1998 by approximately $39.6 million, primarily due to the release in
1997 of approximately $23.0 million held in a debt service reserve fund, and
further decreased by an increase in capital expenditures of $16.6 million in
1998 as compared to 1997. The increase in capital expenditures by the BLM
partnership in 1998 is due to the drilling of new wells and other capital
expenditures relating to the steam sharing program. The increase from 1996 to
1997 in cash flows from investing activities of approximately $25.1 million is
also due to the release in 1997 of the cash held in the debt service reserve
fund, further increased by a decrease in capital expenditures in 1997 as
compared to 1996 of approximately $2.3 million.
Cash flows from investing activities at the Navy II partnership decreased
from 1997 to 1998 by approximately $21.3 million, primarily due to the release
in 1997 of approximately $22.4 million held in a debt service reserve fund,
partially offset by a decrease in capital expenditures in 1998 as compared to
1997. The increase from 1996 to 1997 in cash flows from investing activities of
approximately $18.3 million is also due to the release in 1997 of the cash held
in the debt service reserve fund partially offset by an increase in capital
expenditures in 1997 as compared to 1996.
The increase in the Coso partnerships' cash flows from investing activities
in 1997, as compared to 1996, was due to the release of the debt service
reserve fund in February 1997, offset somewhat by higher capital expenditures
in 1997, as compared to 1996.
The Coso partnerships' cash flows from financing activities have fluctuated
primarily as a result of cash distributions made to their partners. See
"Certain Relationships and Related Transactions--Distributions to Caithness
Energy and CalEnergy."
A portion of the proceeds from the Series A notes offering was used to
initially fund a Debt Service Reserve Account in the amount of $50.0 million.
Amounts deposited in the Debt Service
93
<PAGE>
Reserve Account will be available to pay principal of and interest on the
senior secured notes if we are not able to meet our obligations to make those
payments. See "Description of Series B Notes--Debt Service Reserve Account."
The amount of funds held in the Debt Service Reserve Account will increase or
decrease from time to time and will equal the amount of the scheduled principal
and interest payment due on the senior secured notes for the immediately
succeeding six months.
The Navy I partnership is obligated to pay the Navy the sum of $25.0 million
on or before December 31, 2009, the expiration date of the term of the Navy
Contract. Payment of the obligation will be made from an established sinking
fund to which the Navy I partnership has been making payments since 1987. As of
June 30, 1999, there was approximately $7.9 million on deposit in this sinking
fund, representing both sinking fund payments made by the Navy I partnership
and accrued interest thereon. The Navy I partnership intends to make aggregate
annual payments to this sinking fund of approximately $716,000 through 2009
with cash flows generated from operating activities. See "Business--Royalty and
Revenue-Sharing Arrangements--Navy I."
The Coso partnerships have established a Capital Expenditure Reserve Account
which will be funded semi-annually in accordance with each Coso partnership's
operating budget and schedules thereto approved by our independent engineer.
The Capital Expenditure Reserve Account is pledged as security for the senior
secured notes. See "Description of Series B Notes--Capital Expenditure Reserve
Account." As of June 30, 1999, aggregate capital expenditures of the Coso
partnerships for the remaining balance of 1999 were expected to be
approximately $13.5 million, based on each Coso partnership's operating budget.
Year 2000 Issue
The Year 2000 issue refers to the fact that certain management information
and operating systems use two-digit data fields which recognize dates using the
assumption that the first two digits are "19" (for example, the number 98 is
recognized as the year 1998). When the year 2000 occurs, these systems could
interpret the year 2000 as 1900, which, in turn, could result in system
failures or miscalculations. This could cause disruptions of operations at the
Coso projects and at Edison, the Coso partnerships' sole customer.
The Coso partnerships have implemented a comprehensive program to address the
potential impact of the Year 2000 issue. This program involves several stages,
including inventory and impact assessment, remediation, testing and
implementation. The inventory and impact assessment of the information
technology infrastructure, computer applications and computerized processes
embedded in certain operating equipment has been completed, and the necessary
modifications have been remediated, tested and implemented.
The Coso partnerships depend substantially for their operating revenues on
Edison's purchase of all electrical energy generated by the plants. If Edison
fails to fulfill its contractual obligations under the power purchase
agreements because it has failed to resolve its own Year 2000 issues, it could
have a material adverse effect on the Coso partnerships' revenues and ability
to make payments on the senior secured notes and guarantees. The Coso
partnerships have contacted Edison. Edison indicated that its Year 2000 program
will be completed by December 31, 1999. Further, Edison has reported in its
1998 annual report that its informational and operational systems have been
assessed, and detailed plans have been developed to address modifications
required to be completed, tested and operational by December 31, 1999. The Coso
partnerships will continue to contact Edison in an effort to minimize any
potential Year 2000 compliance impact, however, it is not possible to guarantee
Edison's compliance. Edison and other third parties might fail to resolve
timely their own Year 2000 issues, or might experience delays or changes in the
estimated time it takes to fix these problems.
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The total costs expended to date for the Year 2000 program has been minimal.
The Coso partnerships expect to incur a nominal amount in the future to make
their computer systems Year 2000 compliant.
The Coso partnerships' Year 2000 contingency planning is currently underway
to address risk scenarios at the operating level (such as generation and
transmission), as well as at the business level (such as procurement and
accounting) and include developing strategies for dealing with the most
reasonably likely worst case scenario concerning Year 2000-related processing
failures or malfunctions caused by internal systems that would include a
temporary disruption of service to Edison or the possible disruption of
electricity sales to Edison due to Edison's failure to resolve their own Year
2000 issues in a timely manner. Contingency plans are expected to be completed
in the fourth quarter of 1999, allowing for implementation of the contingency
plan by December 31, 1999.
Although we believe that we and the Coso partnerships have an effective
program in place to adequately address the Year 2000 issue in a timely manner,
failure of third parties upon whom the Coso partnerships' business relies could
result in disruption of the Coso partnerships' generation of revenues and
payments on their project notes. See "Risk Factors--The Coso partnerships could
be materially adversely affected by unanticipated Year 2000 compliance
problems."
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BUSINESS
The Coso Projects
The Coso projects consist of three 80 MW geothermal power plants, which we
call Navy I, BLM and Navy II, and their transmission lines, wells, gathering
system and other related facilities. The Coso projects are located near one
another in the Mojave Desert approximately 150 miles northeast of Los Angeles,
California, and have been generating electricity since the late 1980s. Unlike
fossil fuel-fired power plants, the Coso projects' power plants use geothermal
energy derived from the natural heat of the earth's interior to generate
electricity. Since geothermal power plants have no fossil fuel costs, we
believe our plants enjoy higher and more stable gross operating margins than
fossil fuel-fired power plants with similarly rated capacities.
The Navy I partnership owns Navy I and its related facilities, the BLM
partnership owns BLM and its related facilities and the Navy II partnership
owns Navy II and its related facilities. The Coso partnerships and their
affiliates own the exclusive right to explore, develop and use, currently
without any known interference from any other power developers, a portion of
the Coso Known Geothermal Resource Area. See "--The Coso Known Geothermal
Resource Area." Since 1991, the Coso partnerships have drilled 56 geothermal
wells, approximately 91% of which have contributed to the commercial production
of geothermal energy.
The geothermal power plants, each of which has three separate turbine
generator units, have consistently operated above their nominal capacities, and
the combined average capacity factor for the plants has exceeded 100%, for each
of the last six years. For the six months ended June 30, 1999, the plants
operated at a combined average capacity factor of approximately 101.4%.
The Coso partnerships sell 100% of the electrical energy generated at the
plants to Edison under three long-term Standard Offer No. 4 power purchase
agreements. Each power purchase agreement expires after the last maturity date
of the senior secured notes. Edison is one of the largest investor-owned
electric utilities in the United States. As of December 31, 1998, Edison
reported in its 1998 annual report total assets of $16.9 billion and operating
revenues of $8.8 billion. Edison was, as of the date of this prospectus, rated
A1 by Moody's and A+ by Standard & Poor's.
Under the power purchase agreements, the Coso partnerships receive the
following payments:
. Capacity payments for being able to produce electricity at certain
levels. Capacity payments are fixed throughout the lives of the power
purchase agreements;
. Capacity bonus payments if they are able to produce electricity above a
specified higher level. The maximum capacity bonus payment available is
also fixed throughout the lives of the power purchase agreements; and
. Energy payments which are based on the amount of electricity their
respective plants actually produce.
Energy payments are fixed for the first ten years of firm operation under the
power purchase agreements. Firm operation was achieved for each Coso
partnership when Edison and that Coso partnership under its power purchase
agreement agreed that each generating unit at a plant was a reliable source of
generation and could reasonably be expected to operate continuously at its
effective rating. After the first ten years of firm operation and until its
power purchase agreement expires, Edison makes energy payments to the Coso
partnership based on its avoided cost of energy. Edison's avoided cost of
energy is Edison's cost to generate electricity if Edison were to produce it
itself or
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buy it from another power producer rather than buy it from the relevant Coso
partnership. See "Risk Factors--Future energy payments paid by Edison to the
Coso partnerships will most likely be less than historical energy payments
because they will be paid based on Edison's avoided cost of energy."
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement on the outcome of this or
any other dispute with Edison, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, we have
assumed that the fixed energy price period expires ten years after the first of
the three generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
The Edison power purchase agreements will expire:
. in August 2011 for the Navy I partnership;
. in March 2019 for the BLM partnership; and
. in January 2010 for the Navy II partnership.
As of June 30, 1999, the unaudited combined net book value of the property,
plant and equipment of the Coso partnerships was approximately $466.2 million,
including approximately $158.0 million at the Navy I partnership, $161.1
million at the BLM partnership and $147.1 million at the Navy II partnership.
AB1890 Energy Subsidy Payments
In addition to receiving payments under the power purchase agreements, the
Navy I partnership and the BLM partnership currently qualify for subsidy
payments from a special purpose state fund established under AB1890. The
California Energy Commission administers the fund. AB1890 provides in part for
subsidy payments from 1998 through 2001 to power generators using renewable
sources of energy, including geothermal energy, and who are being paid based on
an avoided cost of energy basis. The funds are distributed in the form of a
production incentive payment that subsidizes renewable energy producers when
prices paid for their electricity are below certain pre-determined target
prices. Under AB1890, the Navy I partnership and the BLM partnership are
expected to receive in the future subsidy payments for energy delivered to
Edison by the Navy I partnership or the BLM partnership, as the case may be, if
Edison's avoided cost of energy falls below 3.0c per kWh. This subsidy is
capped at 1.0c per kWh. The Navy II partnership should also qualify for these
subsidy payments through 2001 once the fixed energy price period under its
power purchase agreement expires.
The Navy I partnership has granted a lien in favor of the California Energy
Commission with respect to any recovery that the Navy I partnership obtains
against Edison which relates to the issue of when the fixed energy price period
expires at its plant, as described above and under the heading
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"Business--Legal Proceedings--Edison Litigation." The lien will secure
approximately $477,000 of AB1890 funds to be paid by the California Energy
Commission to the Navy I partnership with respect to the disputed period in
1998. The Navy I partnership has posted a bond in the same amount as additional
security. In addition, the BLM partnership has granted a similar lien in favor
of the California Energy Commission with respect to any recovery that the BLM
partnership obtains against Edison which relates to the issue of when the fixed
energy price period expires at its plant. This lien will secure approximately
$202,000 of AB1890 funds to be paid by the California Energy Commission to the
BLM partnership with respect to the disputed period. See "Risk Factors--The
Coso partnerships and their managing partners are currently involved in
material litigation with Edison, their sole customer" and "Business--Legal
Proceedings--Edison Litigation."
Operating Strategy
The Coso partnerships seek to maximize cash flow at the Coso projects through
active management of the Coso projects' cost structure and the Coso geothermal
resource. As a result of Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects:
. The Coso partnerships retained two new operators at the Coso projects:
FPL Operating and Coso Operating Company. FPL Operating currently
operates and maintains all three plants, the transmission lines and the
geothermal fields at the Coso projects under three short-term O&M
agreements with the Coso partnerships. Coso Operating Company manages the
geothermal resource, including well drilling, under three additional O&M
agreements with the Coso partnerships. As discussed under "Prospectus
Summary--Recent Developments--Purchase of FPL Interests; Assignment of
FPL O&M Agreements," FPL Operating is currently expected to assign to
Coso Operating Company all of its rights under FPL Operating's O&M
agreements, and Coso Operating Company is currently expected to assume
all of FPL Operating's duties and obligations under those O&M agreements.
Coso Operating Company will thereby become the sole operator of all of
the plants and fields located at the Coso projects, using substantially
all of the same personnel who are currently employed by FPL Operating and
Coso Operating Company at the Coso projects. Also:
. FPL Operating and Coso Operating Company retained substantially the
same employees who were employed by the prior operator. Approximately
70% of the employees who currently work at the Coso projects' sites
have been employed there since 1992; and
. As a result of the change in operators and the restructuring of
operator fees, the aggregate annual fees to be paid by the Coso
partnerships to FPL Operating and Coso Operating Company under their
O&M agreements have been reduced from approximately $7.5 million,
which had been paid to CalEnergy, to approximately $2.0 million.
Payment of these reduced operator fees have been subordinated to all
payments to be made under the senior secured notes;
. Caithness Acquisition, which purchased the managing partners of the Coso
partnerships, has caused any management committee fees payable by each
Coso partnership to its partners to be subordinated to all payments to be
made under the senior secured notes;
. The Coso partnerships expect to reduce annual non-fee related costs at
the Coso projects, including insurance, maintenance and other costs, by
approximately $1.9 million. However, the pro forma financial data
included in this prospectus does not give effect to this cost savings;
and
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. The Coso partnerships are expanding a steam sharing program they
previously implemented among the Coso projects to enhance the management,
and to optimize the overall use, of the Coso geothermal resource. As part
of this program, the Coso partnerships plan to conserve the geothermal
resource whenever possible by, among other things:
. Transferring steam between and among the Coso projects and from BLM
North, rather than drilling new wells at the Coso projects' sites
prematurely; and
. Expanding the flexible field-wide water reinjection program. See "--
Steam Sharing Program."
The Coso projects qualify as Small Power QFs under PURPA and the rules and
regulations promulgated under PURPA by FERC. PURPA exempts the Coso projects
from certain federal and state regulations. The Coso projects must continue to
satisfy certain ownership and fuel-use standards to maintain their QF status.
Since their inception, the Coso projects have satisfied these standards and we
expect that they will continue to do so.
Purchase of CalEnergy Interests
In late 1998, CalEnergy announced that it was planning to merge with
MidAmerican Energy Holdings Company. As a consequence of the planned merger,
FERC required CalEnergy to divest itself of at least a portion of its
approximately 48% equity interest in the Coso projects if the Coso projects
were to continue to qualify as QFs under PURPA. Each Coso partnership is
required to operate and maintain its Coso project as a QF under its power
purchase agreement and under the Indenture. See "--Overview of the Independent
Power Industry."
On February 25, 1999, Caithness Acquisition purchased all of CalEnergy's
interests in the Coso projects. The purchase price consisted of $205.0 million
in cash, plus $5.0 million in contingent payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. In order to complete the
purchase, Caithness Acquisition arranged for short-term debt financing in the
principal amount of approximately $211.5 million. Caithness Acquisition used a
portion of the proceeds from the Series A notes offering that it received from
the Coso partnerships, together with funds from other sources, to repay all
amounts owed under this short-term debt facility. See "Certain Relationships
and Related Transactions--Purchase of CalEnergy Interests."
As part of the purchase of CalEnergy's interests in the Coso projects,
Caithness Energy will be required to pay the contingent payment upon the
settlement, final judgment or other dismissal of the litigation with Edison
described under the heading "Business--Legal Proceedings." The amount of the
contingent payment will depend on the outcome of the litigation with Edison.
If, as a result of the Edison litigation, the Coso partnerships are required to
pay damages to Edison, then the amount of the contingent payment will be
reduced by $0.50 for each $1.00 of damages in excess of any amounts owed to or
received by the Coso partnerships from Edison. The amount owed to the Coso
partnerships by Edison will include any amounts in excess of $5.7 million
received by the Coso partnerships from Edison as a result of the dispute
regarding the escalation of the fixed price energy payment schedule for 1999
and 2000. In no event will the amount of the contingent payment be greater than
$5.0 million or will CalEnergy owe any payment to the Coso partnerships as a
result of any adjustments to the amount of the contingent payment.
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In addition, the Coso partnerships and certain other affiliates of Caithness
Energy entered into a future revenue agreement with CalEnergy. This agreement
provides that the Coso partnerships and such affiliates will pay to CalEnergy
one-seventh of the gross revenues from the Coso projects or any expansions
thereof derived from certain energy-related arrangements with the U.S.
Government. This agreement does not apply to currently existing arrangements
that the Coso partnerships have with the U.S. Government or any extensions or
renewals of those existing arrangements. The term of this agreement will expire
on February 25, 2004, unless a new arrangement is entered into with the U.S.
Government, in which case the term will expire upon the expiration of that new
arrangement.
The Sponsor
Caithness Energy, the principal operating subsidiary of Caithness
Corporation, is a developer and owner of independent power projects and is the
sponsor of the Coso projects. Since 1966, the current owners of Caithness
Corporation have been involved in the development of long-term investment
opportunities involving natural resources. Caithness Corporation is one of the
two original sponsors of the Coso projects and formed Caithness Energy in 1995
to consolidate its ownership of independent power projects.
Caithness Energy believes that it is currently the second largest owner of
geothermal power projects in the United States, based on the total electrical
generating capacity of its power projects. Through its controlled affiliates,
Caithness Energy owns interests in seven geothermal plants, including the Coso
projects, totaling 420 MW. Caithness Energy is also seeking to develop two
additional geothermal power projects with a total potential electrical
generating capacity of over 400 MW, and has interests in other operating power
generating facilities, including solar, wind and natural gas, totaling an
additional 400 MW.
Caithness Energy has historically partnered with strategic investors in its
power project investments. The largest such investors in the Coso projects
currently are:
. ESI Geothermal, which is a subsidiary of FPL Energy, Inc., the
independent power subsidiary of FPL Group, Inc., and which in turn is the
parent company of Florida Power & Light Company, one of the largest
investor-owned utilities in the United States; and
. Dominion Energy, Inc., a subsidiary of Dominion Resources, Inc., which
also is a large investor-owned utility. See "--The Coso Partnerships."
Caithness Acquisition and the Coso partnership recently entered into a Sale
Agreement with ESI Geothermal to purchase all of ESI Geothermal's indirect
ownership interests in the Navy I partnership. You should read "Prospectus
Summary--Recent Developments--Purchase of FPL Interests; Assignment of FPL O&M
Agreements" for more information regarding the pending purchase of ESI
Geothermal's ownership interests in the Navy I partnership and certain related
transactions.
Caithness Energy is headquartered in New York City and has additional offices
in California, Colorado and Florida.
The Coso Partnerships
Affiliates of Caithness Energy and CalEnergy formed the Coso partnerships
during the 1980s to develop, own and operate Navy I, BLM and Navy II. The Navy
I partnership was formed in July 1987, the BLM partnership was formed in March
1988 and the Navy II partnership was formed in July 1989. The Coso partnerships
own and operate the Coso projects. See "--Overview of the Coso Projects--
Project History."
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Each of the Coso partnerships has two general partners, a managing partner
and a non-managing partner. The managing partner of the Navy I partnership is
New CLOC Company, LLC, a Delaware limited liability company ("New CLOC"), the
managing partner of the BLM partnership is New CHIP Company, LLC, a Delaware
limited liability company ("New CHIP") and the managing partner of the Navy II
partnership is New CTC Company, LLC, a Delaware limited liability company ("New
CTC"). The non-managing partner of the Navy I partnership is ESCA LLC, a
Delaware limited liability company ("ESCA"), the non-managing partner of the
BLM partnership is Caithness Coso Holdings, LLC, a Delaware limited liability
company ("CCH"), and the non-managing partner of the Navy II partnership is
Caithness Navy II Group, LLC, a Delaware limited liability company ("Navy II
Group").
ESCA, the non-managing partner of the Navy I partnership, is owned by
affiliates of Caithness Energy and by ESI Geothermal. ESI is in turn indirectly
wholly owned by FPL Energy, Inc. Caithness Acquisition recently entered into a
Sale Agreement with ESI Geothermal to purchase all of ESI Geothermal's indirect
ownership interests in the Navy I partnership. You should read "Prospectus
Summary--Recent Developments--Purchase of FPL Interests; Assignment of FPL O&M
Agreements" for more information regarding the pending purchase of ESI
Geothermal's ownership interests in the Navy I partnership and certain related
transactions. CCH and Navy II Group are owned by Caithness Energy-controlled
entities. Dominion Energy, Inc. is a limited partner of a member of CCH and is
a member of Navy II Group.
Since Caithness Acquisition's purchase of all of CalEnergy's interests in the
Coso projects in February 1999, Caithness Energy has indirectly wholly owned
and controlled the managing partners of the BLM partnership and the Navy II
partnership. Caithness Energy and its affiliates also control CCH, the non-
managing partner of the BLM partnership, and Navy II Group, the non-managing
partner of the Navy II partnership. In addition, while Caithness Energy has
indirectly wholly owned and controlled the managing partner of the Navy I
partnership since February 1999, it does not wholly own and control ESCA, the
non-managing partner of the Navy I partnership. Caithness Energy, FPL Energy,
Inc. and their respective affiliates currently own and control ESCA. See
"Management." Also see "Prospectus Summary--Recent Developments--Purchase of
FPL Interests; Assignment of FPL O&M Agreements."
The Issuer
We are a special purpose corporation and a wholly owned subsidiary of the
Coso partnerships. We were formed for the purpose of issuing the senior secured
notes for ourselves and on behalf of the Coso partnerships. The Coso
partnerships have guaranteed our obligations to repay the senior secured notes.
On May 28, 1999, the closing date of the Series A notes offering, we and the
Coso partnerships completed the following transactions:
. We sold $110.0 million of our 6.80% Series A Senior Secured Notes due
2001 and $303.0 million of our 9.05% Series A Senior Secured Notes due
2009 to the initial purchaser of the Series A notes pursuant to a
purchase agreement, dated May 21, 1999, among the initial purchaser, the
Coso partnerships and us;
. We loaned all of the proceeds from the Series A notes offering to the
Coso partnerships; and
. The Coso partnerships, in turn, caused the net proceeds from the Series A
notes offering, together with cash on their balance sheets and funds from
other sources, to (1) retire all Coso project debt that existed prior to
the Series A notes offering, including the payment of accrued
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and unpaid interest and premiums, of approximately $150.7 million, (2)
initially fund the Debt Service Reserve Account established under the
Depositary Agreement in the amount of $50.0 million, (3) repay
approximately $216.9 million of short term debt, including accrued
interest, incurred to purchase all of CalEnergy's interests in the Coso
projects and (4) make distributions of the remaining balance to the owners
of the Coso partnerships other than the beneficial owners of Caithness
Energy.
Also, concurrently with the closing of the Series A notes offering, Coso
Funding Corp. purchased for cash all of its then outstanding 1992 Notes. The
proceeds of the 1992 Notes were originally loaned by Coso Funding Corp. to the
Coso partnerships, and these loans constituted the existing project debt that
was retired with a portion of the proceeds from the Series A notes offering.
We have no material assets, other than the loans we made to the Coso
partnerships, and do not conduct any business, other than issuing the senior
secured notes and making the loans to be Coso partnerships.
Overview of the Independent Power Industry
The Coso projects are part of the growing domestic independent power
industry. Utilities in the United States have been the predominant producers
of electric power since the early 1900s. In 1978, however, Congress enacted
PURPA, which removed regulatory constraints relating to the production and
sale of electricity by certain non-utility power producers. PURPA requires
electric utilities to buy electricity from non-utility power producers that
use renewable energy sources, known as Small Power QFs, or that produce both
electric energy and useful thermal energy used for industrial, commercial,
heating or cooling purposes, known as Cogeneration QFs. This encouraged
companies other than electric utilities to enter the electric power production
market. Under PURPA, electric utilities are required to comply with state law
guidelines and, in general, must interconnect with and buy capacity and energy
offered by non-utility power producers meeting certain ownership and, in the
case of Cogeneration QFs, operating and efficiency standards, or, in the case
of Small Power QFs, fuel use criteria, established by FERC if there is a need
for such electricity and if it is priced at or below the utility's avoided
cost of energy at the time of the agreements.
According to the Edison Electric Institute, as of December 31, 1997 (the
most recent data available), non-utility power producers represented
approximately 8.5% of the installed generating capacity in the United States,
accounting for approximately 11.8% of the total electric generation in 1997.
Between December 31, 1993 and December 31, 1997, non-utility power producers
represented approximately 44.5% of the new installed generating capacity added
in the United States.
The Coso Known Geothermal Resource Area
The Coso projects are located in an area that has been designated as a Known
Geothermal Resources Area by the Bureau of Land Management pursuant to the
Geothermal Steam Act of 1970. The Bureau of Land Management designates an area
as a Known Geothermal Resource Area when it determines that a commercially
viable geothermal resource is likely to exist there. There are over 100 Known
Geothermal Resource Areas in the United States, most of which are located in
the western United States in tectonically active regions.
The Coso Known Geothermal Resource Area is located in Inyo County,
California, approximately 150 miles northeast of Los Angeles. The Coso
geothermal resource is a "liquid-dominated" hot water source contained within
the heterogeneous fractured granite rocks of the Coso
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mountains. We believe the heat source for the Coso geothermal resource is a hot
molten rock or "magma" body located at a depth of six-to-seven miles beneath
the surface of the field. Geochemical studies indicate that the water in the
Coso geothermal resource is ancient water that has been there since the ice age
or longer.
The Coso partnerships produce steam by drilling wells into the fracture
systems, which tap into these reservoirs of hot water. These fractures act as
the plumbing system within the geothermal resource, enabling hot fluids to
circulate from deep within the earth's crust to drillable depths. Fractured
systems of this type are common among geothermal systems throughout the world.
As is typical in these types of complex geothermal reservoirs, it is often
difficult to predict how well these new wells will perform, even when the new
wells are located in close proximity to each other. The geothermal consultant's
report prepared by GeothermEx, Inc., which is included in Exhibit C of this
prospectus, provides additional information regarding the Coso geothermal
resource.
The Coso geothermal resource, which is a "liquid-dominated" system, is
significantly different from a so-called "dry steam" system. Although a dry
steam system contains more extractable energy per pound than does the mixture
of steam and water from the Coso geothermal resource, we believe that the
liquid-dominated Coso geothermal resource offers certain operating advantages.
Production from geothermal systems over time results in a net loss of steam or
fluid from the reservoir and consequently, a decrease in reservoir pressure
within the system. The liquid portion of the fluid withdrawn from a liquid
dominated system can be injected back into the reservoir at specific points,
which provides a means of maintaining pressure support in the reservoir. In dry
steam fields, no significant liquid fraction is available, and reservoir
pressure maintenance may require the importation of water from an external
source. The Coso geothermal resource is also relatively low in total dissolved
solids as contrasted with other liquid-dominated geothermal resources. This
contributes to less maintenance on the wells and pipes to eliminate the build
up of dissolved solids, and results in longer well life.
Geothermal Energy
Geothermal energy is:
. an established and generally sustainable source of energy that
releases significantly lower levels of emissions than result when
energy is generated by burning fossil fuels;
. derived from the natural heat of the earth when water comes
sufficiently close to hot molten rock to heat the water to
temperatures of 400 degrees Fahrenheit or more. The heated water then
ascends toward the surface of the earth where, if geological
conditions are suitable, it can be extracted for commercial use by
drilling geothermal wells; and
. a renewable source of energy so long as natural ground water flows
and reinjection of extracted geothermal fluids are adequate over the
long term to replenish the geothermal reservoir after geothermal
fluids have been withdrawn.
Compared to fossil fuel-fired power plants, geothermal energy facilities
typically have higher capital costs, primarily as a result of wellfield
development, but tend to have significantly lower variable operating costs.
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Power Production Process
The physical facilities used for geothermal energy production are
substantially the same at Navy I, BLM and Navy II. The following diagram
illustrates the geothermal energy production process:
[DIAGRAM APPEARS HERE]
The geothermal fluids produced at the wellhead consist of a mixture of hot
water and steam. The mixture flows from the wellhead through a gathering system
of insulated steel pipelines to high pressure separation vessels, or
separators. There, steam is separated from the water and is sent to a demister
in the power plant, where any remaining water droplets are removed. This
produces a stream of dry steam, which passes through the high pressure inlet of
a turbine generator, producing electricity. The hot water previously separated
from the steam at the high pressure separators is piped to low pressure
separators, where low pressure steam is separated from the water and sent to
the low pressure inlet of a turbine generator. The hot water remaining after
low pressure steam separation is injected back into the Coso geothermal
resource.
Steam exhausted from the steam turbine is passed to a surface condenser
consisting of an array of tubes through which cold water circulates. Moisture
in the steam leaving the turbine generators condenses on the tubes and, after
being cooled further in a cooling tower, is used to provide cold circulating
water for the condenser.
The primary atmospheric emission control system at each of the Coso projects
consists of surface condenser, non-condensable gas removal equipment and a gas
compressor unit. In the initial
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periods of operations at the Coso projects, gases were mixed with hot water
exiting the low pressure separators and injected back into the Coso geothermal
resource via injection wells. This practice of gas injection has been replaced
with surface hydrogen sulfide abatement systems at each Coso project. The Coso
partnerships installed a "Dow Sulferox H\\2\\S" abatement system at BLM in 1992
and "LO-CAT II" abatement systems at Navy I and Navy II in 1994. Both systems
utilize a patented chemical process which transforms hydrogen sulfide gas into
elemental sulfur, which can then be sold. For certain legal proceedings
relating to the installation of the "Dow Sulferox H\\2\\S" abatement system,
see "--Legal Proceedings--Dow Litigation."
All three plants are designed to operate 24 hours per day, every day of the
year. Each year, three of the turbine generators are shut down for
approximately two weeks for regular inspection, maintenance and repair. The
operator of the plants will attempt to schedule these shut-downs during off-
peak periods. Additionally, outages during weekends, which are considered off-
peak periods, are scheduled twice a year for each of the nine units. You should
read the independent engineer's report prepared by Sandwell Engineering Inc.
and included in Exhibit A of this prospectus for more information about the
plants. It has a description of the status of the current operations at each
plant and their ability to maintain current levels of operations.
Overview of the Coso Projects
Project History
In December 1979, CalEnergy signed the Navy Contract. Under the Navy
Contract, the Navy granted to CalEnergy exclusive contractual rights to explore
for, develop and use a portion of the Coso Known Geothermal Resource Area
located at the United States Naval Air Weapons Center at China Lake,
California. In 1980, an affiliate of Caithness Corporation and CalEnergy formed
a joint venture partnership, which is known as China Lake Joint Venture, to
develop jointly the geothermal resources in this area, and the Navy Contract
was subsequently assigned to China Lake Joint Venture. In 1983 and 1984, China
Lake Joint Venture negotiated the power purchase agreements with Edison. See
"Summary Descriptions of Principal Agreements Relating to the Coso Projects--
Power Purchase Agreements." In April 1985, CalEnergy entered into an Offer to
Lease and Lease for Geothermal Resources with the Bureau of Land Management,
which we call the BLM lease. By assignment from CalEnergy of the BLM lease,
Coso Land Company, another joint venture entity formed by affiliates of
Caithness Corporation and CalEnergy, obtained a leasehold interest in land
adjacent to the Navy lands for geothermal exploration and development.
In 1986, China Lake Joint Venture directly assigned to the Navy I partnership
portions of its interests under the Navy Contract in connection with the
construction of Navy I. In 1988, China Lake Joint Venture assigned to the Navy
II partnership portions of its interests under the Navy Contract in connection
with the construction of Navy II. It also retained a residual interest in the
Navy Contract. In 1988, the BLM lease was assigned to the BLM partnership.
Also, in 1989, the BLM partnership and the Navy II partnership transferred
certain of their respective rights to the BLM/Navy II Transmission Line
described under "Transmission Lines" below to Coso Transmission Line Partners,
a California general partnership of which the BLM partnership and the Navy II
partnership are the general partners, in connection with the completion of Navy
II. Today, the rights under the Navy Contract are vested in the Navy I
partnership, the Navy II partnership and Coso Transmission Line Partners, with
the residual interest held by China Lake Joint Venture, and the rights under
the BLM lease are vested in the BLM partnership. See "--The Coso Partnerships"
and "--Purchase of CalEnergy's Interests."
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Plants
Navy I. Navy I and its steam resource are located on the United States Naval
Weapons Center at China Lake. It commenced operations in 1987. As of June 30,
1999, geothermal steam for Navy I was produced using 40 production and
injection wells located within a radius of approximately 3,000 feet of Navy I.
Navy I consists of three separate turbine generators, known as Units 1, 2 and
3, each with approximately 30 MW of electrical generating capacity. Navy I's
steam gathering and piping systems are cross-connected to Navy II via metered
transfers to allow steam to be transferred from wells located on the real
property covered by the LADWP leases to Navy I and between Navy I and Navy II
pursuant to the steam sharing program. See "--Steam Sharing Program." Unit 1 at
Navy I commenced firm operation in 1987, and Units 2 and 3 at Navy I commenced
firm operation during 1988. Navy I has an aggregate gross electrical generating
capacity of approximately 90 MW, and operated at an average operating capacity
factor of approximately 83.0% in the six month period ended June 30, 1999,
94.6% in 1998, 103.2% in 1997 and 112.1% in 1996, based on a nameplate capacity
of 80 MW.
In January 1999, one of Navy I's three turbine generator units, known as Unit
1, automatically shut down when the stator coils attached to it experienced a
ground fault. The stator coil was repaired, and Unit 1 was scheduled to return
to service in March 1999. However, electrical faults recurred during the start-
up testing stage of Unit 1's generators, and the Navy I partnership postponed
Unit 1's return to service while it repaired the unit. Unit 1 returned to
service prior to June 1, 1999, and is currently in service. The Navy I
partnership had filed a claim in connection with Unit 1's shutdown under its
business interruption and casualty insurance policies. It expects that any
losses resulting from this shutdown will be covered by insurance, subject to a
deductible of $500,000 for property damage and a 25-day deductible for business
interruption. The other two turbine generator units at Navy I and the three
generator units at BLM and Navy II are also currently in service.
BLM. BLM and its steam resource are located on Bureau of Land Management
property (other than the Bureau of Land Management property that is subject to
the LADWP leases), within the boundaries of the United States Naval Weapons
Center at China Lake. It commenced operations in 1989. BLM is comprised of
turbine generators located at two different power blocks: the BLM East site and
the BLM West site. The BLM East site is located approximately 1.3 miles east of
the BLM West site. As of June 30, 1999, geothermal steam for BLM was produced
using 38 production and injection wells located within a radius of
approximately 4,000 feet from either the BLM East or the BLM West site. BLM
consists of three separate turbine generators, known as Units 7, 8 and 9. Units
7 and 8 are located at the BLM East site, each with a generating capacity of
approximately 30 MW, while Unit 9 is located at the BLM West site, with a
generating capacity of approximately 30 MW. BLM's steam gathering and piping
systems are cross-connected to Navy II via metered transfers to allow steam to
be transferred between Navy II and BLM. See "--Steam Sharing Program." All
three units commenced firm operation during 1989. BLM has an aggregate gross
electrical generating capacity of approximately 90 MW, and operated at an
average operating capacity factor of approximately 108.8% in the six month
period ended June 30, 1999, 104.4% in 1998, 99.6% in 1997, and 107.9% in 1996,
based on a nameplate capacity of 80 MW.
Navy II. Navy II and its steam resource are located on the United States
Naval Weapons Center at China Lake. It commenced operations in 1989. As of June
30, 1999, geothermal steam for Navy II was produced using 37 production and
injection wells located within a radius of approximately 6,000 feet of Navy II.
Navy II consists of three separate turbine generators, known as
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Units 4, 5 and 6, each with approximately 30 MW of electrical generating
capacity. Navy II's steam supply systems are cross-connected to Navy I's and
BLM's steam supply systems via metered transfers to allow steam to be
transferred between or among the plants pursuant to the steam sharing program.
See "--Steam Sharing Program." All three Navy II units commenced firm operation
in 1990. Navy II has an aggregate gross electrical capacity of approximately 90
MW, and operated at an average operating capacity factor of approximately
112.3% in the six month period ended June 30, 1999, 108.6% in 1998, 108.9% in
1997, and 110.6% in 1996, based on a nameplate capacity of 80 MW.
Transmission Lines
The electricity generated by Navy I is conveyed over an approximately 28.8-
mile 115 kilovolt ("kV") transmission line on Navy and Bureau of Land
Management land that is connected to the Edison substation at Inyokern,
California. The Navy I partnership owns and uses this transmission line (the
"Navy I Transmission Line") and its related facilities. The electricity
generated by BLM and Navy II is conveyed over an approximately 28.8-mile 230 kV
transmission line on Navy and Bureau of Land Management land that is also
connected to the Edison substation at Inyokern, California (the "BLM/Navy II
Transmission Line"). Coso Transmission Line Partners owns the BLM/Navy II
Transmission Line and related facilities. FPL Operating currently maintains the
Navy I Transmission Line pursuant to an O&M agreement with Navy I and the
BLM/Navy II Transmission Line pursuant to O&M agreements with the BLM
partnership and the Navy II partnership. If Caithness Acquisition's purchase of
ESI Geothermal's ownership interests in the Navy I partnership is completed,
Coso Operating Company will assume all of FPL Operating's maintenance and
operational duties. See "Prospectus Summary--Recent Developments--Purchase of
FPL Interests; Assignment of FPL O&M Agreements."
BLM North
In 1997, LADWP assigned to Coso Land Company, one of our affiliates, all of
its rights and interests in three separate leases that it entered into with the
Bureau of Land Management, including the right to use certain wells and related
equipment located on the real property subject to these three leases. We call
these three leases the LADWP leases. Under the LADWP leases, Coso Land Company
has the right to drill for, extract, produce, remove, use, sell and dispose of
the geothermal resources located on BLM North. Coso Land Company originally
entered into the lease assignment with the LADWP to obtain access to additional
steam to supplement the steam available for transfer among the Coso projects'
plants under the steam sharing program. See "--Steam Sharing Program."
Coso Land Company currently allows the Coso partnerships to have access to
the geothermal resources underlying BLM North, although the Bureau of Land
Management has not formally consented to this arrangement. As of June 30, 1999,
the Coso partnerships were producing steam from two production wells located on
one of the LADWP leases and were injecting fluids into an injection well
located on a second LADWP lease. Another well located on the second LADWP lease
is capable of producing geothermal steam, but it has not been connected to the
Coso projects' gathering system. The third LADWP lease has no wells on it. The
currently-producing wells located at BLM North are connected directly to Navy I
to allow steam to be transferred from these wells through Navy I to the Coso
partnerships' steam gathering and piping system for use by the Coso
partnerships.
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Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as tenants-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will assume all of Coso Land Company's obligations under the LADWP
leases and will reimburse Coso Land Company for the costs it incurred in
acquiring the LADWP leases. These costs were approximately $1.0 million. See
"Summary Description of Principal Agreements Relating to the Coso Projects--The
LADWP Leases."
The Coso partnerships' use of the geothermal resources at BLM North will be
governed by a co-tenancy agreement. Under the co-tenancy agreement, each Coso
partnership will have the right, subject to applicable consents, to use BLM
North for geothermal resource production and injection purposes if it
determines, in its exercise of reasonable business judgment, that it has
insufficient steam economically available to it from other sources.
Power Sales
The Coso partnerships sell all of the electrical energy generated at the
plants to Edison under three substantially similar long-term Standard Offer No.
4 power purchase agreements. Under the power purchase agreements, the Coso
partnerships receive capacity payments for being able to produce electricity at
certain levels, capacity bonus payments if they are able to produce above a
specified higher level and energy payments based on the amount of electricity
their plants actually produce. The capacity and capacity bonus payment rates
are fixed throughout the lives of the power purchase agreements. Energy
payments are fixed for the first ten years of firm operation under the power
purchase agreements. After the ten-year fixed energy price period expires, the
Coso partnerships sell their electricity to Edison based on Edison's avoided
cost of energy. Edison's avoided cost of energy is Edison's cost to generate
electricity if Edison were to produce it itself or buy it from another power
producer rather than buy it from the Coso partnerships. See "--Power Sales--
Energy Payments" and "Business--Legal Proceedings--Edison Litigation."
The Navy I partnership's power purchase agreement expires in August 2011, the
BLM partnership's power purchase agreement expires in March 2019 and the Navy
II partnership's power purchase agreement expires in January 2010. See "Summary
Descriptions of Principal Agreements Relating to the Coso Projects--Power
Purchase Agreements."
Capacity and Capacity Bonus Payments
The Navy I partnership receives levelized firm capacity payments of $161.20
per kW year, the BLM partnership receives levelized firm capacity payments of
$175.00 per kW year and the Navy II partnership receives levelized firm
capacity payments of $176.00 per kW year. Contract capacity levels must be
maintained during the on-peak periods of each month of an approximately four-
month long period, which currently runs from June through September, in each
year, for specified on-peak hours, at a rate equal to at least an 80.0%
contract capacity factor. There is a 20.0% allowance for certain forced outages
during the periods in each month in order to prevent a reduction in contract
capacity. The power purchase agreement for the Navy I partnership specifies a
contract capacity of 75 MW. The power purchase agreements for the BLM
partnership and the Navy II partnership specify a contract capacity of 67.5 MW
each. If a plant maintains the required 80% contract capacity factor during the
applicable periods, the annual capacity payment will be equal to the product of
the capacity payment per kWh stated in the power purchase agreements and the
contract capacity.
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A Coso partnership may also receive capacity bonus payments to the extent
that its plant's on-peak capacity performance exceeds 85.0% during on-peak
hours in the months of June through September. From January 1, 1994 through
December 31, 1998, the Coso partnerships have earned an average capacity bonus
of approximately 97.0% of the maximum capacity bonus possible.
Energy Payments
The energy price component for electricity delivered to Edison is subject to
a different pricing mechanism during the first ten years of each power purchase
agreement, as discussed above. Edison has taken the position that the fixed
energy price period expired in August 1997 for the Navy I partnership and in
March 1999 for the BLM partnership, and will expire in January 2000 for the
Navy II partnership. The Coso partnerships believe that the power purchase
agreements provide that each of the three turbine generator units at each
respective Coso project has its own full ten-year fixed energy price period.
This issue is one of several currently in dispute and subject to an ongoing
lawsuit between, among others, the Coso partnerships and Edison. Without making
any statement on the outcome of this or any other dispute with Edison, for
purposes of this prospectus only, including the historical and pro forma
financial information included herein, we have assumed that the fixed energy
price period expires ten years after the first of the three turbine generator
units at each respective Coso project established firm operation. We believe
that this assumption is conservative and reasonable for purposes of this
prospectus given that we cannot predict the outcome of this issue. See "Risk
Factors--The Coso partnerships and their managing partners are currently
involved in material litigation with Edison, their sole customer" and "--Legal
Proceedings--Edison."
Although energy payments paid to the Navy I partnership and the BLM
partnership are based upon 100% of Edison's avoided cost of energy, the way in
which avoided cost of energy is calculated (currently based on a formula tied
to the price of natural gas) is changing pursuant to the restructuring of the
California electricity market. Under AB1890, the comprehensive restructuring
legislation enacted in California in September 1996, the California Public
Utilities Commission is required to calculate the short-term avoided cost of
energy for payments made to non-utility power generators, such as the Coso
projects, based on the clearing price paid by the California Power Exchange
when certain conditions are met. These conditions include that (1) the
California Public Utilities Commission has issued an order determining that the
California Power Exchange is "functioning properly" and (2) either:
(a) The fossil-fired generation units owned by the purchasing utility
(such as Edison, San Diego Gas & Electric Company or Pacific Gas &
Electric Company) are authorized to charge market-based rates and
the variable costs of such units are being recovered solely through
clearing prices being paid by the California Power Exchange or from
contracts with the ISO; or
(b) The purchasing utility has divested ninety percent of its gas-fired
generation facilities that were operated to meet load in 1994 and
1995.
Divestiture of such gas-fired generation facilities by Edison and the other two
large California utilities is expected to be complete by the end of 1999.
It is likely that within the next twelve months, pursuant to AB1890, Edison's
short-term avoided cost of energy will equal the then-prevailing market
clearing price for wholesale energy at the California Power Exchange. Whether
this pricing will be on an hourly basis, a daily or block average basis (i.e.,
a daily average, daily off-peak or daily on-peak time period averages) or some
other
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variation has not been determined. We note, however, that on July 27, 1999, the
CPUC issued a ruling calling for comments on a number of issues relating to its
implementation of the methodology for determining SRAC based on the clearing
price of the California Power Exchange. It is expected that the CPUC will
resolve these issues no later than June, 2000. We also note that on October 7,
1999, the CPUC is scheduled to consider a proposed decision that would grant a
motion filed by a number of QF facilities to allow them to elect unilaterally,
pursuant to California Public Utilities Code Section 390, to receive, on an
interim basis, SRAC payments based on the California Power Exchange zonal day-
ahead clearing price. The payments made under this election would be subject to
adjustment, depending on the SRAC methodology ultimately adopted by the CPUC
under AB 1890. The market clearing prices for wholesale energy on the
California Power Exchange have occasionally for brief periods exceeded current
energy prices paid by Edison under the power purchase agreements based on its
short-term avoided cost of energy. This has occurred most often during high
load conditions, warm weather and other daily or seasonal peak periods. At
other times, the market clearing prices have been lower than Edison's short-
term avoided cost of energy. No one can predict the outcome of the final
implementation of this change in computing short-term avoided cost of energy,
or the performance of California Power Exchange clearing prices over time. For
further information, see "Risk Factors--Future energy payments paid by Edison
to the Coso partnerships will most likely be less than historical energy
payments because they will be paid based on Edison's avoided cost of energy,"
"Risk Factors--The operations of the Coso projects could be adversely affected
by an inability to comply with regulatory standards" and "Regulation."
The electric industry in California has changed dramatically as a result of
recent decisions by the California Public Utilities Commission and the
enactment of AB1890 in September 1996. The new California electric market
structure, including the ISO PX system, commenced operations on March 31, 1998.
The California Power Exchange, through which Edison is required to sell power
generated by QFs, is responsible for managing the transactions for all power
auctioned through, and purchased by, market participants except those bound by
contract. The complex grid operation, software, forecasting, bidding and market
clearing mechanism of the ISO PX system has a limited operating history. Many
elements of the new market structure present novel regulatory issues that have
not yet been resolved, as well as many practical issues of implementation such
as the development of systems, software and procedures for:
. the California Power Exchange, which provides the auction process to
match electricity supply and demand;
. the independent system operator, or ISO, which has operational control of
the transmission facilities of electrical utilities (including Edison);
and
. all of the market participants who will transact with the ISO PX system.
If the still-developing ISO PX system fails or does not operate as
anticipated, electricity generation, transmission and distribution in
California may be materially and adversely affected. Edison's business may also
be materially and adversely affected. Furthermore, since Edison's avoided cost
of energy ultimately will be tied to the clearing price of the California Power
Exchange, the ISO PX system's functionality will have a significant effect on
the Coso partnerships.
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Steam Sharing Program
The Coso partnerships have previously implemented and intended to expand the
steam sharing program which they established among the Coso projects under a
Coso Geothermal Exchange Agreement they entered into in 1994. The purpose of
the steam sharing program is to enhance the management, and to optimize the
overall use, of the Coso geothermal resource. Pursuant to the steam sharing
program, the Coso partnerships constructed an inter-project steam supply and
water injection system which links the three Coso projects and BLM North
together via metered transfer lines through which the Coso partnerships
exchange steam and other geothermal resources with one another.
As part of the steam sharing program, the Coso partnerships plan to conserve
the geothermal resource whenever possible by, among other things, transferring
steam between and among the Coso projects and BLM North, rather than drilling
new wells at the Coso projects' sites prematurely, and expanding a flexible
field-wide water reinjection program. See "--Power Production Process." While
each of the Navy and the Bureau of Land Management has consented to the steam
sharing program, each has reserved the right, in its sole discretion, to
withdraw its consent to such transfers under certain circumstances. See "Risk
Factors--The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time" and "Summary Description of Principal
Agreements Relating to the Coso Projects--Steam Sharing and Co-Tenancy
Agreements."
In 1998, the Navy I partnership and the Navy II partnership paid aggregate
royalties to the Navy of approximately $5.6 million for steam transferred by
Navy I to Navy II and by Navy II to BLM under the steam sharing program from
geothermal resources located on the property on which Navy I or Navy II, as the
case may be, are situated. Of this amount, the Navy I partnership paid
approximately $1.4 million and the Navy II partnership paid approximately $4.2
million. The BLM partnership reimbursed the Navy II partnership approximately
$1.4 million of the royalties paid by Navy II partnership. The BLM partnership
did not pay a royalty for electricity generated by BLM for steam transferred
from Navy property and sold to Edison.
Operations and Maintenance
The operations and maintenance services for the Coso projects, including Navy
I, BLM and Navy II, the Navy I Transmission Line and the BLM/Navy II
Transmission Line, the wells, the gathering system and the other related
facilities, are currently performed by FPL Operating and Coso Operating Company
on behalf of the Coso partnerships pursuant to three separate O&M agreements
with each of FPL Operating and with Coso Operating Company, each dated February
25, 1999. See "Summary Descriptions of Principal Agreements Relating to the
Coso Projects--O&M Fees; Reduction in Fees."
Until February 25, 1999, CalEnergy had been the exclusive operator of the
Coso projects. Since that date, FPL Operating, an indirect wholly owned
subsidiary of FPL Energy, Inc., has been operating and maintaining the Coso
projects' plants, the transmission lines and the geothermal fields under three
separate short-term O&M agreements. FPL Energy, Inc. is an indirect, wholly
owned subsidiary of FPL Group, Inc., the parent holding company of Florida
Power & Light Company, one of the largest investor-owned utilities in the
United States. FPL Energy, Inc. was formed in 1998 to consolidate operations of
the unregulated energy business sectors involved in domestic and international
power generation. Florida Power & Light Company operates plants in its electric
generating system with a combined capacity of approximately 15,500 MW. FPL
Operating currently operates 56 electric generating facilities in the United
States with a combined generating capacity of
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3,933 MW. FPL Operating is managed by the same central operating group that
operates the majority of Florida Power & Light Company's electric generating
stations.
Coso Operating Company is a wholly owned subsidiary of Caithness Acquisition.
It was initially formed by CalEnergy to facilitate the transfer of operational
control of the Coso projects to Caithness Energy's affiliates. Since February
25, 1999, Coso Operating Company has been managing the geothermal resource,
including well drilling, under three additional fixed price O&M agreements. See
"Summary Descriptions of Principal Agreements Relating to the Coso Projects--
O&M Fees."
Caithness Acquisition recently entered into a Sale Agreement with ESI
Geothermal to purchase all of ESI Geothermal's indirect ownership interests in
the Navy I partnership. As part of that transaction, FPL Operating will assign
to Coso Operating Company all of its rights under its three separate
O&M agreements with the Coso partnerships, and Coso Operating Company will
assume all of FPL Operating's duties and obligations under these O&M
agreements. If these transactions are completed, Coso Operating Company will
become the sole operator of all of the plants and fields located at the Coso
projects. You should read "Prospectus Summary--Recent Developments--Purchase of
FPL Interests; Assignment of FPL O&M Agreements" for more information regarding
the purchase of ESI Geothermal's ownership interests in the Navy I partnership
and the assumption by Coso Operating Company of FPL Operating's duties and
obligations. No other changes to FPL Operating's O&M agreements are expected to
be made.
Royalty and Revenue-Sharing Arrangements
The Coso partnerships are required to make royalty payments to, and are
subject to other revenue-sharing arrangements with, the Navy, the Bureau of
Land Management and certain other persons.
Navy I
Under the Navy Contract, as a royalty for Unit 1 at Navy I, the Navy I
partnership is obligated to reimburse partially the Navy for electricity
supplied to it by Edison from electricity generated at Navy I. The
reimbursement payment is based upon a pricing formula included in the Navy
Contract. For the year ended December 31, 1998, the Navy I partnership
reimbursed the Navy approximately 76.0% of the aggregate price paid by the Navy
to Edison for electricity supplied to it by Edison. The percentage rate of
reimbursement changes semiannually, but cannot exceed 95% of the price paid by
the Navy to Edison, in accordance with a weighted index based on the Consumer
Price Index and price indices for the oil industry, the electric power plant
industry and the construction industry.
In addition, with respect to Unit 1 at Navy I, the Navy I partnership is
obligated to pay the Navy the sum of $25.0 million on or before December 31,
2009, the expiration date of the term of the Navy Contract. Payment of this
obligation will be made from an established sinking fund to which the Navy I
partnership has been making payments since 1987. As of June 30, 1999, there was
approximately $7.9 million on deposit in this sinking fund, representing both
sinking fund payments made by the Navy I partnership and accrued interest
thereon. The Navy I partnership currently intends to make aggregate annual
payments to this sinking fund of approximately $716,000 through 2009. Amounts
currently on deposit in the sinking fund, along with future deposits in the
sinking fund and interest accruing thereon, are being, and will be, held in an
escrow account by a financial institution for the benefit of the Navy.
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For Units 2 and 3 at Navy I, the Navy I partnership's royalty expense is a
fixed percentage of its electricity sales to Edison. The royalty expense is
15.0% of revenues received by the Navy I partnership through 2003 and will
increase to 20.0% from 2004 through 2009, the expiration date of the Navy
Contract. See "Summary Descriptions of Principal Agreements Relating to the
Coso Projects--The Navy Contract." In the year ended December 31, 1998, the
Navy I partnership paid aggregate royalties to the Navy of approximately $6.8
million, based on the current royalty rate of 15%.
BLM
The BLM partnership pays royalties to the Bureau of Land Management under the
BLM lease. The royalty rate is 10% of the value of the steam produced by the
BLM partnership. This royalty rate is fixed for the life of the BLM Lease. For
the year ended December 31, 1998, the BLM partnership paid aggregate royalties
of approximately $6.0 million to the Bureau of Land Management.
In addition to this royalty, the BLM partnership is obligated to pay a
royalty to Coso Land Company, a general partnership of which Caithness
Acquisition and another affiliate of Caithness Energy are the general partners,
in connection with the assignment of the BLM lease to the BLM partnership. See
"Certain Relationships and Related Transactions--Royalty to Coso Land Company."
Navy II
The Navy II partnership pays royalties to the Navy under the Navy Contract.
The Navy II partnership's royalty expense is a fixed percentage of its
electricity sales to Edison. The royalty rate is 10.0% of electricity sales to
Edison through 1999, and will increase to 18.0% from 2000 through 2004 and to
20.0% from 2005 through the end of the initial term. See "Summary Descriptions
of Principal Agreements Relating to the Coso Projects--The Navy Contract." For
the year ended December 31, 1998, the Navy II partnership paid aggregate
royalties of approximately $11.9 million to the Navy, based on the current
royalty rate of 10%.
BLM North
Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as a tenant-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will be required to pay $8.00 per acre in rent and additional rent
to the Bureau of Land Management. When a leased property commences to produce
geothermal steam, the Coso partnerships will pay monthly royalties under the
LADWP leases of 10% of the amount or value of the steam produced, 5% of any by-
products and 5% of commercially demineralized water. The Bureau of Land
Management may establish minimum production levels and reduce the foregoing
royalties if necessary to encourage the greater recovery of leased resources,
or as otherwise justified. Until this assignment becomes effective, Coso Land
Company will be required to make the above payments to the Bureau of Land
Management. See "--Overview of the Coso Projects--BLM North" and "Summary
Descriptions of Principal Agreements Relating to the Coso Projects--The LADWP
Leases."
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Insurance
The Coso partnerships currently maintain property, business interruption,
catastrophe and general liability for the Coso projects. The plants are insured
for $600.0 million per occurrence for general property damage (limited to
replacement costs) and $240.0 million per occurrence for business interruption,
subject to a $25,000 deductible for property damage (and a $250,000 deductible
for the turbine generator sets), with a 15-day deductible for business
interruption and a 25-day deductible for machinery breakdown and earthquake.
Catastrophic insurance (including earthquake and flood) is capped at $200.0
million for property damage, subject to a deductible of $2.5 million or 5.0% of
the loss, whichever is greater. Liability insurance coverage is $51.0 million
(occurrence based). Operators' extra expense (control of well) insurance is
$10.0 million per occurrence with a $25,000 deductible. The above policies were
issued by international and domestic carriers and syndicates with each company
rated A- or better by A.M. Best Co. Inc.
As part of the Series A notes offering, the Coso partnerships obtained title
insurance policies in the aggregate amount of $200.0 million in favor of the
Trustee. Primarily because of the nature of the rights obtained by one or more
of the Coso partnerships from the Navy and the Bureau of Land Management, the
insurance coverage afforded by these policies is narrower, and the exceptions
to coverage are broader, then those which are commonly provided to companies
that are engaged in activities similar to those of the Coso partnerships. No
one can assure you that the title insurer or its reinsurers will be willing or
able to satisfy any claims which may be made under those policies. Also, the
coverage amounts may not be sufficient to satisfy amounts outstanding under the
senior secured notes at any given time. See "Risk Factors--Although the Coso
partnerships currently maintain insurance, loss proceeds might not be enough to
satisfy our obligations under the Series B notes."
Employees
We do not have any employees, and neither do the Coso partnerships. All of
the employees who operate and maintain the Coso projects are currently employed
by FPL Operating and Coso Operating Company. FPL Operating and Coso Operating
Company have retained substantially the same employees previously employed by
CalEnergy, the prior operator. As of June 30, 1999, FPL Operating employed 106
employees at the Coso projects, and Coso Operating Company employed 18
employees at the Coso projects. Approximately 70% of the employees who
currently work at the Coso projects' sites have been employed there since 1992.
None of FPL Operating's or Coso Operating Company's employees are covered by
any collective bargaining agreement. We believe that FPL Operating's and Coso
Operating Company's employee relations are good. In connection with Coso
Operating Company's assumption of FPL Operating's duties and obligations under
FPL Operating's O&M agreements, Coso Operating Company will be offering
employment to substantially all of FPL Operating's employees who have been
working at the Coso projects. See "Prospectus Summary--Recent Developments--
Purchase of FPL Interests; Assignment of FPL O&M Agreements."
Environmental Matters
The Coso partnerships are subject to environmental laws and regulations at
the federal, state and local levels in connection with their development,
ownership and operation of the Coso projects. These environmental laws and
regulations generally require that a wide variety of permits and governmental
approvals be obtained to construct and operate an energy-producing facility.
The facility must then operate in compliance with the terms of these permits
and approvals. If the Coso
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partnerships fail to operate the facility in compliance with applicable laws,
permits and approvals, governmental agencies could levy fines or curtail
operations.
We believe that each of the Coso partnerships is in compliance in all
material respects with all applicable environmental regulatory requirements
applicable to its Coso project, and we believe that maintaining compliance with
current governmental requirements will not require a material increase in
capital expenditures or materially adversely affect that Coso partnership's
financial condition or results of operations. It is possible, however, that
future developments, such as more stringent requirements of environmental laws
and enforcement policies thereunder, could affect capital and other costs at
the Coso projects and the manner in which the Coso partnerships conduct their
business.
Legal Proceedings
Edison Litigation
On June 9, 1997, Edison filed a lawsuit in the Superior Court of Los Angeles
County (later transferred to Inyo County), California, against CalEnergy, the
Coso partnerships and the managing partners of the Coso partnerships--China
Lake Operating Company, now known as New CLOC; Coso Technology Corporation, now
known as New CTC; and Coso Hotsprings Intermountain Power, Inc., now known as
New CHIP. We collectively refer to the defendants in Edison's lawsuit as the
Coso Parties. In this lawsuit, Edison asserts breach of contract claims against
the Coso Parties that relate to the alleged surreptitious venting of certain
non-condensable gases from unmonitored reinjection wells located adjacent to
the plants. The Coso Parties have been vigorously defending themselves against
Edison's claims.
The events relating to Edison's breach of contract claims date back to the
late 1980's and mid-1990's, and focus on the plants' initial period of
operations. The plants had difficulty at that time achieving full compliance
with applicable air quality district regulations which, the Coso Parties
believe, was due in large part to defective equipment installed during the
construction of the plants, as more fully discussed below. As a result, the
Coso partnerships self-reported to the Great Basin Unified Air Pollution
Control District a series of instances of venting primarily from the plants,
and the Great Basin Unified Air Pollution Control District issued Notices of
Violations (which are the functional equivalent of an allegation, not an
adjudication of any violation). The Coso partnerships chose not to contest
these Notices of Violations and paid the agreed-upon fines. There was no formal
finding that any environmental violations occurred.
Edison does not base its claims against the Coso Parties on this self-
reported venting. Rather, Edison alleges that CalEnergy, the prior operator of
the plants, surreptitiously vented hydrogen sulfide gas from unmonitored
reinjection wells in violation of applicable operating permits and
environmental laws and regulations. Edison alleges that the Coso partnerships
did not report some or all of these alleged violations and breached their
contractual obligations to comply with all applicable laws, rules and
regulations. Edison argues that a provision in the power purchase agreements
requiring the Coso partnerships to comply with applicable laws, rules and
regulations allows it to seek damages for any such failures. Edison also
asserts that the output of the plants would have been lower but for the alleged
surreptitious venting.
Originally, Edison sought to terminate the three power purchase agreements
with the Coso partnerships and to recover damages equal to the total amount
Edison had paid for electricity delivered by the Coso partnerships to Edison
since inception. In June 1998, the Coso partnerships
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obtained a ruling from the trial court dismissing Edison's efforts to terminate
the three power purchase agreements. In addition, the trial court ruled that
Edison could not recover damages based on the total amount that Edison had paid
to the Coso partnerships for electricity delivered under the power purchase
agreements. Edison's damage theory is now limited to breach of contract damages
for energy deliveries which it believes were higher than they would have been
had the alleged surreptitious venting not occurred. Edison seeks damages
spanning an extended period of time based on the difference between the
contract price it paid to the Coso partnerships for the excess electricity they
allegedly delivered and the spot market price it would have paid for the amount
of such excess electricity.
In October 1997, the Coso Parties filed a motion for summary judgment arguing
that Edison's claims were barred by the 1993 Settlement Agreement (as defined
below) and that the statute of limitations for Edison's claims had expired. In
June 1993, Mission Power Engineering Company, a California corporation, and The
Mission Group, a California corporation (collectively, the "Mission Entities"),
on behalf of themselves and their respective subsidiaries and affiliates,
including Edison, and CalEnergy and the Coso partnerships, for themselves and
on behalf of their respective subsidiaries and affiliates, entered into a
Settlement Agreement and Release dated June 9, 1993 (the "1993 Settlement
Agreement"). The Mission Entities were at that time, and still are, affiliates
of Edison. The 1993 Settlement Agreement resolved, among other things, certain
claims the Coso partnerships asserted against the Mission Entities for the
Mission Entities' alleged defective construction of the Coso projects.
Pursuant to three "turnkey" engineering procurement and construction
contracts entered into in the late 1980's, the Mission Entities had agreed to
construct Navy I, BLM and Navy II so that these plants operated in compliance
with all applicable laws, rules and regulations. The Coso partnerships' claims
against the Mission Entities related in significant part to the Mission
Entities' alleged breach of this contractual provision. The 1993 Settlement
Agreement also provided for mutual releases of claims, whether known or
unknown, arising out of or relating to the construction of the Coso projects.
The trial court denied the Coso Parties' motion for summary judgment, finding
that triable issues of fact existed. The Coso Parties also assert other
defenses, including, among others, that Edison's claims for damages are not
causally related to the alleged venting and do not state legally cognizable
claims.
In September 1997, the Coso Parties filed a cross-complaint against Edison
and the Mission Entities. In its present form, the cross-complaint alleges,
among other things, breach of contract claims, violations of state law and of
decisions rendered by the California Public Utilities Commission, and that
Edison's lawsuit constitutes a breach of the 1993 Settlement Agreement. The
Coso partnerships have each asserted three separate breach of contract claims
against Edison under the power purchase agreements and are seeking damages in
excess of $125 million, exclusive of interest, accruing through the life of the
respective applicable contractual provisions. The three breach of contract
claims are as follows:
. First, Edison has refused to pay the forecasted energy prices as to each
of the three units at each respective Coso project--Navy I, BLM and Navy
II--for the full ten-year "First Period" under the power purchase
agreements. Edison has taken the position that the power purchase
agreements provide that, with respect to each Coso project, the First
Period expires ten years after the first unit for each respective Coso
project established firm operation. This would mean that the fixed energy
price period expired in August 1997 for the Navy I partnership and in
March 1999 for the BLM partnership, and will expire in January 2000 for
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the Navy II partnership. The Coso partnerships argue, in contrast, that the
power purchase agreements provide that each of the three units at each
respective Coso project has its own full ten-year fixed energy price period.
This would mean, for example, that each of Units 1, 2 and 3 at Navy I has
its own separate ten-year fixed energy price period. Under Edison's
position, the fixed energy price periods for Units 2 and 3 at Navy I end at
the same time that Unit 1's fixed energy price period ends because Unit 1
was the first unit at Navy I to establish firm operation; accordingly, the
fixed energy price periods for Units 2 and 3 are less than ten years.
. Second, Edison has refused to accept the Coso partnerships' election of a
simultaneous purchase and sale arrangement under which Edison is
obligated to pay the full forecasted price for all energy produced by the
Coso projects, without deduction for power used by the plants and their
related operations, and to serve the Coso partnerships' power needs under
a tariff applicable to industrial customers. Instead of accepting the
Coso partnerships' election, Edison has paid the Coso partnerships for
only the net amount of electricity delivered to Edison.
. Third, Edison has refused to extend and escalate the price tables
included in the power purchase agreements for the full ten-year fixed
energy price period of forecasted prices. The Coso partnerships argue
that Edison attached the wrong price tables to the power purchase
agreements because the tables leave out the years 1999 and 2000.
While we strongly dispute Edison's positions and believe the Coso
partnerships' positions are the correct interpretations of the power purchase
agreements, we have assumed, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, that (1)
the full ten-year period expires after the first of the three units at each
respective Coso project established firm capacity, (2) the Coso partnerships
cannot make the election of a simultaneous purchase and sale arrangement and
(3) the pricing tables included in the power purchase agreements are correct.
We believe that this assumption is conservative and reasonable for purposes of
this prospectus given that we cannot predict the outcome of this issue.
On September 9, 1997, the Coso partnerships filed a separate lawsuit in the
Superior Court of Inyo County, California, against Edison seeking restitution
and injunctive relief for unfair competition and false advertising. The unfair
competition claim raises a series of electric industry issues concerning
Edison's alleged program of anti-competitive activities aimed at QFs, such as
the Coso projects, and at other competitors, including electric service
providers or "ESPs." The Coso partnerships have also alleged that Edison
willfully violated decisions and orders of the California Public Utilities
Commission, which includes a claim for punitive damages in an unspecified
amount.
In December 1997, the Superior Court consolidated Edison's and the Coso
partnerships' lawsuits into one proceeding. The parties to the consolidated
actions had been engaged in extensive discovery and motion practice, discovery
(other than expert discovery) was scheduled to be completed by December 31,
1999 and a trial date had been set for March 1, 2000.
However, these dates have been vacated, and no new dates have been set,
pursuant to a stipulation entered into by the parties and an order of the trial
court. In essence, Edison and the Coso Parties agreed to a moratorium on all
ongoing activities in these lawsuits from March 29, 1999 to September 30, 1999,
in order to explore the possibility of reaching a negotiated settlement. Edison
and the Coso Parties agreed to attempt to mediate their disputes and held a
mediation session during the week of September 7, 1999, before a former
California supreme court justice. Subsequent to that
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mediation session, the parties agreed to extend further the moratorium through
October 28, 1999, to allow the parties to continue their settlement
discussions. If the parties are unable to reach a negotiated settlement by
October 28, 1999, the lawsuits will continue where they left off, and the court
will probably set a trial date for some time in the early summer of 2000.
Neither we, the Coso partnerships nor anyone else can predict at this time
whether Edison will prevail on its claims against any or all of the Coso
Parties or whether any or all of the Coso Parties will prevail on their claims
against Edison, in part because pre-trial discovery has not been completed and
is now subject to the moratorium and because of the complexity of the factual
and legal issues involved. Further, no one can give you any assurance that the
parties will be able to reach a negotiated settlement of the lawsuits and, if
they do, what the terms of such a settlement would be. It is possible that the
parties will be unable to reach a settlement and Edison could recover
significant damages. Edison has not yet provided the Coso Parties with any
formal calculation of its alleged damages but, if the parties are unable to
reach a negotiated settlement, the Coso Parties expect Edison to seek damages
in an amount which would be material to the financial condition and results of
operations of the Coso partnerships, either individually or taken as a whole.
Dow litigation
In addition, the BLM partnership is currently involved in an arbitration
proceeding against Dow Chemical Company ("Dow"). The BLM partnership is seeking
to recover certain damages incurred by the BLM partnership prior to 1998 as a
result of problems associated with the installation by Dow in 1992 of a
hydrogen sulfide abatement system at BLM. See "--Power Production Process." The
arbitration proceeding is a result of a settlement agreement entered into
between the BLM partnership and Dow in 1997 in which Dow stipulated to the
issue of its liability based on negligent misrepresentation. Dow has not made
any claims against the BLM partnership in the arbitration proceeding.
Fuji litigation
In March 1998, China Lake Plant Services, Inc., one of our affiliates, and
the Coso partnerships filed a lawsuit in Superior Court of the State of
California, County of Orange (Case No. 791982), against Fuji Electric Co., Ltd.
and Fuji Electric Corporation of America for breach of warranty related to the
Coso partnerships' nine geothermal turbine rotors. The Coso partnerships sought
to recover repair costs and other damages totaling approximately $16.0 million
incurred as a result of vibrations alleged to have occurred during operations,
which resulted in cracking and one catastrophic failure. Fuji made no
counterclaims against the Coso partnerships.
On June 23, 1999, the parties to the lawsuit entered into a Settlement
Agreement and Mutual Release which provides for the settlement of the breach of
warranty claims made against Fuji and releases of all parties with respect to
the subject matter of the lawsuit if the parties satisfy several specific
conditions. These conditions have been satisfied and the lawsuit has been
dismissed with prejudice.
Except as otherwise described above, the Coso partnerships are currently
parties to various minor items of litigation, none of which, if determined
adversely, would be material to the financial condition and results of
operations of the Coso partnerships, either individually or taken as a whole.
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SUMMARY DESCRIPTIONS OF PRINCIPAL
AGREEMENTS RELATING TO THE COSO PROJECTS
The following is a summary of selected provisions of certain principal
agreements relating to the Coso projects. It is not a full statement of the
terms of those agreements. Accordingly, the following summaries are qualified
by reference to each of those agreements and are subject to the terms of the
full text of each of those agreements. You can obtain copies of these
agreements from us upon request. See "Available Information."
Power Purchase Agreements
In 1983 and 1984, China Lake Joint Venture negotiated three separate long-
term Standard Offer No. 4 power purchase agreements with Edison. Subsequently,
the first power purchase agreement was assigned to the Navy I partnership for
Navy I, the second power purchase agreement was assigned to the BLM partnership
for BLM and the third power purchase agreement was assigned to the Navy II
partnership for Navy II. Under the terms of the power purchase agreements, the
Coso partnerships have agreed to sell to Edison, and Edison has agreed to
purchase, the electrical output at Navy I, BLM and Navy II. The power purchase
agreement between each Coso partnership and Edison requires that the Coso
partnership maintain the QF status of its Coso project throughout the contract
term. Set forth below is a summary of certain terms and provisions contained in
each power purchase agreement.
General
Each power purchase agreement provides for the sale to Edison of, in the case
of Navy I, 75 MW of capacity and, in the case of each of BLM and Navy II, 67.5
MW of capacity. Each power purchase agreement also provides for the sale to
Edison of all energy delivered at the point of interconnection, with electrical
service required to operate the Coso projects being supplied by Edison.
Terms of the Power Purchase Agreements
The term of the Navy I partnership's power purchase agreement expires in
August 2011, the term of the BLM partnership's power purchase agreement expires
in March 2019 and the term of the Navy II partnership's power purchase
agreement expires in January 2010. Each power purchase agreement is subject to
earlier termination in accordance with its terms. Upon the expiration of its
term, each power purchase agreement will remain in effect until either party
terminates the agreement upon 90 days' prior written notice.
Generating Facility
Under the power purchase agreements, each Coso partnership must operate its
generating facility in accordance with applicable utility industry standards,
good engineering practices, and any and all laws, and maintain any necessary
governmental authorizations and permits. Each Coso partnership must also
reimburse Edison for any loss which Edison incurs as a result of the Coso
partnership's failure to maintain necessary governmental authorization and
permits.
Under the power purchase agreements, Edison must pay the Coso partnerships
capacity payments, capacity bonus payments and energy payments in accordance
with each plant's electrical energy output.
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Capacity Payments
A plant qualifies for an annual capacity payment by meeting specified
performance requirements on a monthly basis during an approximately four-month
long on-peak period, which currently runs during the months of June through
September of each year. The basic performance requirement is that the plant
deliver an average kWh output during specified on-peak hours of each month in
the on-peak period at a rate equal to at least an 80% contract capacity factor.
The "contract capacity factor" equals (1) a plant's actual electricity output,
measured in kWhs, during the hours of measurement, divided by (2) the product
obtained by multiplying the plant's "contract capacity," as stated in the power
purchase agreement applicable to such Coso project, by the number of hours in
the measurement period. If a Coso project maintains the required 80% contract
capacity factor during the applicable periods, the annual capacity payment will
be equal to the product of the capacity payment per kWh stated in its power
purchase agreement and the contract capacity.
Navy I has a contract capacity of 75 MW, and the Navy I partnership has a
capacity payment per kW year of $161.20 for an annual maximum capacity payment
of approximately $12.1 million. BLM has a contract capacity of 67.5 MW, and the
BLM partnership has a capacity payment per kW year of $175.00 for an annual
maximum capacity payment of approximately $11.8 million. Navy II has a contract
capacity of 67.5 MW, and the Navy II partnership has a capacity payment per kW
year of $176.00 for an annual maximum capacity payment of approximately
$11.9 million. Although capacity prices per kWh remain constant throughout the
life of each power purchase agreement, Edison disburses capacity payments on a
monthly basis in accordance with a tariff schedule filed with the California
Public Utilities Commission. Payments are made unevenly throughout the year,
and are weighted toward the on-peak periods; currently, approximately 65% of
the capacity payments received by the Coso partnerships from Edison are paid
with respect to on-peak months, and 35% with respect to non-peak months.
Except when caused by an uncontrollable event, if a Coso partnership does not
satisfy the performance requirement, it may be placed on probation for up to 15
months, and, if the Coso partnership cannot satisfy the performance requirement
during the probationary period, Edison may derate the contract capacity factor
to a capacity equal to the greater of (1) the capacity actually delivered
during the period when the performance requirement was not met or (2) the
capacity at which the Coso partnership is reasonably likely to meet the
performance requirement. However, if the Coso partnership's failure to meet the
performance requirement is due to a forced outage on the Edison system or a
request by Edison to cease or curtail delivery, then Edison must continue to
make the full capacity payments. If a Coso partnership's energy deliveries are
interrupted or reduced due to an uncontrollable event, Edison must continue to
make full capacity payments to the Coso partnership for 90 days from the
occurrence of the uncontrollable event.
Capacity Bonus Payments
Each Coso partnership is entitled to receive capacity bonus payments during
both on-peak and non-peak months by operating at a contract capacity factor of
between 85% and 100% during on-peak hours of each month. A plant qualifies for
capacity bonus payments with respect to on-peak months provided that the plant
operates at least at an 85% contract capacity factor during the on-peak hours
of the month, and qualifies with respect to non-peak months if performance
requirements for on-peak months have been satisfied and the plant also operates
at a contract capacity factor of at least 85% during on-peak hours of the non-
peak month.
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Capacity bonus payments for each month increase with the level of kWh
delivered between the 85% and 100% contract capacity factor levels during the
month. The annual capacity bonus payment for each month is equal to a
percentage based on the plant's on-peak contract capacity factor (which
percentage may not exceed 18% of one-twelfth of the annual capacity payment).
Energy Payments
In addition to capacity and capacity bonus payments, Edison must make monthly
energy payments to each Coso partnership based on the amount of kWh of energy
delivered by each plant. The energy price component for electricity delivered
to Edison is subject to different pricing mechanisms for the first ten years of
firm operation under each power purchase agreement than are applicable during
the remaining term of each agreement. During the first ten years following the
commencement of firm operation, the energy price per kWh varies between so-
called on-peak and non-peak periods, but the average of these prices equals a
fixed price per kWh specified in the power purchase agreements. After the first
ten years of firm operation and until its power purchase agreement expires,
Edison makes or will make energy payments to a Coso partnership based on
Edison's avoided cost of energy.
Edison has taken the position that the fixed energy price period expired in
August 1997 for the Navy I partnership and in March 1999 for the BLM
partnership, and will expire in January 2000 for the Navy II partnership. The
Coso partnerships believe that the power purchase agreements provide that each
of the three separate turbine generator units at each Coso project has its own
full ten-year fixed energy price period. This issue is one of several currently
in dispute and subject to an ongoing lawsuit between, among others, the Coso
partnerships and Edison. Without making any statement on the outcome of this or
any other dispute with Edison, for purposes of this prospectus only, including
the historical and pro forma financial information included herein, we have
assumed that the fixed energy price period expires ten years after the first of
the three generator units at each respective Coso project established firm
operation. We believe that this assumption is conservative and reasonable for
purposes of this prospectus given that we cannot predict the outcome of this
issue. See "Risk Factors--The Coso partnerships and their managing partners are
currently involved in material litigation with Edison, their sole customer" and
"Business--Legal Proceedings."
After the expiration of the fixed energy price period under the power
purchase agreements, Edison's monthly energy payment equals the product of the
kWh purchased by Edison for each on-peak, mid-peak, and off-peak time period
and Edison's published avoided cost of energy by time of delivery for each time
period. Edison's published avoided cost of energy is currently based on a
formula tied to the price of natural gas. Under AB1890, however, the California
Public Utilities Commission is required to calculate short-term avoided energy
costs for payments made to nonutility power generators such as the Coso
projects based on the clearing price paid by the California Power Exchange when
certain conditions are met. These conditions are discussed under the headings
"Risk Factors--Future energy payments paid by Edison to the Coso partnerships
will most likely be less than historical energy payments because they will be
paid based on Edison's avoided cost of energy" and "Business--Power Sales--
Energy Payments."
Changes in Contract Capacity
Each Coso partnership may terminate its power purchase agreement or reduce
its contract capacity by giving Edison the prescribed notice. Upon such
reduction, the Coso partnership must refund Edison an amount of money equal to
the difference between (1) the accumulated capacity
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payments already paid by Edison up to the time the notice is received and based
on the original contract term and (2) the total capacity payments which Edison
would have paid based on the Coso partnership's actual performance using the
"adjusted capacity price," as well as interest at the current published Federal
Reserve Board three months prime commercial paper rate on such amount.
Testing
At least once a year, at the request of Edison, each Coso partnership must,
at its own expense, demonstrate the ability of its plant to produce the
contract capacity for a reasonable period of time pursuant to mutually agreed
upon procedures.
Outages
Each Coso partnership must make all reasonable efforts to limit the outages
of its generating facility. Each Coso partnership must also make reasonable
efforts not to schedule routine maintenance in the months of June, July, August
and September, and in no event shall outages for scheduled maintenance exceed a
total of 30 peak hours during those months. Outage periods for scheduled
maintenance may not exceed 840 hours in any 12-month period. Each Coso
partnership may accumulate unused maintenance hours on a year-to-year basis up
to a maximum of 1,080 hours. This accrued time must be used consecutively and
only for major overhauls.
Curtailment
After the first ten years following the commencement of firm operation,
Edison is not required to accept or purchase, and may request that the Coso
partnership discontinue or reduce delivery of, energy during periods when such
purchases would result in Edison incurring costs greater than those which it
would incur if it instead generated energy from another of its sources or when
its system demand would require that its hydro-energy be spilled to reduce
generation. The power purchase agreements limit such curtailment to not more
than 300 hours annually during off-peak hours.
Uncontrollable Forces
Each party to the power purchase agreements is relieved from its obligations
under the relevant power purchase agreement (except for payment obligations)
when and to the extent that it is rendered wholly or partly unable to perform
its obligations by an uncontrollable force, provided that the nonperforming
party (1) gives the other party written notice describing the particulars of
the uncontrollable force within two weeks after the occurrence thereof, (2)
uses its best efforts to remedy its inability to perform, and (3) does not
suspend performance beyond the scope or duration required by the uncontrollable
force. If one of the Coso partnership's deliveries to Edison are interrupted or
reduced due to an uncontrollable force, Edison is required to continue capacity
payments for 90 days from the occurrence of the uncontrollable force. If a
party's ability to perform cannot be corrected when the uncontrollable force is
caused by the actions or inactions of legislative, judicial or regulatory
agencies, or other proper authority, the relevant power purchase agreement may
be amended to comply with the legal or regulatory change which caused the
nonperformance. If a loss of QF status occurs due to uncontrollable force and
the relevant Coso partnership fails to make the changes necessary to maintain
its Coso project's QF status, that Coso partnership will be required to
compensate Edison for any economic detriment incurred by it as a result of such
failure. "Uncontrollable Forces" include, but are not limited to, flood,
drought, earthquake, storm, fire, pestilence, natural catastrophes, war, riot,
strike, action or inaction of legislative, judicial or
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regulatory agencies or any occurrence beyond the control of the parties that
cannot be overcome by the exercise of due diligence.
Indemnification
Under the relevant power purchase agreement each party has agreed to
indemnify and hold harmless the other party, its directors, officers, and
employees or agents from and against any loss, damage, claim, cost, charge, and
associated costs and expenses, related to the injury to or death of any person
or damage to the property of a third party arising out of the indemnifying
party's construction, engineering, repair, supervision, inspection, testing,
protection, operation, maintenance, replacement, reconstruction, use, or
ownership of its facilities, other than for liability resulting from the
indemnified party's sole negligence or willful misconduct. Each party is also
responsible for claims brought by its contractors or employees and is required
to indemnify and hold harmless the other party for any such costs.
Insurance
Under the power purchase agreements, each Coso partnership is obligated to
obtain and maintain specified insurance coverages. If the Coso partnership
fails to maintain the required insurance, it must indemnify Edison for any
liabilities to the extent the insurance would have covered those liabilities.
Interconnection
The interconnection facility is designed, installed, operated and maintained
pursuant to an Interconnection and Integration Facilities Agreement.
The Navy Contract
In December 1979, CalEnergy entered into the Navy Contract with the Navy. The
Navy Contract granted to CalEnergy exclusive contractual rights to explore,
develop and use certain of the geothermal resource located within the United
States Naval Air Weapons Center at China Lake, California. Those rights were
subsequently transferred to China Lake Joint Venture, and certain of those
rights were subsequently transferred from China Lake Joint Venture to the Coso
partnerships. The Navy Contract has been modified on a number of occasions to
provide for, among other things, the assignment of all of China Lake Joint
Venture's rights under the Navy Contract to the Navy I partnership with respect
to Navy I and to the Navy II partnership with respect to Navy II, the
assignment of rights to the BLM/Navy II Transmission Line to Coso Transmission
Line Partners and the approval by the Navy of the steam sharing program among
the Coso partnerships. China Lake Joint Venture holds a residual interest in
the Navy Contract. For more information, see "Business--Overview of the Coso
Projects--Project History" and "--Steam Sharing and Co-Tenancy Agreements."
The term of the Navy Contract is for thirty years, expiring in December 2009,
after the last maturity date of the Series B notes. The Navy has the unilateral
right to extend the term of the Navy Contract for a ten-year period by giving
written notice. The Navy requires United States congressional approval to
exercise its option to extend the term of the Navy Contract.
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Rights and Obligations
Under the Navy Contract, the Navy I partnership and the Navy II partnership
enjoy, among other things, exclusive contractual rights to explore, develop and
use a portion of the Coso Known Geothermal Area in an area covering
approximately 3,520 acres. It is possible that these rights do not constitute
interests in real estate. See "Business--Insurance." The Navy I partnership and
Navy II partnership enjoy all rights to the payments set forth in the Navy
Contract, including all payments by Edison under the power purchase agreements,
and termination payments in the event the Navy exercises its right to terminate
the Navy Contract prior to the expiration of its term.
With respect to Unit 1 at Navy I, the Navy I partnership is obligated to pay
the Navy the sum of $25.0 million on or before December 31, 2009, the
expiration date of the term of the Navy Contract. Payment of this amount will
be made from an established sinking fund to which the Navy I partnership has
been making payments since 1987. As of June 30, 1999, there was approximately
$7.9 million on deposit in the sinking fund, representing both sinking fund
payments and accrued interest thereon. The Navy I partnership currently intends
to make aggregate annual payments to this sinking fund of approximately
$716,000 through 2009. See "Management's Discussion and Analysis of Financial
Condition and Result of Operations--Liquidity and Capital Resources."
Both the Navy I partnership and the Navy II partnership are required to pay
to the Navy royalties or the equivalent thereof, for electricity generated by
Units 2 and 3 at Navy I and the three units at Navy II. The percentage royalty
due to the Navy for Units 2 and 3 of Navy I is 15% of revenues received through
2003, 20% from 2004 through 2009, and, if the Navy elects to extend the term of
the Navy Contract, 22.0% thereafter. The percentage royalty due to the Navy for
Navy II is 10% of electricity sales through 1999, 18% from 2000 to 2004, 20%
from 2005 through 2010, and, if the Navy elects to extend the term of the Navy
Contract, 22.0% thereafter.
Termination
The Navy has the right to terminate the Navy Contract under circumstances
that include the convenience of the Navy. The Navy has the right to terminate
the contract at any time by giving the Navy I partnership or the Navy II
partnership, or both, as applicable, six months' prior written notice for
"reasons of national security, national defense preparedness, national
emergency, or for any reasons the Contracting Officer shall determine that such
termination is in the best interest of the U.S. Government."
Upon the expiration of the Navy Contract, title to the wells and casings will
revert to the Navy with no remuneration to the Navy I partnership or the Navy
II partnership. Title to all of the fixtures, facilities and equipment will
remain with the Navy I partnership and Navy II partnership. However, the Navy
has an option to purchase all of the above mentioned fixtures, facilities and
equipment (at a price to be determined), or the Navy may require that the Navy
I partnership and the Navy II partnership remove the fixtures, facilities and
equipment within a reasonable time after expiration of the Navy Contract, at no
cost to the Navy.
If the Navy were to terminate the Navy Contract, the Navy would be required
to pay the Navy I partnership or the Navy II partnership or both, as
applicable, for the unamortized portion of their exploratory investment and for
their investment in installed power plant facilities. There is a cap on the
amounts the Navy would be required to pay as compensation on such termination,
based on the nameplate capacity of the turbine generators. With respect to each
of the Navy I partnership and the Navy II partnership, for the first aggregate
25 MW, the cap is $2.7 million per MW, and for the next
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25 MW (i.e., up to 50 MW), the cap is $2.5 million per MW. For 50 to 75 MW, the
cap is $1.4 million per MW for the Navy I partnership and $2.3 million per MW
for the Navy II partnership. For a total nameplate capacity of 75 MW for Navy I
or Navy II, the total cap in termination compensation would be $165.0 million
for the Navy I partnership and $187.5 million for the Navy II partnership. The
total aggregate termination compensation for the Navy I partnership and the
Navy II partnership would therefore be approximately $352.5 million. The Navy
Contract does not provide for compensation to either the Navy I partnership or
the Navy II partnership for the loss of anticipated profits resulting from such
termination or to the BLM partnership for any detrimental effect on it from the
termination of the Navy Contract.
In addition to its right to terminate the Navy Contract, the Navy may, from
time to time, impose certain access and operational restrictions on the Navy I
partnership and the Navy II partnership for purposes of national security,
personnel safety, protection of property or protection of the environment, and
under certain circumstances may impose emission standards. The Navy has
periodically ordered all personnel at the Coso projects to evacuate the
facilities on several occasions. During evacuation periods, the operators
continue to operate the Coso projects via a remote station located at the
outskirts of the Navy base. This station currently utilizes rights of way that
CalEnergy originally obtained from the Bureau of Land Management. CalEnergy
recently assigned these rights of way to the Coso partnerships as tenants-in-
common with the approval of the Bureau of Land Management. See "Risk Factors--
The Navy could terminate the Coso partnerships' rights to use the Coso
geothermal resource at any time."
The BLM Lease
On April 29, 1985, CalEnergy and the Bureau of Land Management entered into
the BLM lease. Under the BLM lease, CalEnergy acquired a leasehold interest in
approximately 2,550 acres of land, including the contractual right to drill
for, extract, produce, remove, use, sell and dispose of the geothermal resource
thereon. The land is also located at the United States Naval Air Weapons Center
at China Lake. Through various assignments, effective May 1, 1988, the BLM
lease was assigned to the BLM partnership. The BLM Lease was recorded on May 9,
1988, as Instrument No. 88-2092, in the Official Records of Inyo County,
California, and the assignment to the BLM partnership was recorded on the same
date.
Coso Land Company intends to assign to the BLM partnership a leasehold
interest granted by the Bureau of Land Management in an additional parcel of
land (referred to as lease CA 11401) that is adjacent to the BLM lease. This
assignment is subject to the consent of the Bureau of Land Management. The
Bureau of Land Management's consent has recently been received but is subject
to a requirement in the financing documents that certain additional title
documentation be delivered to it, and that delivery is currently in process.
The leasehold interest will expire on November 17, 2002 unless extended by
production. In addition, Coso Land Company holds leasehold interests granted by
the Bureau of Land Management in certain additional leases from the Bureau of
Land Management. These additional leases are located within several miles of
the property covered by the BLM lease. These additional leases are not
currently producing any geothermal resources, are not expected to be needed for
the Coso projects and may be surrendered to the Bureau of Land Management or
allowed to expire.
The primary term of the BLM lease has expired. The BLM lease provides,
however, that the term of the BLM Lease will be extended automatically "so long
thereafter as geothermal steam is produced or utilized in commercial quantities
but shall in no event continue for more than forty
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(40) years after the end of the primary term." This automatic extension due to
the continuation of production is termed being "held by production." Since the
BLM lease is deemed "held by production," the BLM lease has been automatically
extended and the BLM partnership continues to have rights under the BLM lease.
The BLM partnership also enjoys a preferential right of renewal of the BLM
lease for an additional 40-year term if geothermal steam is being produced or
utilized in commercial quantities and the leased land is not needed for other
purposes.
Pursuant to the BLM lease, the Navy controls all activities on the surface of
the real property covered by the BLM lease. In addition, the BLM partnership
must comply with certain "Navy Constraints on Naval Weapon Center Lands." These
constraints include, among other things, certain security measures and
restrictions of access, the Navy's right to suspend operations if an imminent
threat to the environment is presented, permitting requirements, information
and data exchange, and the Navy's right of inspection. For related information,
see "--The Navy Contract." The Bureau of Land Management has retained the right
to grant easements and other rights of way to third parties with respect to the
leased property, so long as those rights do not create unnecessary or
unreasonable interference with the BLM partnership's activities or the
property.
The BLM partnership pays royalties to the Bureau of Land Management under the
BLM Lease. Royalties are 10% of the value of steam produced. This rate is fixed
for the life of the BLM Lease. The Bureau of Land Management has the right to
establish minimum and maximum production levels of steam after notice and a
hearing, and the right to reduce the royalty rate if necessary to encourage the
greater recovery of leased resources, or as otherwise justified.
BLM leases that are "held by production" or that are known to contain wells
capable of production of commercial qualities cannot be canceled without prior
notice and a hearing. BLM leases can also be terminated by operation of law, as
follows: (1) at the anniversary date, for failure to pay the full amount of the
annual rental by that date, and (2) at the end of the primary term, if there is
no production in commercial quantities, there is no producing well or actual
drilling operations are not being diligently prosecuted.
Upon termination of the BLM Lease, the BLM partnership is required to place
all wells in condition for suspension or abandonment, reclaim the land and,
within a reasonable time, remove all the equipment or improvements that the
Bureau of Land Management does not deem necessary for the preservation of
producible wells or protection of the environment.
O&M Agreements
O&M Agreements with FPL Operating
The Coso partnerships entered into three separate O&M agreements with FPL
Operating. The initial term of these O&M agreements is for three years with an
automatic three year extension unless either party notifies the other party at
least 90 days prior to expiration that it does not intend to extend the term of
the O&M agreement. Except for certain services to be performed by Coso
Operating Company, the plant operation and maintenance services are performed
by FPL Operating pursuant to the O&M agreements. FPL Operating's O&M agreements
provide that FPL Operating will do all things necessary or advisable for the
proper operation and maintenance of the geothermal power facilities, the
interconnection to the transmission line, the geothermal wells and related
fluid handling, gathering and distribution systems and perform certain other
services specified in the O&M agreements. It will also operate and maintain the
Navy I Transmission Line and the BLM/Navy II Transmission Line.
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FPL Operating's general duties include, among others:
. supervision of operations and maintenance at the plants, the
interconnection to the transmission lines, the wells and related fluid
handling, the gathering system and any and all technical and engineering
support required for such operations and maintenance;
. the purchase of all materials, supplies, consumables, parts, equipment,
vehicles, utilities and other items necessary to conduct normal
operations and maintenance;
. scheduling all outages and maintenance shutdowns;
. contracting with third parties as may be necessary for the performance of
specialized services;
. maintaining safety and security programs;
. complying with applicable laws and obtaining and maintaining all
government permits, licenses and approvals required of FPL Operating in
connection with the operation of the Coso projects; and
. complying with all federal, state and local laws/ordinances and
regulations relating to industrial hygiene or releases to the
environment.
As compensation for such services, each Coso partnership has agreed to pay to
FPL Operating an annual fee of $134,000, $100,000 and $84,000 in the first,
second and third years, respectively, of the O&M agreements with FPL Operating
(or an aggregate of $402,000, $300,000 and $252,000, respectively). Adjustments
to the compensation may be made if a "Change of Conditions" occurs. A Change of
Conditions includes, among other things, modifications to the facility or the
power purchase agreements, directions from the Coso partnerships to perform
services different from, or in addition to, those originally contemplated, or
the occurrence of an uncontrollable event. In addition, each Coso partnership
has agreed to reimburse FPL Operating for all properly incurred costs and
expenses and reimburse FPL Operating for the performance incentive bonuses that
it pays its employees.
The Coso partnerships have the right under the O&M agreements with FPL
Operating to terminate those agreements upon six months' prior notice or under
certain circumstances, including the occurrence of a total or partial failure
of the geothermal wells and uncured defaults. FPL Operating also has the right
to terminate any of its O&M agreements with the Coso partnerships upon six
months' prior notice or under certain circumstances, including any material
uncured default by the relevant Coso partnership.
At the closing of Caithness Acquisition's purchase of all of ESI Geothermal's
indirect ownership interests in the Coso partnerships, FPL Operating is
expected to assign to Coso Operating Company all of its rights, duties and
obligations under FPL Operating's O&M agreements. No other changes to
FPL Operating's O&M agreements are expected to be made. Coso Operating Company
will assume all of FPL Operating's duties and obligations under FPL Operating's
O&M agreements and become the sole operator of all of the plants and fields
located at the Coso projects, using substantially all of the same personnel who
are currently engaged by FPL Operating and Coso Operating Company at the Coso
projects. Coso Operating Company, as a successor operator, will also be
entitled to receive the O&M fees and reimbursable expenses provided under FPL
Operating's O&M agreements from and after the closing of the assignment and
assumption of these O&M agreements. See "Prospectus Summary--Recent
Developments--Purchase of FPL Interests; Assignment of FPL O&M Agreements."
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O&M Agreements with Coso Operating Company
The Coso partnerships have also entered into three field O&M agreements with
Coso Operating Company. The terms of these field O&M agreements expire on
December 31, 2009. Pursuant to these field O&M agreements, Coso Operating
Company provides certain services for the Coso projects, including among
others:
. exploring for new well sites, drilling new wells, and completing,
testing, and making available new wells for tie in to the resource
gathering systems of the Coso projects;
. drilling, testing, workover and repair work and making available new
wells to the disposal system;
. providing accounting, financial and tax services for the Coso
partnerships; and
. performing well workovers and related activities and all reservoir and
resource management related services and reservoir engineering and
geologic activities with respect to the field and sub-surface reservoir,
including:
. scheduling and supervising well testing,
. well surveys,
. maintaining production data bases,
. reservoir modeling,
. identifying candidates for well workovers,
. acid jobs,
. providing reports on resource availability,
. declines,
. production projections,
. targeting new wells,
. providing three dimensional models of the reservoir,
. maintaining and distributing maps, and
. scheduling and supervising geologic geophysical and/or geochemical
surveys.
As compensation for such services, each Coso partnership has agreed to pay
Coso Operating Company an annual fee of $532,000, $400,000 and $334,000 in the
first, second and third years, respectively, of the O&M agreements with Coso
Operating Company (or an aggregate of $1.6 million, $1.2 million and $1.0
million, respectively). In addition, each Coso partnership has agreed to pay
all proper costs and expenses incurred by the Coso Operating Company and
reimburse Coso Operating Company for the performance incentive bonuses that
Coso Operating Company pays to its employees, as set forth in the O&M
agreements with Coso Operating Company.
The LADWP Leases
In 1997, LADWP assigned to Coso Land Company, one of our affiliates, all of
its rights and interests in certain wells and related equipment located at BLM
North. BLM North covers approximately 6,825 acres of land and is located
adjacent to the real property covered by the Navy
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Contract. Under the LADWP leases, Coso Land Company has the right to drill for,
extract, produce, remove, use, sell and dispose of the geothermal resources
located on BLM North. Coso Land Company originally entered into the lease
assignment with the LADWP to obtain access to additional steam to supplement
the steam available for transfer among the Coso projects' plants under the
steam sharing program.
Coso Land Company has applied to the Bureau of Land Management for assignment
to each Coso partnership of an undivided one-third interest in the LADWP leases
as a tenant-in-common. This assignment is subject to the consent of the Bureau
of Land Management. The Bureau of Land Management's consent has recently been
received but is subject to a requirement in the financing documents that
certain additional title documentation be delivered to it, and that delivery is
currently in process. Once this assignment becomes effective, the Coso
partnerships will assume all of Coso Land Company's obligations under the LADWP
leases and will reimburse Coso Land Company for the costs it incurred in
acquiring the LADWP leases. These costs were approximately $1.0 million.
The primary terms of two of the LADWP leases expire on December 24, 2002, and
the primary term of one of the LADWP leases expires on September 23, 2004. The
terms of the LADWP leases will be extended automatically "so long thereafter as
geothermal steam is produced or utilized in commercial quantities but shall in
no event continue for more than forty (40) years after the end of the primary
term. This automatic extension due to the continuation of production is termed
being "held by production." Coso Land Company enjoys, and after the effective
date of the assignment the Coso partnerships will enjoy, a preferential right
of renewal of the LADWP leases for an additional 40-year term so long as
geothermal steam is being produced or utilized in commercial quantities and the
leased lands are not needed for other purposes.
As of June 30, 1999, the Coso partnerships were producing steam from two
production wells located on one of the LADWP leases (referred to as LADWP lease
CA 11384) and were injecting fluids into an injection well located on a second
LADWP lease (referred to as LADWP lease CA 11385). Another well located on the
LADWP lease CA 11385 is capable of producing geothermal steam, but it has not
been connected to the Coso projects' gathering system. The Bureau of Land
Management has determined that LADWP lease CA 11384 is held by production.
LADWP lease CA 11385 should also be deemed "held by production" and, although
the Bureau of Land Management has not yet made that determination, we expect it
to be automatically extended as well, but we cannot assure you it will be.
Although the third LADWP lease (referred to as LADWP lease CA 11383) has no
wells on it. The Coso partnerships expect that they may produce steam in the
future from the property covered by the third LADWP lease.
Steam Sharing and Co-Tenancy Agreements
The Coso partnerships have implemented and intend to expand a steam sharing
program which they established under a Coso Geothermal Exchange Agreement,
which we call the steam sharing agreement, entered into by the Coso
partnerships in 1994 and amended in 1995. The purpose of the steam sharing
program is to enhance management of the Coso geothermal resource and to
optimize its overall benefits to the Coso partnerships. Pursuant to the steam
sharing agreement, the Coso partnerships constructed an inter-project steam
supply system which links the three Coso projects together via metered transfer
lines through which the Coso partnerships may exchange steam and other
geothermal resources with one another and thereby make optimum use of available
steam to maximum revenues at the Coso projects. As part of this program, the
Coso partnerships plan to conserve the geothermal resource whenever possible
by, among other things, (1) transferring steam
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between and among the Coso projects and BLM North, rather than drilling new
wells at the Coso projects' sites prematurely, and (2) extending a flexible
field-wide water reinjection program.
The Coso partnerships' use of BLM North will be governed by a Cotenancy
Agreement that will provide for the shared ownership of the LADWP leases and
two rights of way granted by the Bureau of Land Management that pertain to (1)
an off-site location used for remote operation of the Coso projects when the
Navy orders evacuations of the plants and fields and (2) the telephone lines
used for the Coso projects. See "--The Navy Contract." Pursuant to this
agreement, the Coso partnerships will each hold, as tenants-in-common, an
undivided one-third working interest in the geothermal resources located at BLM
North. The Cotenancy Agreement will entitle each of the Coso partnerships,
subject to applicable consents, to use BLM North for geothermal resource
production and injection purposes if the Coso partnership determines, in its
exercise of its reasonable business judgment, that it has insufficient steam
economically available to it from other sources.
The steam sharing agreement requires that the Coso partnerships share equally
in the cost of the inter-project steam supply system and includes a formula
that is used to calculate the payments made between or among the Coso
partnerships. In addition, transfers of steam made pursuant to the steam
sharing program generates royalties due by the Coso partnerships to the Navy
and the Bureau of Land Management. The formula for calculating the royalty due
to the Navy has been incorporated by modification into the Navy Contract and
has recently been amended to reflect the addition of the geothermal resources
located on land covered by the LADWP leases. The royalty due to the Bureau of
Land Management is governed by the underlying leases and an Agreement for the
Calculation of Minerals/Revenues that was entered into in 1994. Each of the
Navy and the Bureau of Land Management has provided the consents necessary for
transfers of steam between and among the Coso projects pursuant to the steam
sharing program, but it has, however, reserved the right to suspend, terminate
or withdraw its consent in its sole discretion under certain circumstances.
With respect to the use of the geothermal resources located under the land
covered by the LADWP leases, the Navy has currently consented only to use by
BLM of steam produced from those lands provided that any steam transferred from
property leased from the Bureau of Land Management to Navy I or Navy II must be
offset by transfers within the same month to BLM of steam from wells located on
property leased from the Navy. The reason for the Navy's limited consent is to
avoid the difficulties that arise by virtue of the fact that the energy price
paid to the Navy II partnership under its power purchase agreement remains
fixed rather than paid at Edison's avoided cost of energy. Once the fixed
energy price period at Navy II expires in January 2000, we anticipate that the
Navy will consent to additional transfers of steam between BLM North and the
Coso projects.
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REGULATION
Energy Regulation
PURPA
PURPA provides an electric generating project with rate and regulatory
incentives and exemptions if the project is a QF. There are two types of QFs:
Small Power QFs and Cogeneration QFs. Under PURPA, a power production facility
is a Small Power QF if (i) the facility satisfies certain maximum size
criteria, (ii) the primary energy source of the facility is biomass, waste,
renewable resources or any combination thereof, and 75% of the total energy
input is from these sources, and (iii) the facility is owned by a person not
primarily engaged in the generation or sale of electric power (other than
electric power solely from cogeneration facilities or small power production
facilities). The maximum size criteria, however, do not apply to a facility
that is an "eligible solar, wind, waste or geothermal facility," as defined in
Section 3(17)(E) of the Federal Power Act. A facility qualifies for this
exemption if: (1) it produces electric energy solely by the use, as a primary
energy input, of solar, wind, waste or geothermal resources; (2) an application
for certification or a notice of self-certification of qualifying status of the
facility was submitted to the FERC prior to December 31, 1994; and (3)
construction of the facility commenced prior to December 31, 1999. The Coso
projects have satisfied these requirements and thus are exempt from the size
limitation applicable to Small Power QFs.
Under PURPA, QFs receive two primary benefits. First, PURPA exempts QFs, such
as the Coso projects, from the definition of "electric utility company" under
the Public Utility Holding Company Act of 1935 ("PUHCA"), most provisions of
the Federal Power Act and certain state laws relating to financial,
organization and rate regulation of electric utilities. Second, the regulations
promulgated by FERC under PURPA require that (i) electric utilities purchase
electricity generated by QFs, construction of which commenced on or after
November 9, 1978, at a rate based on the purchasing utility's full "avoided
costs" and (ii) the utilities sell supplementary, back-up, maintenance and
interruptible power to QFs on a just and reasonable and nondiscriminatory
basis. FERC's regulations define "avoided costs" as the "incremental costs to
an electric utility of electric energy or capacity or both which, but for the
purchase from the qualifying facility or qualifying facilities, such utility
would generate itself or purchase from another source." Utilities may also
purchase power at prices other than avoided cost of energy pursuant to
negotiations as provided by FERC's regulations.
We expect that the Coso projects will continue to meet all of the criteria
required for certification as QFs under PURPA. If any Coso project were to fail
to meet such criteria, the Coso partnership that owns that Coso project may
become subject to regulation as a public utility company or its equivalent
under PUHCA and the Federal Power Act. Each Coso partnership has warranted to
Edison that it will maintain the QF status of its respective Coso project
throughout the term of the related power purchase agreement and each of the
Coso partnerships is required under the Indenture to maintain the QF status of
its respective Coso project.
As discussed under the heading "Risk Factors--The operations of the Coso
projects could be adversely affected by an inability to comply with regulatory
standards," it is possible, however, that (1) PURPA could be repealed or
amendments to PURPA could be enacted that substantially reduce the benefits
currently afforded QFs, or (2) the requirements for the Coso projects to
maintain their status as QFs could be made more burdensome. In such event,
operations at the Coso projects or compliance with the terms of the power
purchase agreements could be adversely affected, and the
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Coso partnerships' ability to make payments under their project notes and
guarantees, and our ability to make payments of principal, premium, if any,
and interest on the Series B notes when due, could be materially and adversely
affected.
PUHCA
PUHCA provides that any corporation, partnership or other entity or
organized group that owns, controls or holds power to vote 10% or more of the
outstanding voting securities of a "public utility company" (which is defined
to include an "electric utility company" or a "gas utility company") or a
company that is a "holding company" of a "public utility company" is subject
to registration with the SEC and to regulation under PUHCA, unless exempted by
SEC rule, regulation or order. An entity may also be deemed to be a holding
company if the SEC determines, after providing notice and an opportunity for a
hearing, that such entity exercises a controlling influence over the
management or policies of any public utility or holding company as to make it
necessary or appropriate in the public interest or for the protection of
investors or consumers that such entity be regulated as a holding company.
Unless an exemption is obtained, PUHCA requires registration for a holding
company of a public utility company, and requires a public utility holding
company to limit its utility operations to a single integrated utility system
and to divest any other operations not functionally related to the operation
of the utility system. In addition, a public utility company that is a
subsidiary of a registered holding company under PUHCA is subject to financial
and organizational regulation, including approval by the SEC of its financing
transactions.
The Energy Policy Act of 1992 (the "Policy Act") contains amendments to
PUHCA that may allow the Coso partnerships to operate their businesses without
becoming subject to PUHCA in the event that any Coso project loses its status
as a QF. Under the Policy Act, a company may be exempted from PUHCA if it is
engaged exclusively in the business of owning and/or operating one or more
facilities used for the generation of electric energy exclusively for sale at
wholesale and selling electric energy at wholesale. To qualify for such an
exemption, a company must apply to FERC for a determination of eligibility,
pursuant to implementing rules promulgated by FERC. However, since the power
purchase agreements require each Coso partnership to maintain the QF status of
its respective Coso project, obtaining this exemption would not eliminate the
need to amend or replace the power purchase agreements if the current QF
status is lost. Moreover, although the Policy Act and its implementing rules
provide certain exemptions from PUHCA, the Policy Act may also encourage
greater competition in wholesale electricity markets which could result in a
decline in long-term rates to be paid by electric utilities, including Edison.
Even if a Coso partnership obtained an exemption from PUHCA pursuant to the
Policy Act and implementing rules, in the event that QF status is revoked or
otherwise not maintainable, the applicable Coso partnership would be subject
to regulation as a "public utility" under the Federal Power Act, as described
below.
Federal Power Act
Under the Federal Power Act, FERC has exclusive rate-making jurisdiction
over wholesale sales of electricity and transmission in interstate commerce.
These rates may be based on a cost of service approach or may be determined
through competitive bidding or negotiation. If a Coso project loses its QF
status, the rates set forth in its power purchase agreement would have to be
filed with FERC and would be subject to review by FERC under the Federal Power
Act. Under FERC policy, the rates under those circumstances could be no higher
than Edison would have paid for energy had it not been required to purchase
from such Coso project under PURPA's mandatory purchase requirements, i.e.,
Edison's economy energy (incremental) cost during the period of non-compliance
with QF
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requirements, unless the applicable power purchase agreement otherwise provides
for alternative rates to apply in the event of such loss of QF status. The
power purchase agreements do not contain such a provision nor do they contain
provisions for a renegotiation of the rates to be paid for electric energy in
the event of loss of QF status.
The Federal Power Act and FERC's authority under the Federal Power Act
subject public utilities to various other requirements, including accounting
and record-keeping requirements; FERC approval requirements applicable to
activities such as selling, leasing or otherwise disposing of facilities; FERC
approval requirements for mergers, consolidations, acquisitions and the
issuance of securities; and certain restrictions regarding affiliations of
officers and directors. Certain of these requirements, however, are typically
waived by FERC for public utilities that do not serve captive retail customers,
for example, entities known as exempt wholesale generators, or EWGs.
Accordingly, if a Coso project were to lose its QF status, the related Coso
partnership may be able to obtain EWG status and FERC would likely extend the
same waivers of certain of these requirements to that Coso partnership.
State Regulation
The Coso projects, by virtue of being QFs, are exempt from California rate,
financial and organizational regulations that are applicable to public
utilities. QFs, however, are not exempt from the California regulatory
commission's general supervisory powers relating to environmental and safety
matters.
In the event the Coso projects were to lose their QF status, while they would
become subject to the Federal Power Act and, potentially, PUHCA regulation,
they would nonetheless continue to be exempt from public utility regulation
under state law. Under California law, ownership or operation of a facility
that produces power from other than a conventional power source, such as
geothermal energy, does not make a company a public utility. Similarly,
California law excludes from the definition of public utility a company that
has been determined by FERC to be an exempt wholesale generator under PUHCA.
Wheeling and lnterconnection
Under the Federal Power Act, FERC is authorized to regulate the rates, terms
and conditions for the transmission of electric energy in interstate commerce.
This has been interpreted to mean that FERC has jurisdiction to prescribe the
terms of and to set the rates contained in agreements for the transmission of
electric energy when the applicable transmission system is interconnected and
capable of transmitting energy across a state boundary, even if the utility has
no direct connection with another utility outside its state but is
interconnected with another utility that in turn has interstate connections
with other utilities.
FERC's authority under the Federal Power Act to require electric utilities to
provide transmission service to QFs and other wholesale electricity producers
has been significantly expanded by the Policy Act. Pursuant to the Policy Act,
the Coso partnerships may apply to FERC for an order requiring a utility to
provide transmission services in order to transmit power to a wholesale
purchaser. FERC may issue such an order if FERC determines that such order
would promote the economically efficient transmission and generation of
electricity, would be just and reasonable and not unduly discriminatory or
preferential and otherwise would be in the public interest, provided that the
reliability of the affected electric systems would not be unreasonably
impaired. In addition, in
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April 1996, FERC issued an order directing transmission-owning utilities that
are subject to FERC jurisdiction, including Edison, to file transmission
tariffs providing for non-discriminatory transmission service on terms
comparable to those the transmission owner imposed on itself. Edison has now
complied with this open access order (although operational control of the
majority of Edison's transmission facilities has now been turned over to the
ISO). In addition, the ISO has filed an open access tariff in compliance with
the FERC order. As a result, the Coso partnerships would be able to obtain
transmission service through the ISO (or through Edison's open access tariff,
if necessary), subject to availability, should electricity sales to another
purchaser be necessary or desirable. Thus, the Policy Act and FERC's open
access order have presumably enhanced the Coso partnerships' ability to obtain
transmission access necessary to sell electric energy or capacity to purchasers
other than Edison if a power purchase agreement is terminated. There can be no
assurance, however, that FERC would issue an order mandating transmission
service for the Coso partnerships or that the rates for open access or FERC-
ordered transmission service would be economical for the Coso partnerships.
California Deregulation
In September 1996, AB1890 was enacted to open electric generation in
California to competition while leaving in place the regulated system of power
transmission and distribution. Among the significant provisions of this
legislation are (1) electric rate relief or rate freezes, (2) public benefit
programs, (3) funding for the support of renewable generation and (4)
transition mechanisms for utilities to recover stranded costs that have become
uneconomic by the change in public utility law and the move to a competitive
market. AB1890 reaffirmed that stranded costs resulting from above-market power
purchase agreements which the California Public Utilities Commission had
previously authorized for collection in rates, including the power purchase
agreements, will be recoverable by the utility over the remaining terms of
those power purchase agreements.
An integral component of AB1890 is the formation of the California Power
Exchange and ISO. The California Power Exchange is intended to operate like an
open and transparent commodities market where power producers will compete to
sell their generation and the ISO is intended to be a private entity that
provides all market participants with non-discriminatory access to the
transmission system, while maintaining system security and reliability. The
California Power Exchange and ISO began operations on March 31, 1998. Since
that time, the California Power Exchange has expanded its clearing mechanisms
for day-ahead bidding, the only mechanism available at inception, to include an
hour-ahead mechanism, beginning in August 1998. Further expansions of
California Power Exchange clearing mechanisms are currently planned and
scheduled for introduction in the near future. The ISO is also in the process
of refining its operations and responding to market conditions such as the
recent price spikes for certain ancillary services. Other aspects of ISO PX
operations and services are in the process of implementation as well. As
discussed under the headings "Risk Factors--The operations of the Coso projects
could be adversely affected by an inability to comply with regulatory
standards," and "Risk Factors--Future energy payments paid by Edison to the
Coso partnerships will most likely be less than historical energy payments
because they will be paid based on Edison's avoided cost of energy," the new
market structure in California raises novel regulatory and implementation
issues, which the various regulatory agencies and market participants are still
in the process of resolving. The process of development of the ISO PX system
will have significant effects on the Coso partnerships, given that Edison is
currently required to sell QF power through the
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<PAGE>
California Power Exchange, and that Edison's avoided cost of energy will be set
to equal the California Power Exchange clearing price in the next two or three
years.
In addition to actions taken by the California Legislature and regulation by
the California Public Utilities Commission, bills have been and are being
introduced into the United States Congress mandating the deregulation of the
electric utility industry on the state level, as discussed above under the
heading "Risk Factors--The operations of the Coso projects could be adversely
affected by an inability to comply with regulatory standards."
135
<PAGE>
MANAGEMENT
Funding Corp.
The following table sets forth the persons who currently serve as our
directors and executive officers as of June 30, 1999:
<TABLE>
<CAPTION>
Name Age Position(s)
<S> <C> <C>
James D. Bishop, Sr. .... 66 Director, Chairman and Chief Executive Officer
Leslie J. Gelber......... 43 Director, President and Chief Operating Officer
James D. Bishop, Jr. .... 39 Director, Vice Chairman
Christopher T. McCallion. 37 Director, Executive Vice President and Chief Financial Officer
Larry K. Carpenter....... 49 Director, Executive Vice President
James C. Sullivan........ 71 Director, Senior Vice President and Secretary
Mark A. Ferrucci......... 47 Director
David V. Casale.......... 36 Vice President and Controller
Robert E. Tucker......... 46 Vice President
Barbara Bishop Gollan.... 41 Vice President
</TABLE>
James D. Bishop, Sr., Chairman, Chief Executive Officer and a Director of
Funding Corp. and of Caithness Energy, has served as a Director of Caithness
Corporation since its inception in 1975. Mr. Bishop served as Caithness
Corporation's President from its inception until December 1986 and as Chairman
of Caithness Corporation from January 1987 until the present. Mr. Bishop also
serves as a director for various other entities which engage in independent
power production and natural resource exploration and development. Mr. Bishop
holds a Master of Business Administration degree from Harvard Business School
and a Bachelor of Arts degree from Yale University. Mr. Bishop is the father of
James D. Bishop, Jr. and Barbara Bishop Gollan.
Leslie J. Gelber, President, Chief Operating Officer and a Director of
Funding Corp. and of Caithness Energy, has served as President and Chief
Operating Officer of Caithness Corporation since January 1999. Prior to joining
Caithness Corporation, Mr. Gelber served as President of Cogen Technologies,
Inc., which is also engaged in the field of independent power production, from
August 1998 until December 1998. From July 1993 to July 1998, Mr. Gelber served
as President of ESI Energy, Inc., the non-regulated independent power company
owned by FPL Group, Inc. Mr. Gelber holds a Master of Business Administration
degree from the University of Miami and holds a Bachelor of Arts degree in
Economics from Alfred University.
James D. Bishop, Jr., Vice Chairman and a Director of Funding Corp. and of
Caithness Energy, joined Caithness Corporation in 1988 and has served as
President and Chief Operating Officer of Caithness Corporation from November
1995 until December 1998. Mr. Bishop also serves on all of the boards of
directors and management committees of the entities and joint ventures
affiliated with Caithness Corporation. Mr. Bishop holds a Master of Business
Administration degree from the Kellogg Graduate School of Management at
Northwestern University and holds a Bachelor of Science degree from Trinity
College. Mr. Bishop is the son of James D. Bishop, Sr. and the brother of
Barbara Bishop Gollan.
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<PAGE>
Christopher T. McCallion, Executive Vice President, Chief Financial Officer
and a Director of Funding Corp. and of Caithness Energy, served as Vice
President and Controller of Caithness Corporation from July 1991 to November
1995, and has served as Executive Vice President and Chief Financial Officer of
Caithness Corporation since November 1995. Mr. McCallion holds a Bachelor of
Science degree from Seton Hall University.
Larry K. Carpenter, Executive Vice President and a Director of Funding Corp.
and of Caithness Energy, has served as an Executive Vice President of Caithness
Corporation since January 1999. Prior to joining Caithness Corporation, Mr.
Carpenter served as Vice President of Development at ESI Energy, Inc., the non-
regulated independent power company owned by FPL Group Inc., from 1985 to
December 1998. Mr. Carpenter holds a Bachelor of Science degree in Electrical
Engineering from the University of Florida.
James C. Sullivan, a Senior Vice President, Secretary and a Director of
Funding Corp. and of Caithness Energy, has served as Senior Vice President,
Secretary and a Director of Caithness Corporation since April 1996.
Mr. Sullivan attended Holy Cross Seminary at Notre Dame University, Indiana
University and the University of Tokyo before graduating from the State
University of California at Pasadena.
Mark A. Ferrucci, a Director of Funding Corp., has served as the independent
director of Funding Corp. since May 1999. Since 1997, Mr. Ferrucci has been an
employee of CT Corporation System, an independent company that provides
corporate and UCC services to businesses and law firms. From 1977 until 1992,
Mr. Ferrucci served as CT Corporation System's Assistant Secretary and as
Assistant Vice President of CT Corporation System from 1992 until the present.
David V. Casale, a Vice President and the Controller of Funding Corp. and of
Caithness Energy, joined Caithness Corporation in December 1991 and has served
as a Vice President and as its Controller since November 1995. Mr. Casale holds
a Bachelor of Arts degree from Adelphi University and is a Certified Public
Accountant.
Robert E. Tucker, a Vice President of Funding Corp. and of Caithness Energy,
joined Caithness Corporation in September 1990 and has served as a Senior Vice
President of Caithness Corporation since January 1993. Mr. Tucker holds a
Master of Science degree in Mechanical Engineering and a Bachelor of Science
degree in Mechanical Engineering from Purdue University.
Barbara Bishop Gollan, a Vice President of Funding Corp. and of Caithness
Energy, joined Caithness Corporation as Vice President in October 1990. Ms.
Gollan has authored and co-authored a number of technical papers on geothermal
systems, which were presented to the Geothermal Resources Council, the Geologic
Society of America and the Stanford Geothermal Workshop. Ms. Gollan holds a
Master of Science degree in Geology and Geochemistry from Stanford University
and holds a Bachelor of Arts degree from Amherst College. Ms. Gollan is the
daughter of Mr. James D. Bishop, Sr. and sister of James D. Bishop, Jr.
In connection with the closing of the Series A notes offering, our Board of
Directors appointed Mr. Ferrucci as an independent director. The unanimous
affirmative vote of our Board of Directors (including Mr. Ferrucci) is required
before we can take certain actions, including, but not limited to, (1) engaging
in any business or activity other than issuing the senior secured notes and
making the related loans to the Coso partnerships, (2) incurring any debt, or
assuming or guaranteeing any debt of any other entity, (3) dissolving or
liquidating, (4) consolidating, merging or selling all or substantially all of
our assets or (5) instituting any bankruptcy or insolvency proceedings.
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<PAGE>
None of our directors and executive officers receives any compensation from
us for his or her services, except that nominal compensation is paid in
consideration for Mr. Ferrucci's services.
The Coso Partnerships
Each of the Coso partnerships has two general partners, a managing partner
and a non-managing partner. Under the amended and restated partnership
agreement of each Coso partnership, the managing partner of the Coso
partnership is generally responsible for the management and control of the day-
to-day business and affairs of the Coso partnership and acts on behalf of the
Coso partnership. The managing partner of the Navy I partnership is New CLOC,
the managing partner of the BLM partnership is New CHIP and the managing
partner of the Navy II partnership is New CTC. See "Business--The Coso
Partnerships."
Each managing partner is a limited liability company which is managed by a
manager who is appointed by Caithness Acquisition, the sole member of each
managing partner. The manager is responsible for the ordinary course management
and operations by its Coso partnership of that partnership's Coso project.
Caithness Acquisition has appointed itself as the manager of each managing
partner. Caithness Acquisition has also appointed Mr. Ferrucci as the
independent manager of each managing partner. (In addition, each of the
managing members of the non-managing partners has appointed Mr. Ferrucci as the
independent manager of that non-managing partner.) The approval of the
independent manager is required before the managing partner (or the non-
managing partner, as the case may be) may take certain actions that do not
involve the ordinary course management and operations by the Coso partnerships
of the Coso projects, including, among others, (1) commencing any bankruptcy or
insolvency proceeding involving the managing partner, (2) incurring any debt in
the name of the managing partner for which it would be liable, (3) dissolving,
liquidating, consolidating or merging, or selling all or substantially all of
the assets of, its respective Coso partnership, or (4) engaging in any business
or activity other than acting as the managing partner of its respective Coso
partnership. Each managing partner also has its own officers, who are also our
officers, and who act on behalf of the managing partners of the Coso
partnerships.
Caithness Acquisition, a limited liability company, is the manager and sole
member of each of the managing partners. Caithness Energy, as the manager and
sole owner of Caithness Acquisition, has delegated its role as manager of
Caithness Acquisition to the Caithness Acquisition board of directors,
including the power to manage the managing partners of the Coso partnerships.
Each managing partner's officers are also the officers of Caithness
Acquisition. None of the persons acting on behalf of the Coso partnerships
receives any compensation from the Coso partnerships for his or her services,
except that nominal compensation is paid in consideration for Mr. Ferrucci's
services.
Caithness Energy is governed by a board of directors and not by its members.
Our directors, other than Mr. Ferrucci, also currently serve as members of the
board of directors of Caithness Energy. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members to the Board of Directors of Caithness Energy who hold, in
the aggregate, a majority of the votes of all members of such board of
directors. Caithness Corporation's present appointees are Messrs. Bishop, Sr.,
Bishop, Jr. and Sullivan. In addition, Messrs. Gelber, Carpenter and McCallion
serve as voting members of the board of directors of Caithness Energy pursuant
to their individual executive compensation agreements with Caithness Energy.
These six individuals, together with Mr. Ferrucci, serve as the Caithness
Acquisition board of directors.
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<PAGE>
Management Committees
Under the amended and restated partnership agreement of each Coso
partnership, the managing partner of the Coso partnership is subject to the
directives of a management committee which oversees the business operations of
the Coso partnership. The managing partner of a Coso partnership may not take
certain specific actions without the consent of the management committee of
that Coso partnership. However, the management committee may not direct the
managing partner of the Coso partnership to take any action over which the
independent manager has exclusive authority without the requisite approval of
the independent manager. The management committee of each Coso partnership
consists of four delegates, two of which are appointed by the managing partner
and two of which are appointed by the non-managing partner. Each partner may
substitute or change its own delegates.
Caithness Energy indirectly wholly owns and controls the managing partners of
the BLM partnership and the Navy II partnership. Caithness Energy and its
affiliates also control CCH, the non-managing partner of the BLM partnership,
and Navy II Group, the non-managing partner of the Navy II partnership.
Accordingly, Caithness Energy and its affiliates control the appointment of all
four delegates to the management committees of the BLM partnership and the Navy
II partnership.
While Caithness Energy indirectly wholly owns and controls the managing
partner of the Navy I partnership, it does not currently wholly own and control
ESCA, the non-managing partner of the Navy I partnership. Caithness Energy and
its affiliates and ESI Geothermal currently own and control ESCA. Caithness
Acquisition recently entered into a Sale Agreement with ESI Geothermal to
purchase all of ESI Geothermal's indirect ownership interests in the Navy I
partnership. Following the closing of that purchase, Caithness Acquisition will
indirectly control ESCA and New CLOC and, therefore, the Navy I partnership.
You should read "Prospectus Summary--Recent Developments--Purchase of FPL
Interests, Assignment of FPL O&M Agreements" for more information regarding the
pending purchase of ESI Geothermal's ownership interests in the Navy I
partnership.
Caithness Energy and its affiliates currently have the right to control the
appointment of the two managing partner delegates to the management committee
of the Navy I partnership and, under ESCA's limited liability company
agreement, one of the two non-managing partner delegates. In addition, under
ESCA's limited liability company agreement, ESI Geothermal has the right to
control the appointment of the second non-managing partner delegate to the Navy
I partnership's management committee, and that delegate has the right to veto
any decisions made by the other non-managing partner delegate. Since decisions
of the Navy I partnership's management committee requires at least one vote
from each partner of the Navy I partnership, ESI Geothermal has the right to
veto any decisions made by that management committee. ESI Geothermal has agreed
in the Sale Agreement that, from and after the date of the Sale Agreement, it
will no longer exercise, with certain limited exceptions, its management rights
with respect to the Navy I partnership. See "Prospectus Summary--Recent
Developments--Purchase of FPL Interests; Assignment of FPL O&M Agreements."
Accordingly, Caithness Acquisition essentially controls the decisions made by
the management committees of the Coso partnerships.
Under the amended and restated partnership agreements of the Coso
partnerships, each partner may appoint one delegate with multiple votes. The
names of the delegates appointed by affiliates of Caithness Energy and ESI to
the management committees of the Coso partnerships are set forth below.
139
<PAGE>
Under the amended and restated partnership agreement of each Coso
partnership, the management committee must hold meetings on a quarterly basis
and on such other dates as may be called by any partner. A quorum of at least
three delegates must be present to convene a meeting and/or vote on a
management committee matter. Any action of the management committee must be
taken by a majority vote of the delegates comprising the quorum at the meeting,
but the vote must be composed of at least one affirmative vote by at least one
delegate of the managing partner and one delegate of the non-managing partner.
In lieu of meetings, actions may be taken without a meeting by written consent
or confirmed telephonic vote of at least three delegates.
The managing partner of a Coso partnership cannot make certain investment or
business decisions without the express consent of the management committee of
that Coso partnership. Those business decisions include, among others, those
regarding sale or lease of partnership assets, pledge of partnership assets,
execution or amendment of material contracts, engagement of outside
consultants, termination of the Coso partnerships and approval of budgets. In
addition, each Coso partnership's managing partner is required to prepare the
annual capital expenditure and annual operating budgets for that Coso
partnership and present it to the management committee for approval. If all or
part of the proposed budget is not approved by the management committee in a
timely fashion, the managing partner can retain an independent engineer to
review the proposed budget. If the independent engineer certifies that the
proposed budget is reasonably designed to permit the managing partner to
operate and maintain a project of the type owned by the Coso partnership and to
maximize revenues and net income, the proposed budget is deemed approved. If
the independent engineer does not so certify, the budget will be the same as in
the immediately preceding year, adjusted for inflation. Any controversies or
claims arising out of the amended and restated partnership agreements that
cannot be settled by agreement of the partners are to be settled by binding
arbitration.
As of August 31, 1999, the following persons were the members of the
management committee of each Coso partnership, as applicable. Each person has
two votes on each management committee on which he serves, except that
Christopher McCallion has only one vote on the management committee of the
Navy I partnership and Kenneth P. Hoffman has only one vote on the management
committee of the Navy I partnership:
<TABLE>
<CAPTION>
Name Age Partnership(s)
<S> <C> <C>
James D. Bishop, Jr. ... 39 Navy I partnership, BLM partnership, Navy II partnership
Christopher T.
McCallion.............. 37 Navy I partnership, BLM partnership, Navy II partnership
Kenneth P. Hoffman...... 47 Navy I partnership
</TABLE>
Certain information regarding Messrs. Bishop and McCallion is provided above
under "--Funding Corp."
Kenneth P. Hoffman was appointed to the management committee of the Navy I
partnership by ESI. Mr. Hoffman joined ESI Energy, Inc. in June 1989 and, since
1993, has been its Vice President of Business Management. Mr. Hoffman is
currently a Vice President of FPL Energy, Inc. Prior to joining ESI Energy,
Inc., Mr. Hoffman was employed by Florida Power & Light Company. Mr. Hoffman
holds a Master of Business Administration degree from Florida International
University and a Bachelor of Science degree from Rochester Institute of
Technology. At the closing of the purchase by Caithness Acquisition of ESI
Geothermal's indirect ownership interests in the Navy I partnership,
Mr. Hoffman will resign from the management committee and Mr. McCallion will
assume Mr. Hoffman's position on the Navy I partnership management committee.
See "Prospectus Summary--Recent Developments--Purchase of FPL Interests;
Assignment of FPL O&M Agreements."
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<PAGE>
Management Committee Fees
The members of the management committees are not entitled to any direct
compensation from us or the Coso partnerships. However, each Coso partnership
previously paid to its two general partners annual management committee fees
for their participation on the management committee of that Coso partnership.
The following table sets forth, for the years ended December 31, 1996, 1997 and
1998, and for the six months ended June 30, 1998 and June 30, 1999, the total
amount of management committee fees paid or payable by each of the Coso
partnerships to its partners:
<TABLE>
<CAPTION>
Six Months Ended
June 30, 1999
-------------------------------
Six Four
Months Two Months Months
Year Ended December 31, Ended Ended Ended
-------------------------- June 30, February 28, June 30,
1996 1997 1998 1998 1999 1999 Total
<S> <C> <C> <C> <C> <C> <C> <C>
Navy I Partnership
New CLOC.............. $ -- $ -- $ -- $ -- $ -- $ 37,000 $ 37,000
Predecessor of New
CLOC................. 143,000 143,000 147,000 74,000 25,000 -- 25,000
ESCA.................. 214,000 214,000 221,000 110,000 37,000 74,000 111,000
-------- -------- -------- -------- ------- -------- --------
$357,000 $357,000 $368,000 $184,000 $62,000 $111,000 $173,000
BLM Partnership
New CHIP.............. $ -- $ -- $ -- $ -- $ -- $ 38,000 $ 38,000
Predecessor of New
CHIP................. 145,000 145,000 148,000 74,000 25,000 -- 25,000
CCH................... 222,000 218,000 223,000 111,000 37,000 74,000 111,000
-------- -------- -------- -------- ------- -------- --------
$367,000 $363,000 $371,000 $185,000 $62,000 $112,000 $174,000
Navy II Partnership.....
New CTC............... $ -- $ -- $ -- $ -- $ -- $ 38,000 $ 38,000
Predecessor of New
CTC.................. 145,000 145,000 148,000 74,000 25,000 -- 25,000
Navy II Group......... 218,000 218,000 223,000 111,000 37,000 74,000 111,000
-------- -------- -------- -------- ------- -------- --------
$363,000 $363,000 $371,000 $185,000 $62,000 $112,000 $174,000
</TABLE>
The Coso partnerships no longer pay management committee fees to their
managing partners. See "Certain Relationships and Related Transactions--
Management Committee Fees."
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<PAGE>
OWNERSHIP
Funding Corp.
As of September 1, 1999, our authorized capital stock consisted of 1,000
shares of common stock, par value $0.01 per share, of which 300 shares were
outstanding. Our outstanding common stock is owned equally by the Coso
partnerships.
Coso Partnerships
Our directors and executive officers also act in similar capacities on behalf
of the managing partner of each Coso partnership and, except for Mr. Ferrucci,
on behalf of Caithness Acquisition and Caithness Energy. Several of these
directors and executive officers beneficially own securities of Caithness
Corporation. Caithness Corporation and its affiliates beneficially own all of
the member interests of Caithness Energy.
Caithness Energy is governed by a board of directors and not by its members.
Our directors, except for Mr. Ferrucci, also currently serve as the members of
the board of directors of Caithness Energy. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members who hold, in the aggregate, a majority of the votes of all
members of such board of directors. Caithness Corporation's current appointees
are Messrs. Bishop, Sr., Bishop, Jr. and Sullivan. In addition, Messrs. Gelber,
Carpenter and McCallion serve as voting members of the board of directors of
Caithness Energy pursuant to their individual executive compensation
agreements.
The following table sets forth, as of September 1, 1999, certain information
regarding the beneficial ownership of our voting securities and the beneficial
ownership of the voting securities of each of the Coso partnerships by:
(1) each person who is known by us and the Coso partnerships to
beneficially own 5% or more of our voting securities or 5% or more of
the voting securities of any Coso partnership,
(2) each of our directors and executive officers who also act in similar
capacities on behalf of the managing partner of each Coso partnership
and each of the delegates to the management committee of each Coso
partnership, and
(3) all of our directors and executive officers who also act in similar
capacities for the managing partnership of each Coso partnership and
all of the delegates to the management committee of each Coso
partnership as a group.
Beneficial ownership has been determined in accordance with Rule 13d-3 under
the Securities Exchange Act of 1934, as amended. Except as otherwise noted,
each person named below has an address in care of our principal executive
offices.
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<PAGE>
Beneficial Ownership of Funding Corp. and the Coso Partnerships
<TABLE>
<CAPTION>
Percent Indirect Percent Indirect
Percent Indirect Beneficial Percent Indirect Beneficial
Name and Address Beneficial Ownership in the Beneficial Ownership in the
of Beneficial Ownership in Navy I Ownership in the Navy II
Owner Funding Corp. Partnership BLM Partnership Partnership
<S> <C> <C> <C> <C>
James D. Bishop,
Sr.(1)(2)............. 1.1% 1.8% -- 1.5%
Leslie J.
Gelber(1)(3).......... -- -- -- --
James D. Bishop,
Jr.(1)(4)............. 31.4% 28.9% 35.0% 30.4%
Christopher T.
McCallion(1)(3)....... -- -- -- --
Larry K.
Carpenter(1)(3)....... -- -- -- --
James C.
Sullivan(1)(5)........ 2.8% 2.6% 2.9% 2.8%
Mark A. Ferrucci....... -- -- -- --
David Casale(1)(3)..... -- -- -- --
Robert E.
Tucker(1)(3).......... -- -- -- --
Barbara Bishop
Gollan(1)(3)(6)....... -- -- -- --
Kenneth P. Hoffman..... -- -- -- --
c/o FPL Energy, Inc.
700 Universe Blvd.
Juno Beach, FL 33408
Dominion Energy,
Inc.(7)............... * -- 5.2% 6.3%
901 East Byrd Street
Richmond, VA 23219
ESI Geothermal,
Inc.(8)............... * 5.0% -- --
c/o FPL Energy, Inc.
700 Universe Blvd.
Juno Beach, FL 33408
Mojave Energy
Company(9)............ 6.2% 5.5% 7.6% 5.3%
c/o Davenport
Resources, Inc.
575 Lexington Avenue
New York, NY 10022
All directors,
executive officers and
management committee
delegates as a group.. 35.3% 33.3% 37.9% 34.6%
</TABLE>
- ---------------------
* Less than 5.0%.
(1) The address of such person is c/o Caithness Coso Funding Corp., 1114 Avenue
of the Americas, 41st Floor, New York, New York 10036-7790.
(2) The beneficial ownership of James D. Bishop, Sr.'s interests is based upon
his ownership of shares of common stock of Mojave Power, Inc. and Mojave
Power II, Inc. which own, indirectly through various entities, general
partnership interests in the Navy I partnership and the Navy II
partnership. In addition to these interests, James D. Bishop, Sr. is the
beneficiary of The James D. Bishop Trust--1998 ("Bishop, Sr. Trust"), which
owns shares of common stock of Caithness Corporation. Caithness Corporation
owns, indirectly through various entities, general partnership interests in
the Navy I partnership, the BLM partnership and the Navy II partnership,
which collectively own all of the shares of common stock of Funding Corp.
The voting rights to the shares of common stock of Caithness Corporation
held by the Bishop, Sr. Trust have been transferred to The Caithness
Entities Voting Trust, the trustee of which is James D. Bishop, Jr. The
Bishop, Sr. Trust is irrevocable. James D. Bishop, Sr., therefore, does not
have voting or investment power over these shares of common stock of
Caithness Corporation.
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<PAGE>
(3) Owner of economic interests in the Coso partnerships through Caithness
Corporation's employee incentive plans, which economic interests are not
listed on this table. See "Certain Relationships and Related Transactions--
Interests of Management in Coso Projects."
(4) James D. Bishop, Jr. is: (i) the beneficiary of The James D. Bishop, Jr.
Irrevocable Trust--1996 (the "Bishop, Jr. Trust"), which owns shares of
common stock of Caithness Corporation, the voting rights of which have been
transferred to The Caithness Entities Voting Trust, the trustee of which is
James D. Bishop, Jr.; (ii) the owner of common stock of Caithness
Corporation and of Mojave Power, Inc.; and (iii) the trustee of The
Caithness Entities Voting Trust which possesses sole voting control over
the shares of common stock of Caithness Corporation held by the Bishop, Sr.
Trust, The Barbara Bishop Gollan Irrevocable Trust--1996 (the "Gollan
Trust"), The Elizabeth Bishop DeLuca Irrevocable Trust--1996 and The Linda
Bishop Fotiu Irrevocable Trust--1996. The interests listed in (i) and (ii)
above entitle James D. Bishop, Jr. to the following indirect beneficial
ownership interests: Funding Corp. (1.8%); Navy I partnership (1.4%); BLM
partnership (1.7%); and Navy II partnership (2.4%). James D. Bishop, Jr.
disclaims beneficial ownership of the interests listed in (iii) above.
(5) The beneficial ownership of James C. Sullivan's interests is based upon his
ownership of shares of common stock of Caithness Corporation which owns,
indirectly through various entities, general partnership interests in the
Navy I partnership, the BLM partnership and the Navy II partnership, and
his ownership of shares of common stock of Mojave Power, Inc. and Mojave
Power II, Inc. which own, indirectly through various entities, general
partnership interests in the Navy I partnership and the Navy II
partnership.
(6) Barbara Bishop Gollan is the beneficiary of the Gollan Trust, which owns
shares of common stock of Caithness Corporation. The voting rights to the
shares of common stock of Caithness Corporation held by the Gollan Trust
have been transferred to The Caithness Entities Voting Trust, the trustee
of which is James D. Bishop, Jr. The Gollan Trust is irrevocable. Barbara
Bishop Gollan, therefore, does not have voting or investment power over
these shares of common stock of Caithness Corporation.
(7) Dominion Energy, Inc. owns: (i) a limited liability company membership
interest in Caithness BLM Group, LP, a Delaware limited partnership, which
owns a limited liability company membership interest in CCH, which owns a
general partnership interest in the BLM partnership; and (ii) a limited
liability company membership interest in Navy II Group which owns a general
partnership interest in the Navy II partnership and a limited liability
company membership interest in CCH, which owns a general partnership
interest in the BLM partnership.
(8) ESI Geothermal owns a limited liability company membership interest in
ESCA, which owns a general partnership interest in the Navy I partnership.
Caithness Acquisition recently entered into a Sale Agreement with ESI
Geothermal to purchase ESI Geothermal's limited liability company
membership interest in ESCA and, therefore, its indirect ownership interest
in the Navy I partnership. See "Prospectus Summary--Recent Developments--
Purchase of FPL Interests; Assignment of FPL O&M Agreements."
(9) Mojave Energy Company owns limited liability company membership interests
in Caithness Power, LLC, which owns, indirectly through various entities,
general partnership interests in each of the Coso partnerships.
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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Purchase of ESI Geothermal Interests
On October 6, 1999, Caithness Acquisition and ESI Geothermal signed the Sale
Agreement under which Caithness Acquisition agreed to purchase all of the
indirect ownership interests held by ESI Geothermal in the Navy I partnership
in exchange for a cash payment of $5.0 million. ESI Geothermal beneficially
owns a 5.0% indirect ownership interest in the Navy I partnership. Under the
Sale Agreement, the closing of the purchase is currently required to occur
under the Sale Agreement on or prior to November 1, 1999. ESI Geothermal also
agreed in the Sale Agreement that, from and after the date of the Sale
Agreement, it will no longer exercise, with certain limited exceptions, its
management rights with respect to the Navy I partnership. Following the
closing, ESI Geothermal will no longer have any ownership or other interest in,
and Caithness Acquisition will indirectly control, the Navy I partnership. You
should read "Prospectus Summary-- Recent Developments--Purchase of FPL
Interests; Assignment of FPL O&M Agreements" and "--O&M Fees; Reduction in
Fees; Assumption of FPL Operating O&M Agreements" for more information about
this pending purchase and certain related transactions.
O&M Fees; Reduction in Fees; Assumption of FPL Operating O&M Agreements
O&M Fees
Prior to February 25, 1999, the date that Caithness Acquisition purchased of
all of CalEnergy's interests in the Coso projects, CalEnergy and its affiliates
acted as the plant and field operator at the Coso projects. They also
maintained the Navy I Transmission Line and the BLM/Navy II Transmission Line.
Under the amended partnership agreements of the Coso partnerships, CalEnergy
was entitled to receive reimbursement of direct operating costs, reimbursement
of approved allocable general and administrative costs and payment of operator
fees in consideration for its services as the operator at the Coso projects.
The Coso partnerships paid CalEnergy the aggregate amounts of approximately
$7.5 million in each of 1998, 1997 and 1996 for such costs and fees. For the
first two months of the six month period ended June 30, 1999, the Coso
partnerships paid CalEnergy the aggregate amount of approximately $1.3 million
for such costs and fees.
In connection with Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects, each Coso partnership retained FPL Operating
and Coso Operating Company to operate its Coso project under separate O&M
agreements with each. FPL Operating is an affiliate of ESI Geothermal, which is
a member of ESCA. Coso Operating Company is a wholly owned subsidiary of
Caithness Acquisition. For additional information regarding the operations and
maintenance services being performed by FPL Operating and Coso Operating
Company at the Coso projects, see "Business--O&M Agreements."
Under its O&M agreements with the Coso partnerships, FPL Operating operates
and maintains all three plants, the transmission lines and the geothermal
fields at the Coso projects. As compensation for such services, each Coso
partnership has agreed to pay FPL Operating an annual O&M fee of $134,000,
$100,000 and $84,000 in the first, second and third years, respectively, of the
term of its O&M agreements (or an aggregate of $402,000, $300,000 and $252,000,
respectively). In addition, each Coso partnership has agreed to pay to FPL
Operating all properly incurred costs and expenses and reimburse FPL Operating
for the performance incentive bonuses that it pays its employees, as set forth
in the O&M agreements. For the last four months of the six month period ended
June 30, 1999, the Coso partnerships accrued to FPL Operating aggregate O&M
fees of approximately $133,000. All fees payable to FPL Operating are
subordinated to all payments to be made under the senior secured notes.
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<PAGE>
Under its O&M agreements with the Coso partnerships, Coso Operating Company,
among other things, manages the geothermal resource, including well drilling,
at the Coso projects. As compensation for such services, each Coso partnership
has agreed to pay Coso Operating Company an annual O&M fee of $532,000,
$400,000 and $334,000 in the first, second and third years, respectively, of
the term of its O&M agreements (or an aggregate of $1.6 million, $1.2 million
and $1.0 million, respectively). In addition, each Coso partnership has agreed
to pay all properly incurred costs and expenses and reimburse Coso Operating
Company for the performance incentive bonuses that Coso Operating Company pays
to its employees, as set forth in the O&M agreements. For the last four months
of the six month period ended June 30, 1999, the Coso partnerships accrued to
Coso Operating Company aggregate O&M fees of approximately $533,000. All fees
payable to Coso Operating Company are subordinated to all payments to be made
under the senior secured notes.
At the closing of Caithness Acquisition's purchase of all of ESI Geothermal's
indirect ownership interests in the Navy I partnership described under "--
Purchase of ESI Geothermal Interests" above, FPL Operating is expected to
assign to Coso Operating Company all of its rights, duties and obligations
under FPL Operating's O&M agreements. No other changes to FPL Operating's
O&M agreements are expected to be made. At the closing, Coso Operating Company
is expected to advance to FPL Operating all of the O&M fees and reimbursable
expenses that have accrued and have not been paid to FPL Operating under the
O&M agreements. Following the closing, Coso Operating Company will be entitled
to receive the O&M fees and reimbursable expenses accruing under FPL
Operating's O&M agreements (payment of which will continue to be subordinated
to all payments to be made under the senior secured notes). See "Prospectus
Summary--Recent Developments--Purchase of FPL Interests; Assignment of FPL O&M
Agreements."
Reduction in Fees
As a result of Caithness Acquisition's purchase of all of CalEnergy's
interests in the Coso projects and the accompanying change in plant and field
operators, annual operator fees and costs to be paid by the Coso partnerships
to FPL Operating and Coso Operating Company have been reduced significantly
from those previously paid to CalEnergy, the Coso projects' prior operator,
and, since the closing date of the Series A notes offering, management
committee fees previously payable to the managing partners of the Coso
partnerships have been eliminated. In connection with this reduction in
operator fees and the elimination of management committee fees payable to the
managing partners, ESCA, CCH and Navy II Group, the non-managing partners of
the Navy I partnership, the BLM partnership and the Navy II partnership,
respectively, consented to an additional payment in the aggregate amount of
$26.8 million to the managing partners of the Coso partnerships. For more
information regarding the elimination of the managing partner management
committee fees, see "--Management Committee Fees." This additional payment was
made simultaneously with the closing of the Series A notes offering equally by
each of the Coso partnerships. The aggregate amount of this payment represents
the present value of the share of the reduction in future operator fees and the
elimination of management committee fees payable to the managing partners of
the Coso partnerships that the non-managing partners of each Coso partnership
would have otherwise had to incur under their previous partnership and O&M
agreements. The managing partners of the Coso partnerships caused this
additional payment to be applied to repay the short-term debt their parent,
Caithness Acquisition, incurred in connection with its purchase of all of
CalEnergy's interests in the Coso projects. See "--Purchase of CalEnergy's
Interests."
Management Committee Fees
Each Coso partnership used to pay management committee fees to each of its
general partners in consideration for its participation on the management
committee of that Coso partnership. See
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"Management--Management Committee Fees." Each of the general partners then
distributed these management committee fees to its own managing partner, which,
in turn, distributed them, directly or indirectly, to Caithness Energy or
CalEnergy, as the case may be.
The following table sets forth, for the years ended December 31, 1996, 1997
and 1998, and for the six months ended June 30, 1998 and June 30, 1999, the
total amount of management committee fees distributed or distributable to
Caithness Energy and CalEnergy, respectively, for those periods:
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
------------------------------
Six Two Four
Months Months Months
Year Ended December 31, Ended Ended Ended
-------------------------- June 30, February 28, June 30,
1996 1997 1998 1998 1999 1999 Total
<S> <C> <C> <C> <C> <C> <C> <C>
Navy I Partnership
Caithness Energy....... $214,000 $214,000 $221,000 $110,000 $37,000 $111,000 $148,000
CalEnergy.............. 143,000 143,000 147,000 74,000 25,000 -- 25,000
-------- -------- -------- -------- ------- -------- --------
$357,000 $357,000 $368,000 $184,000 $62,000 $111,000 $173,000
BLM Partnership
Caithness Energy....... $222,000 $218,000 $223,000 $111,000 $37,000 $112,000 $149,000
CalEnergy.............. 145,000 145,000 148,000 74,000 25,000 -- 25,000
-------- -------- -------- -------- ------- -------- --------
$367,000 $363,000 $371,000 $185,000 $62,000 $112,000 $174,000
Navy II Partnership
Caithness Energy....... $218,000 $218,000 $223,000 $111,000 $37,000 $112,000 $149,000
CalEnergy.............. 145,000 145,000 148,000 74,000 25,000 -- 25,000
-------- -------- -------- -------- ------- -------- --------
$363,000 $363,000 $371,000 $185,000 $62,000 $112,000 $174,000
</TABLE>
Affiliates of Caithness Energy have eliminated the payment of management
committee fees by the Coso partnerships to the Coso partnerships' managing
partners. After the closing of the Series A notes offering, the Coso
partnerships will pay management committee fees to their non-managing partners
in the aggregate annual amount of $667,000. See "Business--The Coso
Partnerships." This aggregate amount will be adjusted annually for inflation
based on the Consumer Price Index. For a discussion of certain matters relating
to the elimination of management committee fees payable to the managing partner
of each Coso partnership, see "--O&M Fees; Reduction in Fees."
Purchase of CalEnergy Interests
On February 25, 1999, Caithness Acquisition purchased all of CalEnergy's
interests in the Coso projects. The purchase price consisted of $205.0 million
in cash, plus $5.0 million in contingent payments, plus the assumption of
CalEnergy's and its affiliates' share of debt outstanding at the Coso projects
which then totaled approximately $67.0 million. In order to complete the
purchase, Caithness Acquisition borrowed on a short-term basis the aggregate
principal amount of $211.5 million from an affiliate of the initial purchaser
of the Series A notes. The initial purchaser's affiliate received customary
fees and reimbursement of its expenses in connection with its activities as the
arranger and lender of such short-term debt. Caithness Acquisition used a
portion of the proceeds from the Series A notes offering that it received from
the Coso partnerships, together funds from other sources, to repay all amounts
owing under this short-term debt facility.
As part of the purchase of CalEnergy's interests in the Coso projects,
Caithness Energy will be required to pay the contingent payment upon the
settlement, final judgment or other dismissal of the litigation with Edison. In
addition, the Coso partnerships and certain other affiliates of Caithness
Energy entered into a future revenue agreement with CalEnergy. This agreement
provides that the Coso partnerships and such affiliates will pay to CalEnergy
one-seventh of the gross revenues from the Coso projects or any expansions
thereof derived from certain energy-related arrangements with
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<PAGE>
the U.S. Government. For more information regarding these additional
agreements, see "Business--Purchase of CalEnergy's Interests."
Payments to Transmission Line Partners
Coso Transmission Line Partners, the owner of the BLM/Navy II Transmission
Line, charges the BLM partnership and the Navy II partnership for their use of
the BLM/Navy II Transmission Line. The charges are designed to ensure that Coso
Transmission Line Partners recovers its operating costs. Also, the BLM
partnership and the Navy II partnership pay for the purchase of items used by
Coso Transmission Line Partners for the BLM/Navy II Transmission Line. See
"Business--Overview of the Coso Projects--Transmission Lines." The following
table sets forth, for the six months ended June 30, 1998 and June 30, 1999, and
for the years ended December 31, 1996, 1997 and 1998, the total amount that
Coso Transmission Line Partners charged the BLM partnership and the Navy II
partnership for net operating costs (net of advances from the BLM partnership
or the Navy II partnership, as the case may be):
<TABLE>
<CAPTION>
Year Ended December 31, Six Months Ended June 30, 1999
-------------------------- --------------------------------
Two Months Four Months
Six Months Ended Ended
Ended June February 28, June 30,
1996 1997 1998 30, 1998 1999 1999 Total
<S> <C> <C> <C> <C> <C> <C> <C>
BLM Partnership......... $114,000 $112,000 $115,000 $86,000 $28,000 $58,000 $43,000
Navy II Partnership..... 126,000 127,000 127,000 97,000 $33,000 64,000 50,000
</TABLE>
Distributions to Partners
The Coso partnerships make cash distributions from operating cash flow to its
partners from time to time as determined by their respective management
committees. The Navy I partnership, the BLM partnership and the Navy II
partnership made aggregate cash distributions to Caithness Energy and its
affiliates of approximately $11.9 million, $9.0 million and $21.1 million,
respectively, in the year ended December 31, 1998, approximately $39.9 million,
$21.2 million and $33.7 million, respectively, in the year ended December 31,
1997, and approximately $39.2 million, $30.2 million and $41.1 million,
respectively, in the year ended December 31, 1996. Simultaneously with the
closing of the Series A notes offering, the Coso partnerships made additional
cash distributions to the owners of the Coso partnerships other than Caithness
Energy of approximately $72.3 million. No other cash distributions were made by
the Coso partnerships during six month period ended June 30, 1999.
Prior to Caithness Acquisition's purchase of all of CalEnergy's interests in
the Coso projects, the Navy I partnership, the BLM partnership and the Navy II
partnership made aggregate cash distributions to CalEnergy and its affiliates
of approximately $10.3 million, $8.3 million and $21.1 million, respectively,
in the year ended December 31, 1998, approximately $34.5 million, $19.6 million
and $33.7 million, respectively, in the year ended December 31, 1997, and
approximately $34.0 million, $27.9 million and $41.1 million, respectively, in
the year ended December 31, 1996. As a result of Caithness Acquisition's
purchase of all of CalEnergy's interests in the Coso projects, the Coso
partnerships no longer make any distributions to CalEnergy other than as
provided in the agreements it entered into in connection with that purchase.
See "--Purchase of CalEnergy's Interests."
Interests of Management in Coso Projects
Leslie J. Gelber, a director and President and Chief Operating Officer of
Funding Corp., Christopher T. McCallion, a director and Executive Vice
President and Chief Financial Officer of
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Funding Corp., Larry K. Carpenter, a director and Executive Vice President of
Funding Corp., and certain other executive officers of Funding Corp. have
economic interests in the Coso partnerships. These individuals are participants
in incentive compensation plans maintained by Caithness Corporation, of which
Caithness Energy is the principal operating subsidiary. Under these incentive
compensation plans, these individuals have been granted "units" in Caithness
Energy. Under Caithness Energy's limited liability company agreement, unit
holders are entitled to receive distributions of profits, losses and net cash
flow made by Caithness Energy to its unit holders which are derived by
Caithness Energy from certain of its independent power projects, including the
Coso projects. In particular, these individuals will receive in the aggregate
approximately 23.0% of the distributions of profits, losses and net cash flow
made by Caithness Energy and derived from the Coso partnerships.
Although unit holders of Caithness Energy have rights to economic
distributions only, Messrs. Gelber, Carpenter and McCallion also serve as
members of the board of directors of Caithness Energy pursuant to their
respective executive compensation arrangements. Caithness Energy is governed by
its board of directors, not by its members. Under the limited liability company
agreement of Caithness Energy, Caithness Corporation is entitled to appoint a
number of members to the Board of Directors of Caithness Energy who hold, in
the aggregate, a majority of the votes of all members of such board of
directors. Caithness Corporation's present appointees are Messrs. Bishop, Sr.,
Bishop, Jr. and Sullivan. The rights to distributions held by these individuals
are subject to restrictions on transfer as well as call rights in favor of
Caithness Corporation upon termination of such individual's employment.
Royalty to Coso Land Company
Coso Land Company is a general partnership of which Caithness Acquisition and
one of our other affiliates are the general partners. In 1988, the BLM lease
was assigned to the BLM partnership. In connection with this assignment, the
BLM partnership agreed to pay to Coso Land Company a royalty equal to 5.0% of
the value of the steam produced by BLM on the real property covered by the BLM
lease and certain other lands. The royalty is subordinated to the payment of
all of the BLM partnership's other royalties, all debt service of the BLM
partnership and all operating costs of BLM. As of June 30, 1999, the total
accrued balance of the royalty payable to Coso Land Company was approximately
$21.3 million.
The following table sets forth, for the six month periods ended June 30, 1998
and June 30, 1999, and for the years ended December 31, 1996, 1997 and 1998,
the amount of the royalty payable to Coso Land Company that accrued during such
periods:
<TABLE>
<CAPTION>
Six Months Ended June 30, 1999
---------------------------------------
Six Four
Months Two Months Months
Year Ended December 31, Ended Ended Ended
- ------------------------------ June 30, February 28, June 30,
1996 1997 1998 1998 1999 1999 Total
(In thousands)
<S> <C> <C> <C> <C> <C> <C>
$2,400 $3,200 $3,100 $1,444 $438 $170 $608
</TABLE>
No portion of the royalty that has accrued to date has been paid. Payment of
this royalty will be permitted only to the extent that restricted payments may
be made from funds or deposits in the Distribution Account established under
the Depositary Agreement, and is subordinated to all payments under the senior
secured notes. See "Description of Series B Notes--Distribution Account."
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<PAGE>
DESCRIPTION OF SERIES B NOTES
We issued the Series A notes under an Indenture (the "Indenture") among U.S.
Bank Trust National Association, as trustee, the Coso partnerships and us in a
private transaction that was not subject to the registration requirements of
the Securities Act. You can find the definitions of the terms used in this
description under the heading "Certain Definitions." The terms of the Indenture
apply to the Series A notes and the Series B notes to be issued in exchange for
the Series A notes pursuant to the exchange offer. Upon the issuance of the
Series B notes or the effectiveness of the shelf registration statement, the
Indenture will be subject to the Trust Indenture Act of 1939 (the "Trust
Indenture Act").
The following is a summary of the material provisions of the Indenture, the
registration rights agreement, the Depositary Agreement, the security
agreements and the pledge agreements. It does not restate those agreements in
their entirety. We urge you to read all of these agreements because they, and
not this description, define your rights as holders of the Series B notes.
Copies of the proposed form of Indenture and the other financing documents are
available as set forth below under "--Additional Information." Certain defined
terms used in this description but not defined below under "--Certain
Definitions" have the meanings assigned to them in the Indenture. Except as
otherwise indicated below, the following summary applies to both the Series A
notes and the Series B notes.
Brief Description of the Senior Secured Notes and Guarantees
The senior secured notes:
. are our general obligations;
. are secured by:
(1) a perfected, first priority pledge of the promissory notes (the
"Partnership Notes") evidencing each Coso partnership's obligations
to repay the loan by us to each Coso Partnership;
(2) a perfected, first priority lien on the funds in the Accounts under
the Depositary Agreement; and
(3) a perfected, first priority pledge of all of our outstanding
Capital Stock;
. are pari passu in right of payment to all of our senior borrowings;
. are senior in right of payment to any of our future subordinated
Indebtedness; and
. are unconditionally guaranteed by the Coso partnerships. The Guarantees,
in turn, are secured by:
(1) a perfected, first priority lien on substantially all assets of the
Coso partnerships; and
(2) a perfected, first priority pledge of the Equity Interests in the
Coso partnerships.
The senior secured notes are payable solely from payments to be made by the
Coso partnerships under the Partnership Notes and from other funds that may be
available from time to time in the Accounts held by the Depositary. The Coso
partnerships' obligations to make payments under the Partnership Notes are non-
recourse to the direct and indirect owners of the Coso partnerships (including
Caithness Energy, L.L.C.) except, in the case of the direct owners of the Coso
partnerships, with respect solely to recourse to those owners' general
partnership interests in the
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Coso partnerships pledged to the Collateral Agent as security for the
Guarantees. None of ESCA LLC, a Delaware limited liability company, and New
CLOC Company, LLC, a Delaware limited liability company, the general partners
of the Navy I Partnership (collectively, the "Navy I Partners"), Caithness Coso
Holdings, LLC, a Delaware limited liability company, and New CHIP Company, LLC,
a Delaware limited liability company, the general partners of the BLM
Partnership (collectively the "BLM Partners") or Caithness Navy II Group, LLC,
a Delaware limited liability company, and New CTC Company, LLC, a Delaware
limited liability company, the general partners of the Navy II Partnership
(collectively the "Navy II Partners" and, together with the Navy I Partners and
the BLM Partners, the "Partners"), nor any of the direct or indirect owners of
the Partners or of the Issuer, will be obligated to contribute additional funds
if monies in the Accounts are insufficient for the payment of debt service in
respect of the senior secured notes. So long as the senior secured notes are
outstanding, distributions to the Partners from the Distribution Account will
constitute Restricted Payments under and as defined in the Indenture.
Principal, Maturity and Interest
The Indenture provides for the issuance by us of up to $450.0 million of
senior secured notes, of which $110.0 million of Series A notes due 2001 and
$303.0 million of Series A notes due 2009 were issued at the closing of the
Series A notes offering. We will issue all Series B notes in denominations of
$100,000 and integral multiples of $1,000 in excess thereof. The Series B notes
due 2001 will mature on December 15, 2001, and the Series B notes due 2009 will
mature on December 15, 2009.
Interest on the Series B notes due 2001 will accrue at the rate of 6.80% per
annum and will be payable semi-annually in arrears on December 15 and June 15,
commencing December 15, 1999. We will make each interest payment to the Holders
of record of the Series B notes due 2001 on the immediately preceding December
1 and June 1, as the case may be. Interest on the Series B notes due 2009 will
accrue at the rate of 9.05% per annum and will be payable semi-annually in
arrears on December 15 and June 15, commencing December 15, 1999. We will make
each interest payment to the Holders of record of the Series B notes due 2009
on the immediately preceding December 1 and June 1, as the case may be.
Interest on the Series B notes will accrue from the date of original issuance
of the Series A notes which have been exchanged for such Series B notes or, if
interest has already been paid, from the date it was most recently paid.
Interest will be computed on the basis of a 360-day year comprised of twelve
30-day months.
We will pay the principal of the Series B notes due 2001 in semi-annual
installments, commencing December 15, 1999, as follows:
<TABLE>
<CAPTION>
Scheduled Payment Percentage of Principal
Date Amount Payable
----------------- -----------------------
<S> <C>
December 15, 1999 47.8773%
June 15, 2000 11.0736%
December 15, 2000 16.4427%
June 15, 2001 10.1900%
December 15, 2001 14.4164%
</TABLE>
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We will pay the principal of the Series B notes due 2009 in semi-annual
installments, commencing June 15, 2002, as follows:
<TABLE>
<CAPTION>
Scheduled Payment Percentage of Principal
Date Amount Payable
----------------- -----------------------
<S> <C>
June 15, 2002 2.8743%
December 15, 2002 4.3109%
June 15, 2003 3.6564%
December 15, 2003 5.4584%
June 15, 2004 4.1363%
December 15, 2004 6.2043%
June 15, 2005 4.6838%
December 15, 2005 7.0257%
June 15, 2006 5.0541%
December 15, 2006 7.5815%
June 15, 2007 6.2601%
December 15, 2007 9.3898%
June 15, 2008 6.4927%
December 15, 2008 9.7650%
June 15, 2009 6.8231%
December 15, 2009 10.2835%
</TABLE>
Methods of Receiving Payments on the Series B Notes
If a Holder has given wire transfer instructions to us, we will pay all
principal, interest, premium, if any, and Liquidated Damages, if any, on that
Holder's Series B notes in accordance with those instructions. Otherwise, we
will make all payments of principal, interest, if any, and Liquidated Damages,
if any, on the Series B notes at the office or agency of the Paying Agent and
Registrar within the City and State of New York unless we elect to make
interest payments by check mailed to the Holders at their respective addresses
set forth in the register of Holders.
Paying Agent and Registrar for the Series B Notes
The Trustee will initially act as Paying Agent and Registrar. We may change
the Paying Agent or Registrar without prior notice to the Holders, and we or
any of our Subsidiaries may act as Paying Agent or Registrar.
Transfer and Exchange
A Holder may transfer or exchange Series B notes in accordance with the
Indenture. The Registrar and the Trustee may require a Holder, among other
things, to furnish appropriate endorsements and transfer documents, and we may
require a Holder to pay any taxes and fees required by law or permitted by the
Indenture. We are not required to transfer or exchange any Series B note
selected for redemption. Also, we are not required to transfer or exchange any
Series B note for a period of 15 days before a selection of Series B notes to
be redeemed.
We and the Trustee will treat the registered Holder of a Series B note as the
owner of the Series B note for all purposes.
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Guarantees
The Coso partnerships have fully and unconditionally, jointly and severally
guaranteed our obligations under the Indenture and the senior secured notes.
The obligation of each Coso partnership under its Guarantee is limited so as
not to constitute a fraudulent conveyance under applicable law. See "Risk
Factors--Federal and state statute allow courts, under specific circumstances,
to void guarantees and require noteholders to return payments received from
guarantors."
Under the Guarantees, the Coso partnerships each have agreed for the benefit
of the Trustee and the Collateral Agent to be bound by and to perform all of
their obligations under covenants contained in the Credit Agreements. The
failure of the Coso partnerships to perform those covenants will result in a
Guarantee Event of Default, after the expiration of any applicable grace
period.
Security
The senior secured notes are secured by:
(1) a perfected, first priority pledge of the Partnership Notes evidencing
each Coso partnership's obligation to repay the loan made to it by us;
(2) a perfected, first priority lien on the funds in the Accounts under the
Depositary Agreement; and
(3) a perfected, first priority pledge of all of our outstanding Capital
Stock.
We have entered into a pledge agreement (the "Note Pledge Agreement")
providing for the pledge by us to U.S. Bank Trust National Association, as
collateral agent (in such capacity, the "Collateral Agent") for the benefit of
the Trustee and the Holders of the senior secured notes, of the Partnership
Notes held by us. We have also entered into the Depositary Agreement. The
Depositary Agreement grants to U.S. Bank Trust National Association, as
depositary (in such capacity, the "Depositary") for the benefit of the Trustee
and the Holders of the senior secured notes, a perfected, first priority lien
on the funds in the Accounts. Each Coso partnership, in its capacity as one of
our owners, has entered into a pledge agreement (each, a "Partnership Pledge
Agreement" and, together with the Note Pledge Agreement, the "Issuer Pledge
Agreements"). These pledge agreements provide for the perfected, first priority
pledge by each Coso partnership to the Collateral Agent, for the benefit of the
Trustee and the Holders of the senior secured notes, of all of our Capital
Stock. In addition, each affiliate of the Coso partnerships or us that holds
material assets related to the Projects has provided a lien on such assets to
secure the senior secured notes.
The Guarantees are secured by:
(1) a perfected first priority lien on substantially all of the assets of
the Coso partnerships; and
(2) a perfected, first priority pledge of all of the Equity Interests in
the Coso partnerships.
Each of the Coso partnerships has entered into a Deed of Trust and a Security
Agreement which provides for a perfected, first priority lien on the assets of
the Coso partnerships. The Partners have entered into one or more pledge
agreements (each, a "Partner Pledge Agreement" and, together with the Issuer
Pledge Agreements, the "Pledge Agreements") which provides for the perfected,
first priority pledge to the Collateral Agent for the benefit of the Trustee
and the Holders of the Series B notes of all of the respective general partner
interests of each of (i) the Navy I Partners in the Navy I Partnership, (ii)
the BLM Partners in the BLM Partnership and (iii) the Navy II Partners
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in the Navy II Partnership. These pledges secure the payment and performance
when due of all of the Obligations under the Guarantees.
So long as no Event of Default has occurred and is continuing, and subject to
certain terms and conditions in the Indenture, the Credit Agreements and the
Security Documents, all revenues actually received by the Coso partnerships
will be allocated to the appropriate Accounts in the manner described under the
caption "Flow of Funds."
Upon the occurrence and during the continuance of an Event of Default:
(1) all of our rights and the rights of the Coso partnerships and the
Partners to exercise any voting or other consensual rights in respect
of the pledged Collateral will cease. All of these rights will become
vested in the Trustee, which, to the extent permitted by law, will have
the sole right to exercise these voting and other consensual rights;
(2) the Trustee may sell the pledged Collateral or any part thereof for the
benefit of the Trustee and the Holders in accordance with the terms of
the Security Documents; and
(3) the Trustee shall have all rights of a "secured party" under the
Uniform Commercial Code of the State of New York.
All funds distributed under the Security Documents and the Indenture and
received by the Trustee for the benefit of the Holders will be distributed by
the Trustee in accordance with the provisions of the Indenture.
The Trustee will determine the circumstances and manner in which it will
dispose of the Collateral, including whether to release all or any portion of
the Collateral from the Liens created by the Security Documents and whether to
foreclose on the Collateral following an Event of Default. Upon the full and
final payment and performance of all Obligations in respect of the Partnership
Notes, the Indenture, the Series B notes and the Security Documents will
terminate and the Collateral will be released.
Optional Redemption
The Series B notes due 2001 are not redeemable.
The Series B notes due 2009 are redeemable at our option at any time and from
time to time, in whole or in part, upon not less than 30 nor more than 60 days
notice to each Holder of Series B notes due 2009, at a redemption price equal
to the Make-Whole Price. "Make-Whole Price" means an amount equal to the
greater of (i) 100% of the principal amount of such Series B notes due 2009 and
(ii) as determined by a Reference Treasury Dealer, the sum of the present
values of the remaining scheduled payments of principal and interest thereon
discounted to the date of redemption on a semiannual basis (assuming a 360-day
year consisting of twelve 30-day months) at the Treasury Rate plus 50 basis
points, plus, in each case, accrued and unpaid interest thereon to the
Redemption Date. Unless we default in payment of the redemption price, on and
after the Redemption Date, interest will cease to accrue on the Series B notes
due 2009 or portions thereof called for redemption.
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Mandatory Redemption
We will be required to redeem the Series B notes as described below. The
Series B notes will be subject to mandatory redemption, in whole or in part,
ratably among each series at a redemption price equal to the principal amount
of the Series B notes being redeemed plus accrued and unpaid interest to the
redemption date, upon:
(1) the receipt of Loss Proceeds or Eminent Domain Proceeds by a Coso
partnership if the applicable Coso partnership determines that:
(a) the affected Project cannot be rebuilt, repaired or restored to
permit operations on a commercially reasonable basis, or the
applicable Coso partnership determines not to rebuild, repair or
restore the affected Project, in which case the amount of such Loss
Proceeds or Eminent Domain Proceeds shall be available for such
redemption, or
(b) only a portion of the affected Project is capable of being rebuilt,
repaired or restored, in which case, if excess proceeds exist after
such rebuild, repair or restoration, only the amount of such excess
Loss Proceeds or Eminent Domain Proceeds shall be made available
for such redemption;
(2) the receipt by the applicable Coso partnership of proceeds in
connection with a Title Event, in which case the amount of such Title
Event Proceeds shall be made available for such redemption, subject to
reduction by the costs expended in connection with collecting proceeds
upon the occurrence of such Title Event, and any additional reasonable
costs or expenses that the Coso partnerships will be subject to as a
result of the Title Event;
(3) the receipt by the Coso partnerships of net proceeds in excess of $5.0
million realized in connection with a Permitted Power Contract Buy-Out,
or $10.0 million, when aggregated with all previous Permitted Power
Contract Buy-Outs, in which case the amount of all proceeds associated
with such Permitted Power Contract Buy-Outs shall be made available for
such redemption, unless each of the Rating Agencies confirm that a
Rating Downgrade will not occur if no redemption is made with such
proceeds; and
(4) the receipt by the Coso partnerships of net proceeds received in
connection with a termination of the Navy Contract under Section
VIII(2) of the Navy Contract (P0004 Modification dated October 19,
1983).
Selection and Notice
If less than all of the Series B notes are to be redeemed at any time, the
Trustee will select Series B notes for redemption on a pro rata basis, unless
otherwise required by the principal national securities exchange, if any, on
which the Series B notes are listed; provided that no Series B notes of $1,000
or less shall be redeemed in part; and provided, further, that in the case of
redemption of the Series B notes due 2009 at our option, only Series B notes
due 2009 will be redeemed. We will mail notices of redemption by first class
mail at least 30 but not more than 60 days before the redemption date to each
Holder of Series B notes to be redeemed at its registered address. Notices of
redemption may not be conditional. If any Series B note is to be redeemed in
part only, the notice of redemption that relates to that Series B note shall
state the portion of the principal amount of the Series B note to be redeemed.
A new Series B note in principal amount equal to the unredeemed portion of the
partially redeemed Series B note will be issued in the name of the Holder of
the partially redeemed Series B note upon cancellation of the original Series B
note. Series B notes called for redemption will become due on the date fixed
for redemption. Unless we default in payment of the redemption price on and
after the redemption date, interest ceases to accrue on Series B notes or
portions of them called for redemption.
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Repurchase at the Option of Holders upon Change of Control
Upon the occurrence of a Change of Control, each Holder of Series B notes
will have the right to require us to repurchase all or any part (equal to
$1,000 or an integral multiple thereof) of such Holder's Series B notes
pursuant to the offer described below (the "Change of Control Offer") at an
offer price in cash equal to 101% of the aggregate principal amount thereof
plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the
date of purchase (the "Change of Control Payment"). Within ten days following
any Change of Control, we will mail a notice to each Holder describing the
transaction or transactions that constitute the Change of Control and offering
to repurchase Series B notes on the date specified in such notice, which date
shall be no earlier than 30 days and no later than 60 days from the date such
notice is mailed (the "Change of Control Payment Date"), pursuant to the
procedures required by the Indenture and described in such notice. We will
comply with the requirements of Rule 14e-1 under the Exchange Act and any other
securities laws and regulations thereunder to the extent such laws and
regulations are applicable in connection with the repurchase of the Series B
notes as a result of a Change of Control.
On the Change of Control Payment Date, we will, to the extent lawful,
(1) accept for payment all Series B notes or portions thereof properly
tendered pursuant to the Change of Control Offer,
(2) deposit with the Paying Agent an amount equal to the Change of Control
Payment in respect of all Series B notes or portions thereof so
tendered, and
(3) deliver or cause to be delivered to the Trustee the Series B notes so
accepted together with an Officers' Certificate stating the aggregate
principal amount of Series B notes or portions thereof being purchased
by us.
The Paying Agent will promptly mail to each Holder of Series B notes so
tendered the Change of Control Payment for such Series B notes, and the Trustee
will promptly authenticate and mail (or cause to be transferred by book entry)
to each Holder a new Series B note equal in principal amount to any unpurchased
portion of the Series B notes surrendered, if any; provided that each such new
Series B note will be in a principal amount of $1,000 or an integral multiple
thereof. We will publicly announce the results of the Change of Control Offer
on or as soon as practicable after the Change of Control Payment Date.
The Change of Control provisions described above will be applicable whether
or not any other provisions of the Indenture are applicable. Except as
described above with respect to a Change of Control, the Indenture will not
contain provisions that permit the Holders of the Series B notes to require
that we repurchase or redeem the Series B notes in the event of a takeover,
recapitalization or similar transaction. Finally, our ability to pay cash to
the Holders of Series B notes upon a repurchase may be limited by our then
existing financial resources. See "Risk Factors--We may not have the funds
necessary to finance a change of control offer which may be required under the
Indenture."
We will not be required to make a Change of Control Offer upon a Change of
Control if a third party makes the Change of Control Offer in the manner, at
the times and otherwise in compliance with the requirements set forth in the
Indenture applicable to a Change of Control Offer made by us and purchases all
Series B notes validly tendered and not withdrawn under such Change of Control
Offer.
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The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of our assets and the assets of the Coso partnerships taken as a whole.
Although there is a developing body of case law interpreting the phrase
"substantially all," there is no precise established definition of the phrase
under applicable law. Accordingly, the ability of a Holder of Series B notes to
require us to repurchase such Series B notes as a result of a sale, lease,
transfer, conveyance or other disposition of less than all of our assets and
the assets of the Coso partnerships taken as a whole to another Person or group
may be uncertain.
Ratings
Moody's has assigned the senior secured notes due 2001 a rating of "Ba1" and
the senior secured notes due 2009 a rating of "Ba2." S&P has assigned each of
the senior secured notes due 2001 and the senior secured notes due 2009 a
rating of "BB." Duff & Phelps has assigned the senior secured notes due 2001 a
rating of "BB+" and the senior secured notes due 2009 a rating of "BB." We
cannot assure you that any of these credit ratings will remain in effect for
any period of time or that these ratings will not be lowered, suspended or
withdrawn entirely by Moody's, S&P or Duff & Phelps, if, in their judgment,
circumstances warrant a change. Any lowering, suspension or withdrawal of any
rating may have a material adverse effect on the market price or marketability
of the Series B notes.
Nature of Recourse on the Series B Notes
All payments of principal, interest, and premium, if any, and Liquidated
Damages, if any, on the Series B notes will be solely our obligations. Our
obligations to make those payments are secured by the liens described under "--
Security" and are guaranteed by the Coso partnerships. The Guarantees, in turn,
are secured by a perfected, first priority lien on substantially all of the
assets of the Coso partnerships, and the general partnership interests in the
Coso partnerships. The Series B notes are payable solely from payments to be
made by the Coso partnerships under the Partnership Notes and from other funds
that may be available from time to time in the Accounts held by the Depositary.
The Coso partnerships' obligations to make payments under the Partnership Notes
are non-recourse to the direct and indirect owners of the Coso partnerships
(including Caithness Energy, L.L.C.) except, in the case of the Partners, with
respect solely to recourse to the Partner's general partnership interests in
the Coso partnerships pledged to the Collateral Agent as security for the
Guarantees. Except for the Coso partnerships and the Partners (solely to the
extent that each Partner has pledged its general partnership interests in the
relevant Coso partnership), neither our shareholders nor any Affiliate,
incorporator, officer, director or employee of theirs or of ours has guaranteed
the payment of the Series B notes or has any obligation with respect to the
payment of the Series B notes.
Flow of Funds
Depositary Agreement
Under the Depositary Agreement, the Collateral Agent, on behalf of the
Secured Parties, has appointed the Depositary as security agent for the Secured
Parties with respect to funds of the Coso partnerships in which the Depositary
has been granted a security interest. The Depositary will hold, invest and
disburse funds in which the Depositary and/or the Collateral Agent, on behalf
of the Secured Parties, has been granted a security interest. Neither we nor
any of the Coso partnerships has any right of withdrawal under any Account
except under the circumstances established under the Depositary Agreement.
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The Depositary Agreement Accounts
The Coso partnerships have established and created the following accounts
(collectively, the "Accounts") with the Depositary under the Depositary
Agreement and pledged these Accounts as security for the benefit of the
Depositary and the Collateral Agent acting on behalf of all the Secured
Parties:
(1) Revenue Account;
(2) Principal Account;
(3) Interest Account;
(4) Debt Service Reserve Account;
(5) Capital Expenditure Reserve Account;
(6) Operating and Maintenance Fees Account;
(7) Management Fees Account;
(8) Distribution Account;
(9) Distribution Suspense Account;
(10) Loss Proceeds Account; and
(11) Redemption Account.
All amounts deposited with the Depositary, at our written request and
direction, will be invested by the Depositary in Permitted Investments.
Revenue Account; Priority of Payments
All revenues or other proceeds actually received by the Coso partnerships or
otherwise derived from the ownership or operation of the Coso projects are
required to be paid into the Revenue Account. The Coso partnerships have
arranged for the direct payment of all such revenues into the Revenue Account,
and no Coso partnership has any right of withdrawal from the Revenue Account
except pursuant to the priority of payments set forth below.
The Revenue Account is funded from the following:
(1) all revenues and other proceeds actually received by the Coso
partnerships (including payments under the Power Purchase Agreements);
(2) to the extent amounts in the Debt Service Reserve Account equal the
Debt Service Reserve Required Balance, the income, if any, from the
investment of funds in such Account; and
(3) other amounts as required to be transferred to the Revenue Account from
any other Account pursuant to the Depositary Agreement.
Upon receipt of a certificate from the relevant Coso partnership (or its duly
authorized agent for such purposes) detailing the amounts to be paid, funds in
the Revenue Account shall be transferred via wire transfer by the Depositary in
the following priority:
First, as and when required, to pay the Coso partnerships' Operating and
Maintenance Costs, provided that, if the cumulative Operating and Maintenance
Costs of the Coso partnerships in any fiscal year exceed the projected
Operating and Maintenance Costs of the Coso partnerships in the
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applicable annual Operating Budget of the Coso partnerships by more than 25%,
then no amounts may be withdrawn on behalf of the Coso partnerships to pay non-
budgeted operating costs unless the Coso partnerships certify that (1) such
additional non-budgeted costs are reasonably designed to permit the Coso
partnerships to satisfy their obligations in respect of the Partnership Notes
and maximize their revenue and net income and (2) the Independent Engineer
certifies that the additional cost is prudent and reasonable.
Second, on a monthly basis, to the Depositary, the Trustee, any Permitted
Additional Senior Lender and the Collateral Agent any amounts then due and
payable to each of them as fees, costs and expenses; provided, however, that if
funds in the Revenue Account are insufficient on any date to make the payments
specified in this paragraph Second, distribution of funds shall be made ratably
to the specified recipients based on the respective amounts owed such
recipients;
Third, on a monthly basis, (1) to the Interest Account an amount which,
together with the amount then in such account, equals all of the interest due
or becoming due on the senior secured notes and, without duplication, the
Partnership Notes on the next succeeding Interest Payment Date; (2) to the
Principal Account an amount which, together with the amount then in such
account, equals all of the principal and premium, if any, and Liquidated
Damages, if any, due or becoming due on the senior secured notes and, without
duplication, the Partnership Notes on the next succeeding Principal Payment
Date; (3) to a sub-account within the Principal Account an amount which,
together with the amounts then in such sub-account, equals all of the principal
due or becoming due on any Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness within the succeeding six-month
period; and (4) to a sub-account within the Interest Account an amount which,
together with the amounts then in such sub-account, equals all of the interest
due or becoming due on any Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness within the succeeding six-month
period (except to the extent that Permitted Indebtedness or other Permitted
Partnership Indebtedness other than such Indebtedness described in clause (4)
of the definition of Permitted Indebtedness is otherwise available to pay such
interest); provided, however, that if monies in the Revenue Account are
insufficient on any date to make the transfers specified in this paragraph
Third, distribution of monies shall be made ratably to the specified Accounts
based on the respective amounts owed such Accounts;
Fourth, on a monthly basis, if the amount available to be drawn under the
Debt Service Reserve Letter of Credit is less than the Debt Service Reserve
Required Balance, to the Debt Service Reserve Account an amount as necessary to
fund the Debt Service Reserve Account so that the sum of the amount available
to be drawn under the Debt Service Reserve Letter of Credit plus the balance in
the Debt Service Reserve Account equals the Debt Service Reserve Required
Balance;
Fifth, on a monthly basis, to the Capital Expenditure Reserve Account, an
amount necessary to cause the balance thereof to be equal to the Capital
Expenditure Reserve Required Balance;
Sixth, on a monthly basis, to the Operating and Maintenance Fees Account, an
amount necessary for the payment of Operating and Maintenance Fees then due and
owing;
Seventh, on a monthly basis, to the Management Fees Account, an amount
necessary for the payment of Management Fees then due and owing;
Eighth, on a monthly basis, any remaining amounts to the Distribution
Account; and
Ninth, any amounts in the Distribution Account which cannot be distributed
because of the failure to satisfy certain conditions to distributions, to the
Distribution Suspense Account.
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Interest Account and Principal Account
Funds in the Interest Account and the Principal Account shall be utilized to
make payments of interest and Liquidated Damages, if any, principal and
premium, if any, on the Partnership Notes, the senior secured notes and any
outstanding Permitted Indebtedness or other Permitted Partnership Indebtedness
other than such Indebtedness described in clause (4) of the definition of
Permitted Indebtedness.
Debt Service Reserve Account
The Debt Service Reserve Account was initially funded from the proceeds of
the Series A notes offering in an amount that equaled the Debt Service Reserve
Required Balance as of May 28, 1999. We may replace funds held in the Debt
Service Reserve Account with a Debt Service Reserve Letter of Credit having a
stated amount equal to the amount being withdrawn from the Debt Service Reserve
Account. These deposits, in conjunction with the Debt Service Reserve Letter of
Credit, if any, will be available in the event the Revenue Account, the
Principal Account and the Interest Account lack sufficient funds on a Payment
Date to meet payments of principal, premium, if any, and interest on the senior
secured notes.
At any time that the sum of the amount available to be drawn under the Debt
Service Reserve Letter of Credit plus the amount then on deposit in the Debt
Service Reserve Account is less than the Debt Service Reserve Required Balance,
the Debt Service Reserve Account shall then accumulate cash deposits from, and
in the following order of priority:
(1) the Revenue Account, as provided above under the caption "Flow of
Funds--Revenue Account; Priority of Payments"; and
(2) net interest, if any, earned on amounts deposited in the Debt Service
Reserve Account; and
(3) amounts then on deposit in the Operating and Maintenance Fees Account
and the Management Fees Account (in equal amounts from each such
Account),
until the sum of the amount available to be drawn under the Debt Service
Reserve Letter of Credit plus the amount then on deposit in the Debt Service
Reserve Account equals the Debt Service Reserve Required Balance. Once the Debt
Service Reserve Required Balance is reached, interest income, if any, in excess
of such amount shall be transferred to the Revenue Account.
Capital Expenditure Reserve Account
The Capital Expenditure Reserve Account shall be funded in accordance with
the provisions set forth above under the caption "Flow of Funds--Revenue
Account; Priority of Payments" and in accordance with the Operating Budget and
schedules thereto approved by the Independent Engineer prior to the end of each
calendar year (and, in good faith, so as to implement even monthly
contributions) or with such variations from such Operating Budget and schedules
as the Coso partnerships certify to the Trustee are reasonable and necessary
and in accordance with prudent industry practice. Amounts on deposit in the
Capital Expenditure Reserve Account shall be used for Capital Expenditures to
be made in accordance with prudent industry practice and as may be required
pursuant to the terms of the Indenture and the Depositary Agreement.
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Operating and Maintenance Fees Account
Funds in the Operating and Maintenance Fees Account shall be used for the
payment of Operating and Maintenance Fees due and owing; provided that:
(1) the aggregate amount of all Operating and Maintenance Fees paid on
account of any twelve month period shall not exceed an amount equal to
$2.0 million plus the CPI Adjustment; and
(2) the payment of any Operating and Maintenance Fees due and owing in
excess of the amount permitted pursuant to clause (1) above shall be
subject to the prior satisfaction of the conditions set forth under the
caption "--Distribution Account."
In addition, funds in the Operating and Maintenance Fees Account shall be
transferred to the Debt Service Reserve Account under the circumstances
described in the second paragraph under the caption "Debt Service Reserve
Account."
Management Fees Account
Funds in the Management Fees Account shall be used for the payment of
Management Fees due and owing subject to:
(1) the prior satisfaction of the conditions set forth under the caption
"Distribution Account"; and
(2) compliance by the Coso partnerships with the covenant set forth under
the caption "Credit Agreements--Certain Covenants--Required Geothermal
Percentage."
In addition, funds in the Management Fees Account shall be transferred to the
Debt Service Reserve Account under the circumstances described in the second
paragraph under the caption "Debt Service Reserve Account."
Distribution Account
The Distribution Account receives funds transferred from the Revenue Account
after all other then required amounts have been paid as provided above under
the caption "Revenue Account; Priority of Payments." Restricted Payments may be
made only from and to the extent of funds on deposit in the Distribution
Account. Such distributions are subject to the prior satisfaction of the
following conditions:
(1) the amount then on deposit in the Principal Account shall be equal to
or greater than the aggregate payments of principal and premium, if
any, and Liquidated Damages, if any, due on the senior secured notes
and, without duplication, the Partnership Notes on the next succeeding
Principal Payment Date and on other Permitted Indebtedness and
Permitted Partnership Indebtedness (other than such Indebtedness
described in clause (4) of the definition of Permitted Indebtedness)
within the succeeding six-month period, and the amount then on deposit
in the Interest Account shall be equal to or greater than the aggregate
payments of interest due on the senior secured notes and (without
duplication) the Partnership Notes on the next succeeding Interest
Payment Date and on other Permitted Indebtedness and Permitted
Partnership Indebtedness (other than such Indebtedness described in
clause (4) of the definition of Permitted Indebtedness) within the
succeeding six-month period;
(2) the amount available to be drawn under the Debt Service Reserve Letter
of Credit plus the amount on deposit in the Debt Service Reserve
Account equals or exceeds the Debt Service Reserve Required Balance and
the amount on deposit in the Capital Expenditure Reserve Account equals
or exceeds the Capital Expenditure Reserve Required Balance;
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(3) no Default or Event of Default has occurred and is continuing;
(4) the Debt Service Coverage Ratio for the most recently ended four full
fiscal quarters for which internal financial statements are available
immediately preceding the date on which such distribution is to be made
(or in the case of any proposed distribution date prior to January 1,
2000, the Debt Service Coverage Ratio for the period commencing on May
1, 1999, and ending on the last date of the most recently ended month
for which internal financial statements are available immediately
preceding the date on which such distribution is to be made) is equal
to or greater than (a) 1.25 to 1 for any annual or interim period
ending prior to or as of December 30, 2001 or (b) 1.4 to 1 for any
annual or interim period ending after December 30, 2001, in either case
as certified by one of our authorized officers;
(5) the projected Debt Service Coverage Ratio for the next succeeding four
full fiscal quarters is equal to or greater than (a) 1.25 to 1 for any
annual or interim period ending prior to or as of December 30, 2001 or
(b) 1.4 to 1 for any annual or interim period ending after December 30,
2001, in either case as certified by one of our authorized officers;
(6) We provide to the Trustee an Officers' Certificate at the time of each
distribution stating that, based on customary assumptions, as of such
date, sufficient geothermal resources remain to operate the Coso
projects at contract capacity through the Final Maturity Date; and
(7) the Geothermal Engineer provides to the Trustee (a) a written
certificate at least annually stating that, for the period covered by
such certification, the wells then in operation are producing, in the
aggregate among the Coso projects, at least 105% of the steam necessary
to generate the energy projected for the comparable period in the
Independent Engineer's Base Case Projections and (b) during the
calendar year 2006, a report on the geothermal resource available as of
such date and whether sufficient geothermal resource remains to enable
the Projects, in the aggregate, to produce sufficient steam to generate
the energy projected in the Independent Engineer's Base Case
Projections through the maturity date of the Series B notes due 2009.
Distribution Suspense Account
Funds in the Distribution Account which may not be distributed because of a
failure to satisfy any conditions to distributions will be transferred to the
Distribution Suspense Account. Funds in the Distribution Suspense Account may
be transferred back to the Distribution Account and distributed when (1) all
conditions to distribution are satisfied and (2) no Default or Event of Default
has occurred and is continuing. At any time that funds in the Revenue Account
are not sufficient to pay any amounts which are due and payable and required to
be paid with proceeds of the Revenue Account, then funds in the Distribution
Suspense Account shall be transferred to the Revenue Account for distribution
as required.
Loss Proceeds Account
All Loss Proceeds and Eminent Domain Proceeds received by the Coso
partnerships shall be deposited in the Loss Proceeds Account subject to
disbursement for repair or replacement of the assets affected, or otherwise, as
follows:
The Depositary will apply the amounts in the Loss Proceeds Account to the
payment (or reimbursement to the extent the same have been paid or satisfied by
the relevant Coso partnership) of the costs of repair or replacement of the
relevant Coso project or any part thereof that has been
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affected due to an Event of Loss or Event of Eminent Domain upon the
Depositary's receipt of a complete and properly executed requisition from an
authorized officer of the relevant Coso partnership and approved by the
Independent Engineer; provided, however, that no such approval of the
Independent Engineer shall be required if less than $5.0 million in the
aggregate for all Coso projects affected by such occurrence is requested
pursuant to such requisition or requisitions in any fiscal year.
If the applicable Coso partnership determines that the affected Project is
not capable of being rebuilt or replaced to permit operation on a commercially
reasonable basis, or determines not to rebuild, repair or restore the affected
Coso project (or if the Loss Proceeds and Eminent Domain Proceeds, together
with any other amounts available to such Coso partnership for such rebuilding
or replacement, are not sufficient to permit such rebuilding or replacement),
the Depositary shall transfer the Loss Proceeds and Eminent Domain Proceeds to
the Collateral Agent for distribution to the Redemption Account in accordance
with the Indenture and the Depositary Agreement. The Depositary shall transfer
the Loss Proceeds and Eminent Domain Proceeds in excess of the cost of
repairing or replacing the affected Project to the Redemption Account in
accordance with the Indenture and the Depositary Agreement. If the applicable
Coso partnership does not rebuild or replace the affected Coso project, the
Depositary shall transfer the Loss Proceeds and Eminent Domain Proceeds to the
Collateral Agent for distribution to the Redemption Account in accordance with
the Indenture and the Depositary Agreement. See "--Mandatory Redemption."
All Title Event Proceeds received by the Coso partnerships, as applicable,
shall be deposited in the Loss Proceeds Account subject to disbursement in
connection with remedying such Title Event. Any Title Event Proceeds not so
expended shall be transferred to the Redemption Account.
Redemption Account
The Redemption Account will be funded from:
(1) certain proceeds received in connection with an Event of Loss, an Event
of Eminent Domain or a Title Event;
(2) certain proceeds realized in connection with a Permitted Power Contract
Buy-Out;
(3) proceeds received in connection with a termination of the Navy Contract
under Section VIII(2) thereof; and
(4) proceeds received as a result of the foreclosure or the Collateral
serving the obligations of the Coso partnerships following an Event of
Default under the Indenture.
All proceeds received in connection with an Event of Loss, Event of Eminent
Domain or a Title Event will be deposited in the Loss Proceeds Account and
proceeds will be transferred to the Redemption Account if not used to repair or
replace the affected Coso project or remediate the title deficiency, as
permitted under the Indenture, and shall be distributed to the Collateral Agent
for distribution after giving effect to the provisions of the Indenture, and
the Depositary Agreement with respect to such proceeds. See "--Mandatory
Redemption."
Investment of Monies
Amounts deposited in the Accounts under the Depositary Agreement, at our or
any of the Coso partnership's written request and direction, shall be invested
by the Depositary in Permitted Investments. Such investments shall generally
mature in such amounts and not later than such times
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as may be necessary to provide monies when needed to make payments from such
monies as provided in the Depositary Agreement. Net interest or gain received,
if any, from such investments shall be applied as provided in the Depositary
Agreement. Absent written instructions from us, the Depositary shall invest the
amounts held in the accounts and funds under the Depositary Agreement in
Permitted Investments described in clause (1) of such definition. So long as an
outstanding balance shall remain in any of the Accounts under the Depositary
Agreement, the Depositary shall provide us and the Coso partnerships with
monthly statements showing the amount of all receipts, the net investment
income or gain received and collected, all disbursements and the amount then
available in each such Account.
Certain Covenants
Actions with Respect to the Credit Agreements
We will enforce all of our rights under the Credit Agreements and the
Partnership Notes for the benefit of the Trustee and the Holders. We will not
grant any consents or waivers thereunder, amend or modify any provisions
thereof or otherwise modify the Credit Agreements or the Partnership Notes,
except as provided below. See "--Amendment of Credit Agreement and Partnership
Notes."
Limitations on Indebtedness
We may not create or incur or suffer to exist any Indebtedness other than
Permitted Indebtedness.
Limitations on Guarantees
We may not contingently or otherwise be or become liable in connection with
any guarantee, except for endorsements and similar obligations in the ordinary
course of business.
Liens
We may not directly or indirectly, create, incur, assume or suffer to exist
any Lien of any kind on any asset now owned or hereafter acquired, except
Permitted Liens described in clause (1) of the definition of Permitted Liens.
Restricted Payments
We may not make any Restricted Payments or direct any Restricted Payments to
be made on behalf of any Coso partnership except for payments permitted under
the Depositary Agreement as described under the caption "Flow of Funds."
Prohibitions on Other Obligations or Assignments
We may not assign any of our rights or obligations under any Financing
Document, and may not enter into additional contracts if it would be reasonably
expected to cause a Material Adverse Effect and except otherwise only as
contemplated under the Indenture, including entering into contracts in
connection with investments in Permitted Investments.
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Prohibitions on Fundamental Changes
We may not enter into any transaction of merger or consolidation, change our
form of organization or our business, liquidate, wind-up or dissolve or
discontinue our business. We are also restricted from engaging in any business
other than in connection with the issuance of the senior secured notes, the
incurrence of Permitted Indebtedness and the performance of our obligations
under the Transaction Documents. We may not lease (as lessor) or sell,
transfer, assign, hypothecate, pledge or otherwise dispose of any of our
property or assets, except as may be contemplated by the Financing Documents.
Additional Covenants
In addition to the covenants described above, the Indenture contains
covenants applicable to us regarding (1) maintenance of existence, (2) payment
of taxes, (3) maintenance of books and records, (4) compliance with laws, (5)
delivery to the Trustee and the Rating Agencies of compliance certificates and
of notices of Credit Agreement Events of Default and Guarantee Events of
Default, (6) delivery to the Trustee and the Rating Agencies of unaudited
quarterly reports for us and the Coso partnerships for the first three quarters
of each fiscal year containing condensed combined financial information and
audited annual reports for us and the Coso partnerships, and (7) delivery to
the Trustee of all other information required to be delivered pursuant to Rule
144A(d)(4) under the Securities Act in order to permit compliance by a Holder
with Rule 144A in connection with the resale of Series A notes.
Events of Default
Certain Events
The Indenture provides that the following events constitute Events of
Default:
(1) Failure to pay any principal, interest or other amounts owed on any
senior secured notes when the same becomes due and payable, whether by
scheduled maturity or required prepayment or redemption or by
acceleration or otherwise, and such failure continues for ten days or
more following the due date for payment;
(2) A Credit Agreement Event of Default or a Guarantee Event of Default has
occurred and is continuing;
(3) Any representation or warranty made by us in the Indenture or in any
other Financing Document, or any representation, warranty or statement
in any certificate, financial statement or other document furnished to
the Trustee or any other Person by us or on our behalf, proves to have
been untrue or misleading in any material respect as of the time made,
confirmed or furnished and the fact, event or circumstance that gave
rise to such inaccuracy has resulted in, or could reasonably be
expected to result in, a Material Adverse Effect and that fact, event
or circumstance continues uncured for 30 or more days from the date one
of our Responsible Officers receives notice thereof from the Trustee;
provided that, if we commence and diligently pursue efforts to cure
such fact, event or circumstance within such 30-day period and deliver
written notice to the Trustee thereof, we may continue to effect such
cure, and such misrepresentation shall not be deemed an Event of
Default for an additional 60 days so long as we are diligently pursuing
such cure;
(4) We fail to perform or observe any covenant or agreement contained in
the Indenture regarding maintenance of existence or restrictions on
Indebtedness, Liens, Restricted Payments,
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guarantees, disposition of assets, amendments to the Credit Agreement or
Partnership Notes or taking of actions thereunder as directed by the
Required Holders, fundamental changes, or nature of business and such
failure continues uncured for 30 or more days from the date one of our
Responsible Officers receives notice thereof from the Trustee;
(5) We fail to perform or observe any of our covenants contained in the
Indenture (other than those contained in (4) above) and such failure
continues uncured for 30 or more days from the date one of our
Responsible Officers receives notice thereof from the Trustee of such
failure; provided that if we commence and diligently pursue efforts to
cure such default within such 30-day period, we may continue to effect
such cure of the default and such default will not be deemed an Event
of Default for an additional 90 days so long as we are diligently
pursuing such cure;
(6) Certain events involving our bankruptcy, insolvency, receivership or
reorganization;
(7) Any Pledge Agreement ceases to be in full force and effect or there is
a Material Adverse Effect on the Lien purported to be granted in any
Issuer Pledge Agreement such that it ceases to be a valid and perfected
Lien in favor of the Collateral Agent for the benefit of the Secured
Parties on the Collateral described therein with the priority purported
to be created thereby; provided, however, that we have 10 days after
one of our Responsible Officers obtains actual knowledge thereof to
cure any such cessation, if curable, or to furnish to the Collateral
Agent all documents or instruments required to cure any such cessation,
if curable; or
(8) Any event of default under any of our Indebtedness which results in
Indebtedness in excess of $2.5 million becoming due and payable prior
to its stated maturity.
Control by Holders
The Holders of at least a majority in aggregate principal amount of
Outstanding Notes (the "Required Holders") will have the right to direct the
time, place and method of conducting any proceeding for any right or remedy
available to the Trustee or exercising any trust or power conferred on the
Trustee in the Indenture. The Required Holders, acting through the Trustee,
will have the right to direct the time, place and method for exercising any
right or remedy available to the Issuer under the Credit Agreements and the
Partnership Notes; provided that upon the occurrence of an Event of Default
related to failure to make payments on the senior secured notes, Holders of
25% in aggregate principal amount of the Outstanding Notes have the right to
cause the acceleration of the Partnership Notes.
Subject to the above paragraph, if an Event of Default has occurred and is
continuing and as a result thereof or in connection therewith or pursuant to
an acceleration of the senior secured notes arising therefrom, payments on the
senior secured notes are not made when due, the Trustee is required to enforce
the Guarantees and the rights of the Holders thereunder.
Enforcement of Remedies
If one or more Events of Default have occurred and are continuing, then:
(a) in the case of an Event of Default described in clause (6) above under
"Certain Events," the entire principal amount of the Outstanding Notes,
all interest accrued and unpaid thereon, and all premium and other
amounts payable under the senior secured notes and the
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Indenture, if any, will automatically become due and payable without
presentment, demand, protest or notice of any kind; or
(b) in the case of an Event of Default described in clause (2) (in
connection with a Credit Agreement Event of Default or a Guarantee
Event of Default) above under "Certain Events" relating to certain
events involving the bankruptcy, insolvency, receivership or
reorganization of any of the Coso partnerships, the entire principal
amount of the Outstanding Notes (on a pro rata basis), all interest
accrued and unpaid thereon, and all premium and other amounts payable
under the senior secured notes and the Indenture, if any, will
automatically become due and payable without presentment, demand,
protest or notice of any kind; or
(c) in the case of an Event of Default described in:
(i) clause (1) above under "Certain Events," upon the direction of the
Holders of no less than 25% in aggregate principal amount of the
Outstanding Notes, the Trustee will, by notice to us, declare the
entire principal amount of the Outstanding Notes, all interest
accrued and unpaid thereon, and all premium and other amounts payable
under the senior secured notes and the Indenture, if any, to be due
and payable, or
(ii) clauses (2) (except as described in clause (b) above), (3), (4), (5),
(7) or (8) above under "Certain Events," upon the direction of the
Required Holders, the Trustee will, by notice to us, declare the
entire principal amount of the Outstanding Notes, all interest
accrued and unpaid thereon, and all premium and other amounts payable
under the senior secured notes and the Indenture, if any, to be due
and payable.
If an Event of Default occurs and is continuing and is known to the Trustee,
the Trustee will mail to each Holder notice of the Event of Default within 30
days after the occurrence thereof. Except in the case of an Event of Default
in payment of principal of or interest on any senior secured note, the Trustee
may withhold the notice to the Holders if the Trustee in good faith determines
that withholding the notice is in the interest of the Holders.
If an Event of Default relating to failure to pay amounts owed on the senior
secured notes has occurred and is continuing, the Trustee may declare the
principal amount of the Outstanding Notes, all interest accrued and unpaid
thereon, and all premium and other amounts payable under the senior secured
notes and the Indenture, if any, to be due and payable notwithstanding the
absence of direction from Holders of at least 25% in aggregate principal
amount of the Outstanding Notes directing the Trustee to accelerate the
maturity of the senior secured notes unless Holders of more than 75% in
aggregate principal amount of the Outstanding Notes direct the Trustee not to
accelerate the maturity of such senior secured notes, if in the good faith
exercise of its discretion the Trustee determines that such action is
necessary to protect the interests of the Holders.
If an Event of Default relating to a Credit Agreement Event of Default or a
Guarantee Event of Default (other than a Credit Agreement Event of Default
related to failure to pay the Partnership Notes or a Guarantee Event of
Default related to failure to make payments under the Guarantees) has occurred
and is continuing, the Trustee may declare the principal amount of the
Outstanding Notes, all interest accrued and unpaid thereon, and all premium
and other amounts payable under the senior secured notes and the Indenture, if
any, to be due and payable notwithstanding the absence of direction from the
Required Holders directing the Trustee to accelerate the maturity of such
amount of senior secured notes unless the Required Holders direct the Trustee
not to accelerate the maturity of such senior secured notes, if in the good
faith exercise of its discretion the Trustee determines that such action is
necessary to protect the interests of the Holders.
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In addition, if one or more of the Events of Default referred to in clause
(c)(ii) immediately above has occurred and is continuing, the Trustee may
declare the entire principal amount of the senior secured notes, all interest
accrued and unpaid thereon, and all premium and other amounts payable under the
senior secured notes and the Indenture, if any, to be due and payable
notwithstanding the absence of direction from the Required Holders directing
the Trustee to accelerate the maturity of the senior secured notes unless the
Required Holders direct the Trustee not to accelerate the maturity of the
senior secured notes, if in the good faith exercise of its discretion the
Trustee determines that such action is necessary to protect the interests of
the Holders.
In the case of any Event of Default occurring by reason of any willful action
or inaction taken or not taken by us or on our behalf with the intention of
avoiding payment of the premium that we would have had to pay if we then had
elected to redeem the Series A notes due 2009 or the Series B Notes due 2009
pursuant to the optional redemption provisions of the Indenture, a premium
equal to the then applicable Treasury Rate shall also become and be immediately
due and payable to the extent permitted by law upon the acceleration of the
Series A notes due 2009 or the Series B Notes due 2009. If an Event of Default
occurs at a time when the Series A notes due 2001 or the Series B notes due
2001 are outstanding by reason of any willful action (or inaction) taken (or
not taken) by us or on our behalf with the intention of avoiding the
prohibition on redemption of the Series A notes due 2001 or any Series B notes
due 2001, then a premium equal to the then applicable Treasury Rate shall also
become and be immediately due and payable to the extent permitted by law upon
the acceleration of the Series A notes due 2001 or the Series B notes due 2001.
At any time after the principal of the senior secured notes has become due
and payable upon a declared acceleration, and before any judgment or decree for
the payment of the money so due, or any portion thereof, has been entered, the
Holders of not less than a majority in aggregate principal amount of the
Outstanding Notes, by written notice to us and the Trustee, shall rescind and
annul such declaration and its consequences if:
(1) there has been paid to or deposited with the Trustee a sum sufficient
to pay:
(a) all overdue interest on the senior secured notes,
(b) the principal of and premium, if any, on any senior secured notes that
have become due (including overdue principal) other than by such
declaration of acceleration and interest thereon at the respective
rates provided in the senior secured notes for overdue principal,
(c) to the extent that payment of such interest is lawful, interest upon
overdue interest at the respective rates provided in the senior
secured notes for overdue interest, and
(d) all sums paid or advanced by the Trustee and the reasonable
compensation, expenses, disbursements, and advances of the Trustee,
its agents and counsel, and
(e) all Events of Default, other than the nonpayment of the principal of
the senior secured notes and the Partnership Notes that has become due
solely by such acceleration, have been cured or waived in accordance
with the Indenture;
(2) If an Event of Default relating to failure to pay amounts owed on the
senior secured notes has occurred and is continuing and an acceleration
has occurred, the Trustee may (as the Holders of 25% in aggregate
principal amount of the Outstanding Notes request) direct the
Collateral Agent to take possession of all Collateral;
(3) If an Event of Default relating to a Credit Agreement Event of Default
or a Guarantee Event of Default (other than a Credit Agreement Event of
Default related to failure to pay the
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Partnership Notes or a Guarantee Event of Default related to failure to
pay amounts owed on the senior secured notes) has occurred and is
continuing and an acceleration has occurred, the Trustee may (as the
Required Holders request) direct the Collateral Agent to take possession
of all Collateral;
(4) If an Event of Default other than those referred to in clauses (2) and (3)
above has occurred and is continuing and an acceleration has occurred, the
Trustee may (as the Required Holders request) direct the Collateral Agent
to take possession of all Collateral; or
(5) If one or more Guarantee Events of Default shall have occurred and be
continuing under a Guarantee, the Trustee may (as the Required Holders
request) direct the Collateral Agent to take possession of all Collateral.
Application of Monies Collected by Trustee
Any monies collected or to be applied by the Trustee after an Event of
Default in respect of the senior secured notes will be applied to amounts owed
with respect to all senior secured notes and all other Senior Indebtedness on
a pro rata basis and, in respect of senior secured notes of a series, will be
applied ratably to the Holders of senior secured notes in the following order
from time to time, on the date or dates fixed by the Trustee:
(1) first, to the payment of all amounts due to the Trustee or any
predecessor Trustee under the Indenture;
(2) second, (A) in case the unpaid principal amount of the Outstanding
Notes or other outstanding Senior Indebtedness has not become due, to
the payment of any overdue interest, (B) in case the unpaid principal
amount of a portion of the Outstanding Notes or other outstanding
Senior Indebtedness has become due, first to the payment of accrued
interest on all Outstanding Notes and all other Senior Indebtedness for
overdue principal, premium, if any, and overdue interest, and next to
the payment of the overdue principal on all senior secured notes and
all other Senior Indebtedness or (C) in case the unpaid principal
amount of all the Outstanding Notes and all other Senior Indebtedness
has become due, first to the payment of the whole amount then due and
unpaid upon the Outstanding Notes and all other Senior Indebtedness for
principal, premium, if any, and interest, together with interest for
overdue principal, premium, if any, and overdue interest; and
(3) third, in case the unpaid principal amount of all the Outstanding Notes
and all other Senior Indebtedness has become due, and all of the
outstanding principal, premium, if any, interest and other amounts owed
in connection with the senior secured notes and all other Senior
Indebtedness have been fully paid, any surplus then remaining will be
paid to us, or to whomsoever may be lawfully entitled to receive the
same, or as a court of competent jurisdiction may direct.
Amendments and Supplements
We, the Coso partnerships, the Trustee and the Collateral Agent may amend or
supplement the Indenture or execute a waiver without the consent of the
Holders:
. to add additional covenants of ours;
. to surrender rights conferred upon us, or to confer additional benefits
upon the Holders;
. to increase the assets securing our obligations under the Indenture;
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. to issue Additional Notes on the conditions described herein;
. to cure any ambiguity, defect or inconsistency or for any purpose not
inconsistent with the terms of the Indenture;
. to comply with requirements of the SEC in order to effect or maintain
the qualification of this Indenture under the Trust Indenture Act; or
. to reflect any amendments required by a Rating Agency in circumstances
where confirmation of the Ratings is required or permitted under the
Indenture.
The Indenture may be otherwise amended or supplemented by us, the Coso
partnerships, the Trustee and the Collateral Agent with the consent of Holders
of not less than a majority in aggregate principal amount of the Outstanding
Notes; provided that no such amendment or supplement may, without the consent
of all Holders of Outstanding Notes, modify:
. the principal, premium and interest payable upon the senior secured
notes,
. the dates on which interest or principal on any senior secured notes is
paid,
. the dates of maturity of any Series B notes, or
. the procedures for amendment by a supplemental indenture.
Notwithstanding the foregoing, the provisions in the Indenture relating to a
Change of Control and the related definitions as used therein may be amended by
the Holders of at least a majority in aggregate principal amount of the
Outstanding Notes.
Additional Senior Secured Notes
In the event we incur Permitted Indebtedness in the form of Additional Notes,
whether issued pursuant to the Indenture or a separate indenture, the Holders
of the senior secured notes and the holders of Additional Notes shall be
treated as one class for all purposes (including voting with respect to the
exercise of remedies in the event of an Event of Default). Notwithstanding
anything to the contrary in the Indenture, we and the Trustee may amend the
Indenture or enter into an intercreditor agreement to implement such treatment.
Amendment of Credit Agreement and Partnership Notes
We and the Trustee may, without the consent of or notice to the senior
secured note Holders, consent to any amendment or modification of any Credit
Agreement or the Partnership Notes
. as permitted by the provisions of the Credit Agreements, the Partnership
Notes or the Indenture,
. to cure any ambiguity, defect or inconsistency,
. to add additional rights in favor of us, or
. in connection with any amendment to the Credit Agreements or Partnership
Notes where such amendment is required by a Rating Agency in
circumstances where confirmation of the Ratings are required or
permitted under the Indenture or the Credit Agreements.
Except as described above, neither we nor the Trustee shall consent to any
other amendment or modification of the Credit Agreements or the Partnership
Notes or grant any waiver or consent
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thereunder without the consent of the Required Holders. An amendment to the
Credit Agreements or to the Partnership Notes which changes the amounts of
payments due thereunder, the Person to whom such payments are to be made or the
dates on which such payments are to be made shall not be made without the
unanimous consent of the Holders.
Satisfaction and Discharge of the Indenture; Defeasance
We may terminate the Indenture and the Guarantees by delivering all
Outstanding Notes to the Trustee for cancellation and by paying all other sums
payable under the Indenture.
Legal and covenant defeasance shall be permitted upon terms and conditions
customary for transactions of this nature.
Trustee
There shall at all times be a Trustee under the Indenture, which shall be a
corporation having either (1) a combined capital and surplus of at least $500.0
million, or (2) having a combined capital and surplus of at least $100.0
million and being a wholly owned subsidiary of a corporation having a combined
capital and surplus of at least $500.0 million in each case subject to
supervision or examination by a Federal or State or District of Columbia
authority and having a corporate trust office in New York, New York, to the
extent there is such an institution eligible and willing to serve. We agreed to
indemnify and hold harmless the Trustee in connection with the performance of
its duties under the Indenture, except for liability which results from the
negligence, bad faith or willful misconduct of the Trustee.
The Trustee may resign at any time by giving written notice thereof to us.
The Trustee may be removed at any time by act of the Required Holders,
delivered to the Trustee and to us. We will give notice of each resignation and
removal of the Trustee and each appointment of a successor Trustee to all
Holders.
Information Available to Holders
Pursuant to the Indenture, so long as any senior secured notes are
outstanding, we and the Coso partnerships will furnish to the Holders of senior
secured notes:
(1) all quarterly and annual financial information that would be required
to be contained in a filing with the SEC on Forms 10-Q and 10-K if we
and each Coso partnership were required to file such Forms, including a
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and, with respect to the annual information
only, a report thereon by our and each Coso partnership's certified
independent accountants, and
(2) all current reports that would be required to be filed with the SEC on
Form 8-K if we and the Coso partnerships were required to file such
reports, in each case within the time periods specified in the SEC's
rules and regulations.
In addition, for so long as any senior secured notes remain outstanding, we and
the Coso partnerships will furnish to the Holders and to securities analysts
and prospective investors, upon their request, the information required to be
delivered pursuant to Rule 144A(d)(4) under the Securities Act.
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Agent Relationship
Each Coso partnership has designated us as its agent under the Indenture for
the sole purpose of (i) issuing the Series B notes to the extent of each such
Coso partnership's obligations thereunder and (ii) otherwise carrying out each
Coso partnership's obligations and duties and exercising each Coso
partnership's rights and privileges under the Indenture. Each Coso partnership
will indemnify us against all claims arising in connection with our performance
of its obligations.
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Description of Credit Agreements
Pursuant to a Credit Agreement between each Coso partnership and us (the
"Credit Agreements"), (i) the Coso partnerships issued the Partnership Notes to
us at the closing of the Series A notes offering, and (ii) the Coso
partnerships agreed to make payments under the Partnership Notes in amounts
which are sufficient to enable us to pay scheduled principal of and interest on
the senior secured notes.
The Coso partnerships have absolutely and unconditionally agreed to make
payments under the Partnership Notes in scheduled installments and to pay
interest, in arrears, on the unpaid principal amount of each installment. If
the proceeds received from our issuance of Additional Notes are loaned to the
Coso partnerships, then additional Partnership Notes having a principal amount
equal to the amount of such proceeds so loaned to the Coso partnerships will be
issued by the Coso partnerships and such principal shall be payable in
scheduled installments which correspond to the repayment of principal of such
Additional Notes.
Optional Prepayment
Optional prepayment of the Partnership Notes shall not be permitted except in
connection with the defeasance of the senior secured notes or the optional
redemption of the Series A notes due 2009 and the Series B notes due 2009.
Mandatory Prepayment
The Coso partnerships are required to prepay the Partnership Notes with
proceeds received by the Coso partnerships in connection with an Event of Loss,
a Title Event, an Event of Eminent Domain, a Permitted Power Contract Buy-Out
or a termination of the Navy Contract under Section VIII(2) of the Navy
Contract to the extent set forth in "Description of Series B Notes--Mandatory
Redemption."
Certain Covenants
Set forth below are certain covenants of the Coso partnerships contained in
the Credit Agreements.
Events of Loss. If any Event of Loss or Event of Eminent Domain occurs and
the cost of repairing, restoring, replacing or rebuilding (collectively,
"Reconstructing") is $5.0 million or less, and if, in the reasonable judgment
of the managing partner of the relevant Coso partnership, to Reconstruct would
be prudent and consistent with such Coso partnership's obligations to maintain
such Coso project, then such Coso partnership shall, at its own expense and
whether or not such damage, destruction or loss is covered by an insurance
policy, with reasonable promptness, Reconstruct the same. If there are Loss
Proceeds or Eminent Domain Proceeds (from insurance or otherwise) available as
a result of such damage, destruction or loss in the amount of $5.0 million or
less, then said Loss Proceeds or Eminent Domain Proceeds shall be available to
such Coso partnership for application pursuant to the provisions described
under "Loss Proceeds Account."
If an Event of Loss or an Event of Eminent Domain occurs and the Loss
Proceeds or Eminent Domain Proceeds are greater than $5.0 million but less than
the total amount outstanding under the Partnership Note (the "Partnership Note
Balance") such Coso partnership shall have the option to Reconstruct the Coso
project, or any part thereof, upon the satisfaction of certain conditions. If
such Coso partnership fails to exercise such option, the Coso partnership shall
apply the Loss Proceeds or Eminent Domain Proceeds to prepay amounts
outstanding under the Partnership Note as described in "Mandatory Prepayment."
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If an Event of Loss or an Event of Eminent Domain occurs and the Loss
Proceeds or Eminent Domain Proceeds are equal to or exceed the Partnership Note
Balance, then the Coso partnership shall apply those Loss Proceeds or Eminent
Domain Proceeds to prepay amounts outstanding under its Partnership Note, as
described in "Mandatory Prepayment," unless such Coso partnership obtains a
determination form the Rating Agencies that the credit rating of the senior
secured notes that had been in effect immediately before the Event of Loss or
Event of Eminent Domain will not be adversely affected by applying those Loss
Proceeds or Eminent Domain Proceeds to Reconstruction of the Coso project.
Reporting Requirements. Each of the Coso partnerships shall provide to us:
. all quarterly and annual financial information that would be required to
be contained in a filing with the SEC on Forms 10-Q and 10-K if the Coso
partnerships were required to file such Forms, including a "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and, with respect to the annual information only, a report
thereon by the Coso partnerships' certified independent accountants;
. all current reports that would be required to be filed with the SEC on
Form 8-K if the Coso partnerships were required to file such reports, in
each case within the time periods specified in the SEC's rules and
regulations;
. all other information in respect of the Coso partnerships requested by
us to enable us to meet our obligations under the Indenture;
. copies of material notices; and
. written notice of any Credit Agreement Event of Default under the Credit
Agreement or any event or condition that could reasonably be expected to
result in a Material Adverse Effect. To the extent that the information
provided pursuant to the preceding sentence includes financial
statements of each of the Coso partnerships, the Coso partnerships also
shall provide to us combined financial statements.
Sale of Assets. Except as contemplated by the Transaction Documents, none of
the Coso partnerships shall sell, lease (as lessor) or transfer (as transferor)
any property or assets material to the operation of the Coso projects except
for fair value in the ordinary course of business to the extent that such
property is no longer useful or necessary in connection with the operation of
the Coso projects.
Ownership of Coso Partnerships. None of the Navy I Partners, Navy II Partners
or the BLM Partners shall sell, transfer or convey any partnership interests
held by such Partner in the Navy I partnership, Navy II partnership or the BLM
partnership, respectively, unless:
(1) such sale, transfer or conveyance would not result in any change in the
relevant Coso project's status as a Qualifying Facility; and
(2) the Person to whom such partnership interests are sold, transferred or
conveyed enters into a pledge agreement providing for the perfected,
first priority pledge to the Collateral Agent for the benefit of the
Trustee and the Holders of the senior secured notes of all such
partnership interests.
Insurance. The Coso partnerships shall maintain or cause to be maintained
insurance as is generally carried by companies engaged in similar businesses
and owning similar properties in the same general areas and financed in a
similar manner. The Coso partnerships shall maintain business interruption
insurance, casualty insurance, including flood and earthquake coverage, and
primary and
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excess liability insurance, as well as customary worker's compensation and
automobile insurance. The Coso partnerships shall not reduce or cancel such
insurance coverages (or permit any such coverages to be reduced or canceled) if
an independent insurance consultant determines that such reduction or
cancellation would not be reasonable under the circumstances and the insurance
coverages sought to be reduced or canceled are available on commercially
reasonable terms or that another level of coverage greater than that proposed
by the Coso partnerships is available on commercially reasonable terms (in
which case such coverage may be reduced to the higher of such available
levels).
QF Status. The Coso partnerships shall operate and maintain the Coso projects
as QFs unless the failure to so operate and maintain such Coso projects as QFs
would not cause or result in (1) a breach of the power purchase agreements that
the Coso partnerships are party to or (2) an adverse effect on the revenues to
be received under such power purchase agreements.
Governmental Approvals; Title. Each of the Coso partnerships shall at all
times (1) obtain and maintain in full force and effect all material
Governmental Approvals and other consents and approvals required at any time in
connection with its business and (2) preserve and maintain good and valid title
to its properties and assets (subject to no liens other than Permitted Liens),
except in each case where the failure to do so in clause (1) or (2) could not
reasonably be expected to have a Material Adverse Effect.
Nature of Business. None of the Coso partnerships shall engage in any
business other than their existing businesses.
Compliance with Laws. Each of the Coso partnerships shall comply with all
applicable laws, except where non-compliance could not reasonably be expected
to have a Material Adverse Effect.
Prohibition on Fundamental Changes. None of the Coso partnerships shall enter
into any transaction of merger or consolidation, change its form of
organization or its business, liquidate or dissolve itself (or suffer any
liquidation or dissolution); provided that any Coso partnership shall be able
to merge with or into any other Coso partnership so long as no Default or Event
of Default exists or will occur as a result thereof and subject to the
satisfaction of other customary conditions. None of the Coso partnerships shall
purchase or otherwise acquire all or substantially all of the assets of any
other Person, except for the purchase or acquisition by any of the Coso
partnerships of the partnership interests or assets related to the other Coso
project.
Revenue Account. Each of the Coso partnerships shall take all actions as may
be necessary to cause all revenues of the Coso partnerships to be deposited in
the Revenue Account to the extent required by the Depositary Agreement.
Transactions with Affiliates. Except as provided in or with respect to
Project Documents which currently exist, none of the Coso partnerships shall
make any payment to, or sell, lease, transfer or otherwise dispose of any of
its properties or assets to, or purchase any property or assets from, or enter
into or make or amend any transaction, contract, agreement, understanding,
loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an
"Affiliate Transaction"), unless:
(1) such Affiliate Transaction is on terms that are no less favorable to
the relevant Coso partnership than those that would have been obtained
in a comparable transaction by such Coso partnership with an unrelated
Person; and
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(2) the relevant Coso partnership delivers to the Trustee:
. with respect to any Affiliate Transaction or series of related
Affiliate Transactions involving aggregate consideration in excess
of $1.0 million, a resolution of the general partner of such Coso
partnership set forth in an Officers' Certificate certifying that
such Affiliate Transaction complies with this covenant and that such
Affiliate Transaction has been approved by a each of the Partners of
the Coso partnership; and
. with respect to any Affiliate Transaction or series of related
Affiliate Transactions involving aggregate consideration in excess
of $5.0 million, an opinion as to the fairness to the Holders of
such Affiliate Transaction from a financial point of view issued by
an investment banking firm of national standing.
The following items shall not be deemed to be Affiliate Transactions and,
therefore, will not be subject to the provisions of the prior paragraph:
(1) transactions between or among the Coso partnerships and us;
(2) payment of any Operating and Maintenance Fees or Management Fees,
provided that such payment is made in accordance with the provisions in
clauses (7) and (8) set forth under the caption "Flow of Funds--Revenue
Account; Priority of Payments;" and
(3) Restricted Payments that are permitted by the provisions of the
Depositary Agreement described below under the caption "--Restricted
Payments."
Restricted Payments. None of the Coso partnerships shall make any Restricted
Payments, except as permitted under the Depositary Agreement and described
under the caption "Flow of Funds."
Exercise of Rights Under Project Documents. None of the Coso partnerships
shall exercise, or fail to exercise, their rights under the Project Documents
in a manner which could reasonably be expected to result in a Material Adverse
Effect.
Amendments to Contracts. None of the Coso partnerships shall terminate,
amend, replace or modify, or permit to be terminated, amended, replaced or
modified, (other than immaterial amendments or modifications as certified by
the Coso partnerships) any of the Project Documents to which it is a party
unless:
. such Coso partnership certifies that such termination, amendment,
replacement or modification could not reasonably be expected to have a
Material Adverse Effect; and
. in the case of any amendment, termination or modification of a Power
Purchase Agreement which affects the revenues derived by any of the Coso
partnerships by more than $5.0 million, or $10.0 million when aggregated
with all previous amendments or modifications, the Coso partnerships
provide a letter from each of the Rating Agencies confirming that such
amendment, termination or modification will not result in a Rating
Downgrade after giving effect to any mandatory redemption of senior
secured notes required to be made in connection with any such amendment,
modification or termination pursuant to a Permitted Power Contract Buy-
Out.
Limitations on Indebtedness/Liens. None of the Coso partnerships shall create
or incur or suffer to exist any Indebtedness other than Permitted Partnership
Indebtedness. None of the Coso partnerships shall grant, create, incur or
suffer to exist any Liens upon any of its properties, except for Permitted
Liens.
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Operating Budget. If, during any fiscal year, any Coso partnership (1)
exceeds its Operating Budget by more than 25% or (2) expends 75% or less of its
Operating Budget, then in either case such Coso partnership shall cause the
Independent Engineer to certify that the expenditures were reasonably designed
to permit such Coso partnership to operate and maintain a facility of that type
and to maximize its revenue and net income.
Required Geothermal Percentage. Each Coso partnership shall use its best
efforts to maintain in cooperation with the other Coso partnerships, the
minimum geothermal resource required to produce, in the aggregate among all of
the Coso projects, at least 105% of the steam necessary to generate the energy
projected in the Independent Engineer's Base Case Projections. In addition:
(a) The Coso partnerships shall cause the Geothermal Engineer to deliver,
not more than 30 days after October 31 of each year, a certificate
setting forth the Actual Geothermal Percentage for the Projects
measured as of October 31 of such year;
(b) If as of October 31 in any year the Geothermal Engineer shall determine
that the Actual Geothermal Percentage for the Projects is less than
105%, then:
. the Coso partnerships shall develop a plan of corrective action to
achieve an Actual Geothermal Percentage of at least 105%, which plan
shall be approved by the Geothermal Engineer, and the Coso
partnerships shall diligently implement such approved plan; and
. no payment of Management Fees or any Restricted Payment shall be
made until such time as the Geothermal Engineer shall determine that
the Actual Geothermal Percentage for the Projects is at least equal
to 105%; and
(c) The Coso partnerships shall cause the Geothermal Engineer to deliver,
during the calendar year 2006, a report on the geothermal resource
available as of such date and whether sufficient geothermal resource
remains to enable the Coso projects, in the aggregate, to produce
sufficient steam to generate the energy projected in the Independent
Engineer's Base Case Projections through the maturity date of the
Series A notes due 2009 and the Series B notes due 2009.
Books and Records. The Coso partnerships shall maintain their books and
records and give us, the Trustee, the Collateral Agent and the Independent
Engineer inspection rights at reasonable times and upon reasonable prior
notice.
Additional Project Documents. The Coso partnerships shall perform and observe
their respective covenants and obligations under all of the Project Documents
in all material respects, except where the failure to do so could not
reasonably be expected to result in a Material Adverse Effect. The Coso
partnerships shall not be permitted to enter into any Additional Project
Documents if entering into such document would result in a Material Adverse
Effect; provided that the Coso partnerships shall be permitted to enter into
agreements for the purchase by such Coso partnerships of electricity so long as
(1) such agreements with respect to each Coso partnership do not provide for
payments in excess of $10.0 million per year by such Coso partnership and (2)
prior to entering into any such agreement the relevant Coso partnership
delivers an officer's certificate to the Trustee certifying that the proposed
agreement is on arms-length terms.
Additional Covenants. In addition to the covenants described above, the
Credit Agreements also contain covenants of the Coso partnerships regarding:
. maintenance of existence,
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. payment of taxes and claims unless being contested in good faith; and
. preservation and maintenance of Liens on the Collateral and the priority
thereof.
Events of Default.
Certain Events
The following events constitute Credit Agreement Events of Default under each
Credit Agreement:
(1) the failure by any of the Coso partnerships to pay or cause to be paid
any principal of, premium, if any, or interest, fees or any other
obligations on its Partnership Note for ten or more days after the same
becomes due and payable, whether by scheduled maturity or required
prepayment or by acceleration or otherwise;
(2) any representation or warranty made by any Coso partnership under its
Credit Agreement shall prove to have been untrue or misleading in any
material respect as of the time made, confirmed or furnished and the
fact, event or circumstance that gave rise to such inaccuracy could
reasonably be expected to result in a Material Adverse Effect and such
fact, event or circumstance shall continue to be uncured for 30 or more
days from the date a Responsible Officer of such Coso partnership
receives notice thereof from the Trustee; provided that if such Coso
partnership commences efforts to cure such fact, event or circumstance
within such 30-day period, such Coso partnership may continue to effect
such cure and such misrepresentation shall not be deemed a Credit
Agreement Event of Default for an additional 60 days so long as such
Coso partnership is diligently pursuing such cure;
(3) the failure by any of the Coso partnerships to perform or observe any
covenant under its Credit Agreement relating to maintenance of
existence, restrictions on Indebtedness, Permitted Liens, Restricted
Payments, guarantees, disposition of assets, maintenance of insurance,
amendments to the Project Documents, fundamental changes, or nature of
business and such failure shall continue uncured for 30 or more days
after a Responsible Officer of either of such Coso partnership receives
notice thereof from the Trustee;
(4) the failure by any of the Credit Parties to perform or observe any of
the other covenants under the Credit Agreement or in the other
Financing Documents the Credit Parties are party to (other than such
failures described in clause (1) or (3) above or (13) below) and such
failure shall continue uncured for 30 or more days after a Responsible
Officer of the Credit Parties receives notice thereof from the Trustee;
provided that if the Credit Parties commence efforts to cure such
default within such 30-day period, the Credit Parties may continue to
effect such cure of the default and such default shall not be deemed a
Credit Agreement Event of Default for an additional 90 days so long as
the Credit Parties are diligently pursuing such cure;
(5) certain events involving the bankruptcy, insolvency, receivership or
reorganization of any of the Coso partnerships;
(6) the entry of one or more final and non-appealable judgment or judgments
for the payment of money in excess of $2.5 million (exclusive of
judgment amounts fully covered by insurance or indemnity) against any
of the Coso partnerships, which remain unpaid or unstayed for a period
of 90 or more consecutive days after the entry thereof;
(7) any event of default under any Permitted Partnership Indebtedness
(other than Subordinated Indebtedness) that results in Permitted
Partnership Indebtedness in excess of $2.5 million becoming due and
payable prior to its stated maturity;
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(8) the Coso partnerships fail to perform any of their respective payment
obligations under their respective guarantees for 10 or more days
after the same becomes due and payable;
(9) any Governmental Approval required for the operation of a Project
owned by the Coso partnerships is revoked, terminated, withdrawn or
ceases to be in full force and effect if such revocation, termination,
withdrawal or cessation could reasonably be expected to have a
Material Adverse Effect and such revocation, termination, withdrawal
or cessation is not cured within 60 days following the occurrence
thereof;
(10) any Project Document ceases to be valid and binding and in full force
and effect prior to its stated maturity date other than as a result of
an amendment, termination or Permitted Power Contract Buy-Out
permitted under the Credit Agreement or any third party thereto fails
to perform its material obligations thereunder or makes any material
misrepresentation thereunder and such event results in a Material
Adverse Effect; provided that no such event shall be a Credit
Agreement Event of Default if within 180 days from the occurrence of
any such event, (a) the third party resumes performance or cures such
misrepresentation or (b) the applicable Coso partnership enters into
an Additional Project Document in replacement thereof, as permitted
under the Credit Agreement;
(11) the failure of the Coso partnerships or any other party to perform or
observe any of its covenants or obligations contained in any of the
Project Documents to which it is a party if such failure shall result
in the termination of such Project Document or otherwise result in a
Material Adverse Effect; provided, however, that such event shall not
be a Credit Agreement Event of Default if within 180 days from the
occurrence of any such event, the failure is cured or the Coso
partnerships enter into an Additional Project Document in replacement
thereof as permitted under the Credit Agreement;
(12) any of the Security Documents ceases to be effective or any Lien
granted therein ceases to be a valid and perfected Lien in favor of
the Collateral Agent on the Collateral described therein with the
priority purported to be created thereby; provided, however, that the
Credit Party party to any such Security Document shall have 10 days
after a Responsible Officer of the applicable Credit Party obtains
knowledge thereof to cure any such cessation or to furnish to the
Trustee, the Collateral Agent or the Depositary all documents or
instruments required to cure any such cessation;
(13) in the case of a determination by the Geothermal Engineer that the
Actual Geothermal Percentage is less than 105% (as set forth in the
annual certificate required pursuant to the covenant under the caption
"--Description of Credit Agreements--Certain Covenants --Required
Geothermal Percentage"), any:
. failure by the Coso partnerships (a) to prepare a plan approved by
the Geothermal Engineer within 90 days of such certification to
achieve an Actual Geothermal Percentage of at least 105%, (b) to
diligently implement such plan and (c) to achieve an Actual
Geothermal Percentage of at least 105% within a reasonable period
of time thereafter as determined in the sole discretion of the
Geothermal Engineer; or
. determination by the Geothermal Engineer or the Coso partnerships
that achieving an Actual Geothermal Percentage of at least 105% is
not reasonably feasible; or
(14) an Event of Default described under clauses (3), (4), (5), (6), (7) or
(8) of "Certain Events" of the summary of the Event of Default
provisions of the Indenture occurs. See "--Indenture--Events of
Default."
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Enforcement of Remedies
If one or more Credit Agreement Events of Default under any Credit Agreement
have occurred and are continuing, then:
(1) in the case of a Credit Agreement Event of Default under a Credit
Agreement described in clause (5) above, the entire outstanding
principal amount of all Partnership Notes, all interest accrued and
unpaid thereon, and all premium and other amounts payable under the
Partnership Notes and the Credit Agreements, if any, will automatically
become due and payable without presentment, demand, protest or notice
of any kind; or
(2) in the case of a Credit Agreement Event of Default described in:
. clause (1) and (8) above, upon the direction of the Holders of no
less than 25% in aggregate principal amount of the Outstanding
Notes, we will declare the outstanding principal amount of the
Partnership Notes and all interest accrued and unpaid thereon, and
all premium and other amounts payable under the Credit Agreements,
if any, to be due and payable; or
. clauses (2), (3), (4), (6), (7), (9), (10), (11), (12), (13) and
(14) above, upon the direction of the Required Holders, we will
declare the outstanding principal amount of the Partnership Notes
and all interest accrued and unpaid thereon, and all premium and
other amounts payable under the Credit Agreements, if any, to be due
and payable.
Additional Information
Anyone who receives this prospectus may obtain a copy of the Indenture, the
Depositary Agreement, the Pledge Agreements and other Financing Documents
without charge by writing to Caithness Coso Funding Corp., 1114 Avenue of the
Americas, 41st Floor, New York, New York 10036-7790, Attention: Secretary.
Book-Entry, Delivery and Form
The Series B notes will initially be represented by one or more Series B
notes in registered, global form (collectively, the "Global Series B Notes").
The Global Series B Notes will be deposited upon issuance with the Trustee as
custodian for The Depository Trust Company ("DTC"), in New York, New York, and
registered in the name of DTC or its nominee, in each case for credit to an
account of a direct or indirect participant in DTC as described below.
Except as set forth below, the Global Series B Notes may be transferred, in
whole and not in part, only to another nominee of DTC or to a successor of DTC
or its nominee. Beneficial interests in the Global Series B Notes may not be
exchanged for Series B notes in certificated form except in the limited
circumstances described below. See "--Exchange of Book-Entry Notes for
Certificated Notes." Except in the limited circumstances described below,
owners of beneficial interests in the Global Series B Notes will not be
entitled to receive physical delivery of Certificated Notes (as defined below).
In addition, transfers of beneficial interests in the Global Series B Notes
will be subject to the applicable rules and procedures of DTC and its direct or
indirect participants (including, if applicable, those of Euroclear and Cedel),
which may change from time to time.
The Trustee is acting as Paying Agent and Registrar. The Series B notes may
be presented for registration of transfer and exchange at the offices of the
Registrar.
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Depository Procedures
The following description of the operations and procedures of DTC, Euroclear
and Cedel are provided solely as a matter of convenience. These operations and
procedures are solely within the control of the respective settlement systems
and are subject to changes by them from time to time. We take no responsibility
for these operations and procedures and urges investors to contact the system
or their participants directly to discuss these matters.
DTC has advised us that DTC is a limited-purpose trust company created to
hold securities for its participating organizations (collectively, the
"Participants") and to facilitate the clearance and settlement of transactions
in those securities between the Participants through electronic book-entry
changes in accounts of the Participants. The Participants include securities
brokers and dealers (including the initial purchaser), banks, trust companies,
clearing corporations and certain other organizations. Access to DTC's system
is also available to other entities such as banks, brokers, dealers and trust
companies that clear through or maintain a custodial relationship with a
Participant, either directly or indirectly (collectively, the "Indirect
Participants"). Persons who are not Participants may beneficially own
securities held by or on behalf of DTC only through the Participants or the
Indirect Participants. The ownership interests in, and transfers of ownership
interests in, each security held by or on behalf of DTC are recorded on the
records of the Participants and the Indirect Participants.
DTC has also advised us that, pursuant to procedures established by it, (i)
upon deposit of the Global Series B Notes, DTC will credit the accounts of
Participants designated by the Trustee with portions of the principal amount of
the Global Series B Notes and (ii) ownership of such interests in the Global
Series B Notes will be shown on, and the transfer of ownership thereof will be
effected only through, records maintained by DTC (with respect to the
Participants) or by the Participants and the Indirect Participants (with
respect to other owners of beneficial interests in the Global Series B Notes).
Investors in the Global Series B Notes may hold their interests therein
directly through DTC, if they are Participants in such system, or indirectly
through organizations (including Euroclear and CEDEL) which are Participants in
such system. Euroclear and Cedel will hold interests in the Global Series B
Notes on behalf of their participants through customers' securities accounts in
their respective names on the books of their respective depositories, which are
Morgan Guaranty Trust Company of New York, Brussels office, as operator of
Euroclear, and Citibank, N.A., as operator of Cedel. All interests in a Global
Series B Note, including those held through Euroclear or Cedel, may be subject
to the procedures and requirements of DTC. Those interests held through
Euroclear or Cedel may also be subject to the procedures and requirements of
such systems. The laws of some states require that certain persons take
physical delivery in definitive form of securities that they own. Consequently,
the ability to transfer beneficial interests in a Global Series B Note to such
persons may be limited to that extent. Because DTC can act only on behalf of
the Participants, which in turn act on behalf of the Indirect Participants and
certain banks, the ability of a person having beneficial interests in a Global
Series B Note to pledge such interests to persons or entities that do not
participate in the DTC system, or otherwise take actions in respect of such
interests, may be affected by the lack of a physical certificate evidencing
such interests. For certain other restrictions on the transferability of the
Series B notes, see "--Exchange of Book-Entry Series B Notes for Certificated
Series B Notes."
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Except as described below, owners of interests in the Global Series B Notes
will not have Series B notes registered in their names, will not receive
physical delivery of Series B notes in certificated form and will not be
considered the registered owners or holders thereof under the Indenture for any
purpose.
Payments in respect of the principal of, and premium, if any, and interest on
a Global Series B Note registered in the name of DTC or its nominee will be
payable to DTC or its nominee in its capacity as the registered holder under
the Indenture. Under the terms of the Indenture, we and the Trustee will treat
the persons in whose names the Series B notes, including the Global Series B
Notes, are registered as the owners thereof for the purpose of receiving such
payments and for any and all other purposes whatsoever. Consequently, neither
we, the Trustee nor any agent of ours or the Trustee has or will have any
responsibility or liability for (i) any aspect of DTC's records or any
Participant's or Indirect Participant's records relating to or payments made on
account of beneficial ownership interests in the Global Series B Notes, or for
maintaining, supervising or reviewing any of DTC's records or any Participant's
or Indirect Participant's records relating to the beneficial ownership
interests in the Global Series B Notes, or (ii) any other matter relating to
the actions and practices of DTC or any of the Participants or the Indirect
Participants.
DTC has advised us that its current practice, upon receipt of any payment in
respect of securities such as the Series B notes (including principal and
interest), is to credit the accounts of the relevant Participants with the
payment on the payment date, in amounts proportionate to their respective
holdings in the principal amount of beneficial interests in the relevant
security as shown on the records of DTC unless DTC has reason to believe it
will not receive payment on such payment date. Payments by the Participants and
the Indirect Participants to the beneficial owners of the Series B notes will
be governed by standing instructions and customary practices and will not be
the responsibility of DTC, the Trustee or us. Neither we nor the Trustee will
be liable for any delay by DTC or any of the Participants in identifying the
beneficial owners of the Series B notes, and we and the Trustee may
conclusively rely on and will be protected in relying on instructions from DTC
or its nominee as the registered owner of the Global Series B Notes for all
purposes.
Except for trades involving only Euroclear and Cedel participants, interests
in the Global Series B Notes are expected to be eligible to trade in DTC's Same
Day Funds Settlement System and secondary market trading activity in such
interests will, therefore, settle in immediately available funds, subject in
all cases to the rules and procedures of DTC and the Participants. See "--Same
Day Settlement and Payment." Transfers between Participants in DTC will be
affected in accordance with DTC's procedures and will be settled in same day
funds, and transfers between participants in Euroclear and Cedel will be
effected in the ordinary way in accordance with their respective rules and
operating procedures.
Subject to compliance with the transfer restrictions applicable to the senior
secured notes described herein, cross-market transfers between the Participants
in DTC, on the one hand, and Euroclear or Cedel participants, on the other
hand, will be effected through DTC in accordance with DTC's rules on behalf of
Euroclear or Cedel, as the case may be, by its respective depositary; however,
such cross-market transactions will require delivery of instructions to
Euroclear or Cedel, as the case may be, by the counterparty in such system in
accordance with the rules and procedures and within the established deadlines
(Brussels time) of such system. Euroclear or Cedel, as the case may be, will,
if the transaction meets its settlement requirements, deliver instructions to
its respective depositary to take action to effect final settlement on its
behalf by delivering or receiving interests in the relevant Global Series B
Note in DTC, and making or receiving payment in accordance with
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normal procedures for same-day funds settlement applicable to DTC. Euroclear
participants and Cedel participants may not deliver instructions directly to
the depositories for Euroclear or Cedel.
DTC has advised us that it will take any action permitted to be taken by a
Holder of Series B notes only at the direction of one or more Participants to
whose account DTC has credited the interests in the Global Series B notes and
only in respect of such portion of the aggregate principal amount of the Series
B notes as to which such Participant or Participants has or have given such
direction. However, if any of the events described under "--Exchange of Book
Entry Series B Notes for Certificated Series B Notes" occurs, DTC reserves the
right to exchange the Global Series B Notes for legended Series B Notes in
certificated form and to distribute such Series B notes to its Participants.
Although DTC, Euroclear and Cedel have agreed to the foregoing procedures to
facilitate transfers of interests in the Global Series B Notes among
Participants in DTC, Euroclear and Cedel, they are under no obligation to
perform or to continue to perform such procedures, and such procedures may be
discontinued at any time. Neither we nor the Trustee nor any agent of ours or
the Trustee will have any responsibility for the performance by DTC, Euroclear
an Cedel or their participants or indirect participants of their respective
obligations under the rules and procedures governing their respective
operations.
Exchange of Book-Entry Notes for Certificated Notes
The Global Series B Notes will be exchangeable for definitive Series B notes
in registered certificated form ("Certificated Notes") if (i) DTC (x) notifies
us that it is unwilling or unable to continue as depository for the Global
Series B Notes and we thereupon fail to appoint a successor depository or (y)
has ceased to be a clearing agency registered under the Exchange Act, (ii) we,
at our option, notify the Trustee in writing that we elect to cause the
issuance of the Certificated Notes or (iii) there shall have occurred and be
continuing a Default or an Event of Default with respect to the Series B Notes.
In addition, beneficial interests in a Global Series B Note may be exchanged
for Certificated Notes upon request but only upon prior written notice given to
the Trustee by or on behalf of DTC in accordance with the Indenture. In all
cases, Certificated Notes delivered in exchange for any Global Series B Note or
beneficial interests in any Global Series B Note will be registered in the
names, and issued in any approved denominations, requested by or on behalf of
DTC (in accordance with its customary procedures).
Same Day Settlement and Payment
The Indenture requires that payments made in respect of the Series B notes
represented by the Global Series B Notes (including principal, premium, if any,
and interest) be made by wire transfer of immediately available funds to the
accounts specified by the Global Series B Note Holder. With respect to Series B
notes in certificated form, we will make all payments of principal, premium, if
any, and interest by wire transfer of immediately available funds to the
accounts specified by the Holders thereof or, if no such account is specified,
by mailing a check to each such Holder's registered address. The Series B notes
represented by the Global Series B Notes are expected to trade in the
Depository's Same-Day Funds Settlement System, and any permitted secondary
market trading activity in such senior secured notes will, therefore, be
required by the Depository to be settled in immediately available funds. We
expect that secondary trading in any Certificated Notes will also be settled in
immediately available funds.
Because of time zone differences, the securities account of a Euroclear or
Cedel participant purchasing an interest in a Global Series B Note from a
Participant in DTC will be credited, and any
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such crediting will be reported to the relevant Euroclear or Cedel participant,
during the securities settlement processing day (which must be a business day
for Euroclear and Cedel) immediately following the settlement date of DTC. DTC
has advised the Issuer that cash received in Euroclear or Cedel as a result of
sales of interests in a Global Series B Note by or through a Euroclear or Cedel
participant to a Participant in DTC will be received with value on the
settlement date of DTC but will be available in the relevant Euroclear or Cedel
cash account only as of the business day for Euroclear or Cedel following DTC's
settlement date.
Registration Rights; Liquidated Damages
The following is a summary of the material provisions of the registration
rights agreement. It does not purport to be complete and is subject to, and is
qualified entirely by, all of the provisions of the registration right
agreement. We urge you to read the registration rights agreement in its
entirety because it, and not this description, defines your registration rights
as Holders of the Series B notes. See "--Additional Information."
The Issuer, the Coso partnerships and the Initial Purchaser entered into the
registration rights agreement pursuant to which we and the Coso partnerships
agreed to file with the SEC the exchange offer registration statement on an
appropriate form under the Securities Act with respect to an offer to exchange
the Series A notes.
If:
(1) We and the Coso partnerships are not:
(a) required to file the exchange offer registration statement; or
(b) permitted to consummate the exchange offer because the exchange
offer is not permitted by applicable law or SEC policy; or
(2) any Holder of Transfer Restricted Securities notifies us prior to the
20th day following consummation of the exchange offer that:
(a) it is prohibited by law or SEC policy from participating in the
exchange offer; or
(b) that it may not resell the Series B notes acquired by it in the
exchange offer to the public without delivering a prospectus and
the prospectus contained in the exchange offer registration
statement is not appropriate or available for such resales; or
(c) that it is a broker-dealer and owns Series A notes acquired
directly from us or one of our affiliates,
then we and the Coso partnerships will file with the SEC a shelf registration
statement to cover resales of Transfer Restricted Securities by the Holders
thereof who satisfy certain conditions relating to the provision of information
in connection with the shelf registration statement.
We and the Coso partnerships will use their best efforts to cause the
applicable registration statement to be declared effective as promptly as
possible by the SEC. For purposes of the preceding, "Transfer Restricted
Securities" means each Series A note until the earliest to occur of:
(1) the date on which such Series A note has been exchanged by a Person
other than a broker-dealer for a Series B note in the exchange offer;
(2) following the exchange by a broker-dealer in the exchange offer of a
Series A note for a Series B note, the date on which such Series B note
is sold to a purchaser who receives from such broker-dealer on or prior
to the date of such sale a copy of the prospectus contained in the
exchange offer registration statement;
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(3) the date on which such Series A note has been effectively registered
under the Securities Act and disposed of in accordance with the shelf
registration statement; or
(4) the date on which such Series A note is distributed to the public
pursuant to Rule 144 under the Securities Act.
The registration rights agreement provides:
(1) we and the Coso partnerships will file an exchange offer registration
statement with the SEC on or prior to 90 days after the closing of the
Series A notes offering;
(2) we and the Coso partnerships will use our and their best efforts to
have the exchange offer registration statement declared effective by
the SEC on or prior to 180 days after the closing of the Series A notes
offering;
(3) unless the exchange offer would not be permitted by applicable law or
SEC policy, we and the Coso partnerships will
(a) commence the exchange offer; and
(b) use our and their best efforts to issue on or prior to 30 business
days, or longer, if required by the federal securities laws, after
the date on which the exchange offer registration statement is
declared effective by the SEC, Series B notes in exchange for all
Series A notes tendered prior thereto in the exchange offer; and
(4) if obligated to file the shelf registration statement, we and the Coso
partnerships will use our and their best efforts to file the shelf
registration statement with the SEC on or prior to 45 days after such
filing obligation arises and to cause the shelf registration statement
to be declared effective by the SEC on or prior to 90 days after such
obligation arises.
If:
(1) we and the Coso partnerships fail to file any of the registration
statements required by the registration rights agreement on or before
the date specified for such filing; or
(2) any of such registration statements is not declared effective by the
SEC on or prior to the date specified for such effectiveness (the
"Effectiveness Target Date"); or
(3) we and the Coso partnerships fail to consummate the Exchange Offer
within 30 business days of the Effectiveness Target Date with respect
to the exchange offer registration statement; or
(4) the shelf registration statement or the exchange offer registration
statement is declared effective but thereafter ceases to be effective
or usable in connection with resales of Transfer Restricted Securities
during the periods specified in the registration rights agreement (each
such event referred to in clauses (1) through (4) above, a
"Registration Default"),
then we and the Coso partnerships will pay liquidated damages ("Liquidated
Damages") to each Holder of Transfer Restricted Securities, with respect to the
first 90-day period immediately following the occurrence of the first
Registration Default in an amount equal to $.05 per week per $1,000 principal
amount of Transfer Restricted Securities held by such Holder.
The amount of the Liquidated Damages will increase by an additional $.05 per
week per $1,000 principal amount of Transfer Restricted Securities with respect
to each subsequent 90-day period until all Registration Defaults have been
cured, up to a maximum amount of Liquidated Damages for all Registration
Defaults of $.25 per week per $1,000 principal amount of Transfer Restricted
Securities.
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All accrued Liquidated Damages will be paid by us and the Coso partnerships
on each Damages Payment Date to the holder of the Series A global notes by wire
transfer of immediately available funds or by federal funds check and to
holders of certificated Series A notes by wire transfer to the accounts
specified by them or by mailing checks to their registered addresses if no such
accounts have been specified.
Following the cure of all Registration Defaults, the accrual of Liquidated
Damages will cease.
Holders of Series A notes will be required to make certain representations to
us (as described in the registration rights agreement) in order to participate
in the exchange offer and will be required to deliver certain information to be
used in connection with the shelf registration statement and to provide
comments on the shelf registration statement within the time periods set forth
in the registration rights agreement in order to have their Series A notes
included in the shelf registration statement and benefit from the provisions
regarding Liquidated Damages set forth above. By acquiring Transfer Restricted
Securities, a Holder will be deemed to have agreed to indemnify us and the Coso
partnerships against certain losses arising out of information furnished by
such Holder in writing for inclusion in any shelf registration statement.
Holders of Series A notes will also be required to suspend their use of the
prospectus included in the shelf registration statement under certain
circumstances upon receipt of written notice to that effect from us.
Certain Definitions
Certain terms defined below are summaries of terms defined in, and are
defined more specifically in, the Project Documents and the Financing
Documents. Such summaries do not purport to be complete and are subject to, and
are qualified in their entirety by reference to, all of the provisions of the
Project Documents and the Financing Documents.
"Accounts" means the accounts established under the Depositary Agreement.
"Actual Geothermal Percentage" means a percentage calculated by dividing the
geothermal resource available at the wellhead or pursuant to a contract for
such geothermal resource by the resource that would be required to meet the
production level necessary to generate the energy projected in the Independent
Engineer's Base Case Projections.
"Additional Notes" means additional senior secured notes, other than the
senior secured notes, having the same final maturity and amortization as the
Series B notes due 2001 or the Series B notes due 2009, as the case may be,
except as amortization may be increased pro rata across all payments to reflect
such shorter term, if any.
"Additional Project Document" means:
(1) any contract or undertaking relating to the purchase or sale of
electricity from the Projects entered into by any of the Coso
partnerships after the closing of the Series A notes offering;
(2) any consent or security instrument entered into by any of the Coso
partnerships or any other relevant party in connection with an
Additional Project Document; or
(3) any contract or undertaking to which we or any Coso partnership is a
party entered into after the closing of the Series A notes offering,
relating to (i) the supply, procurement or transportation of
consumables or other supplies to the Coso projects, or (ii) the design,
construction, operation or maintenance of the Coso projects; in each
case which is material to the applicable Coso project.
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"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition, "control,"
as used with respect to any Person, shall mean the possession, directly or
indirectly, of the power to direct or cause the direction of the management or
policies of such Person, whether through the ownership of voting securities, by
agreement or otherwise; provided that beneficial ownership of 10% or more of
the Voting Stock of a Person shall be deemed to be control. For purposes of
this definition, the terms "controlling," "controlled by" and "under common
control with" shall have correlative meanings.
"Approved Related Party" with respect to any Change of Control means:
(1) any direct or indirect controlling stockholder or 80% (or more) owned
Subsidiary of Caithness Energy, L.L.C.; or
(2) any trust, corporation, partnership or other entity, the beneficiaries,
stockholders, members, partners, owners or Persons beneficially holding
an 80% or more controlling interest of which consist of Caithness
Energy, L.L.C. and/or such other Persons referred to in the immediately
preceding clause (1).
"BLM Partners" means Caithness Coso Holdings, LLC, a Delaware limited
liability company, and New CHIP Company, LLC, a Delaware limited liability
company, the general partners of the BLM Partnership.
"BLM Partnership" means Coso Energy Developers, a California general
partnership.
"BLM Project" means, collectively, BLM East, which consists of two 30 MW
turbine generators, and BLM West, which consists of one 30 MW turbine
generator.
"Capital Expenditure Reserve Account" means the account of such name created
under the Depositary Agreement.
"Capital Expenditure Reserve Required Balance" means an amount equal to the
aggregate Capital Expenditures budgeted for the Coso projects for the next
succeeding twelve-month period (a) as approved by the Independent Engineer and
delivered to the Trustee at least annually and (b) as adjusted by management
and set forth in an Officers' Certificate delivered to the Trustee six months
following each budget approved by the Independent Engineer.
"Capital Expenditures" means Major Maintenance, any expenses incurred in
connection with the development and implementation of any plan for the drilling
and maintenance of additional geothermal wells for the Coso projects and any
other expenses that are capitalized on the balance sheet and qualify as capital
expenditures of the relevant Coso partnership in accordance with GAAP.
"Capital Stock" means:
(1) in the case of a corporation, corporate stock;
(2) in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however
designated) of corporate stock;
(3) in the case of a partnership or limited liability company, partnership
or membership interests (whether general or limited); and
(4) any other interest or participation that confers on a Person the right
to receive a share of the profits and losses of, or distributions of
assets of, the issuing Person.
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"Change of Control" means the occurrence of any of the following:
(1) the direct or indirect sale, transfer, conveyance or other disposition
(other than by way of merger or consolidation), in one or a series of
related transactions, of all or substantially all of the properties or
assets of the Issuer and the Coso partnerships taken as a whole to any
"person" (as that term is used in Section 13(d)(3) of the Exchange Act)
other than Caithness Energy, L.L.C. or an Approved Related Party;
(2) the adoption of a plan relating to the liquidation or dissolution of
the Issuer or any of the Coso partnerships; or
(3) the first day on which Caithness Energy, L.L.C. ceases to own, directly
or indirectly, (a) 50% or more of the total voting power of the Voting
Stock of the Issuer and of each of the Coso partnerships and (b) 25% or
more of the total economic ownership interests in the Issuer and each
Coso partnership.
"Collateral" means all collateral pledged, or in respect of which a lien is
granted, pursuant to the Indenture and the Security Documents.
"Collateral Agent" means U.S. Bank Trust National Association, as collateral
agent for the benefit of the Secured Parties, together with its successors and
assigns.
"Comparable Treasury Issue" means the United States Treasury security
selected by a Reference Treasury Dealer as having a maturity comparable to the
Remaining Average Life of the Series A notes due 2009 or the Series B notes
2009 to be redeemed that would be utilized, at the time of selection and in
accordance with customary financial practice, in pricing new issues of
corporate debt securities of comparable maturity to the Remaining Average Life
of such notes.
"Comparable Treasury Price" means, with respect to any date of redemption,
(i) the average of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) on the third
business day preceding such date of redemption, as set forth in the daily
statistical release (or any successor release) published by the Federal Reserve
Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S.
Government Securities," or (ii) if such release (or any successor release) is
not published or does not contain such prices on such business day, (A) the
average of the Reference Treasury Dealer Quotations, or (B) if the Trustee
obtains fewer than three such Reference Treasury Dealer Quotations, the average
of all such Reference Treasury Dealer Quotations.
"CPI Adjustment" means an amount equal to (i) $2.0 million plus the amount of
all previous annual adjustments made pursuant to this definition multiplied by
(ii) the percentage change from the previous year in the annual average
consumer price index as published by the Bureau of Labor Statistics of the
United States Department of Labor in the "Consumer Price Index for All Urban
Consumers, 1982-84 = 100, All Cities, % change past year' under the column "Yr.
Avg."'; provided that for purposes of calculating the CPI Adjustment, the most
recently ended calendar year prior to the date of determination shall be used;
and provided, further, the CPI Adjustment for the twelve months ended December
30, 1999, shall be zero. If the Bureau of Labor Statistics shall no longer
publish such statistics, or if the Bureau of Labor Statistics shall no longer
maintain any statistics on the purchasing power of the consumer dollar,
comparable statistics published by a reasonable financial periodical or
recognized authority mutual agreed upon by the Issuer and the Trustee shall be
used to determine the CPI Adjustment.
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"Credit Agreement" means, individually, (1) that certain Credit Agreement
dated as of May 28, 1999, between the Navy I Partnership, as borrower, and us,
as lender, (2) that certain Credit Agreement dated as of May 28, 1999, between
the BLM Partnership, as borrower, and us, as lender, or (3) that certain Credit
Agreement dated as of May 28, 1999, between the Navy II Partnership, as
borrower, and us, as lender.
"Credit Agreement Event of Default" means a Credit Agreement Event of Default
as defined in the Credit Agreement.
"Credit Parties" means each of the Coso partnerships, each of the Partners
and each affiliate of the Coso Partnerships or the Partners that is a party to
any Security Document.
"Custodian" means, initially, the Trustee, and its successors and assigns or
any other custodian performing similar functions.
"Debt Service Coverage Ratio" means for any period, without duplication, the
ratio of (i) (A) the sum of all revenues (including interest and fee income,
but excluding any insurance proceeds and all other similar non-recurring
receipts in an aggregate amount in excess of $2.0 million in any twelve-month
period) of the Coso partnerships for such period, minus (B) the aggregate
amount of Operating and Maintenance Costs of the Coso partnerships for such
period, minus (C) all Capital Expenditures during such period, to (ii) the sum
of (A) all principal, premium (if any) and interest payable with respect to
Permitted Indebtedness outstanding (other than Subordinated Indebtedness) for
such period, plus (B) the aggregate amount of overdue principal, premium (if
any) and interest payments owed with respect to Permitted Indebtedness
outstanding (other than Subordinated Indebtedness) from previous periods; all
as determined on a cash basis in accordance with GAAP.
"Debt Service Reserve Account" means the account of such name created under
the Depositary Agreement.
"Debt Service Reserve Letter of Credit" one or more irrevocable, direct pay
letters of credit issued by the Debt Service Reserve LOC Provider in favor of
the Depositary where the account party is not the Issuer and/or Coso
partnerships.
"Debt Service Reserve LOC Provider" means the commercial bank(s) or financial
institution(s) issuing the Debt Service Reserve Letter of Credit, which
institution shall be rated not less than A by S&P and A2 by Moody's.
"Debt Service Reserve Required Balance" means, on the closing date of the
Series A notes offering, $50.0 million, and thereafter an amount equal to the
aggregate amount of the principal and interest due on the senior secured notes
on the next succeeding semi-annual scheduled payment date.
"Deeds of Trust" means (i) that certain Deed of Trust, Assignment of Rents,
Fixture Filing and Security Agreement dated as of May 28, 1999, executed by the
Navy I Partnership in favor of the trustee thereunder and the Collateral Agent
as beneficiary, (ii) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security Agreement dated as of May 28, 1999, executed by the BLM
Partnership in favor of the trustee thereunder and the Collateral Agent as
beneficiary, (iii) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security Agreement dated as of May 28, 1999, executed by the Navy II
Partnership in favor of the trustee thereunder and the Collateral Agent as
beneficiary, (iv) that certain Deed of Trust, Assignment of Rents, Fixture
Filing and Security
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Agreement dated as of May 28, 1999, executed by Coso Transmission Line Partners
in favor of the trustee thereunder and the Collateral Agent as beneficiary, (v)
that certain Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement dated as of May 28, 1999, executed by China Lake Joint Venture in
favor of the trustee thereunder and Collateral Agent as beneficiary, (vi) that
certain Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement dated as of May 28, 1999, executed by Coso Land Company in favor of
the trustee thereunder and the Collateral Agent as beneficiary and (vii) any
other deed of trust entered into by any Credit Party in favor of the trustee
thereunder and the Collateral Agent as beneficiary.
"Default" means an event or condition that, with the giving of notice, lapse
of time or failure to satisfy certain specified conditions, or any combination
thereof, would become a Credit Agreement Event of Default or an Event of
Default.
"Depositary" means U.S. Bank Trust National Association, as depositary under
the Depositary Agreement.
"Depositary Agreement" means the Deposit and Disbursement Agreement, dated as
of May 28, 1999, between the Issuer, the Collateral Agent, the Depositary and
the Coso partnerships.
"Distribution Account" means the account of such name created under the
Depositary Agreement.
"Distribution Suspense Account" means the account of such name created under
the Depositary Agreement.
"Duff & Phelps" means Duff & Phelps Credit Rating Company.
"Eminent Domain Proceeds" means all amounts and proceeds (including
instruments) received by a Coso partnership in respect of any Event of Eminent
Domain, after deducting all reasonable expenses incurred in litigating,
arbitrating, compromising, settling or consenting to the settlement of any
claims against the appropriate Governmental Authority (exclusive of any
termination by the Navy of the Navy Contract pursuant to the terms thereof).
"Equity Interests" means Capital Stock and all warrants, options or other
rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"Event of Default" means the occurrence of an event of default under the
Indenture.
"Event of Eminent Domain" means any compulsory transfer or taking or transfer
under threat of compulsory transfer or taking of any material part of the
Collateral or the Coso projects by any Governmental Authority, but excluding
any termination of the Navy Contract.
"Event of Loss" means an event which causes all or a portion of a Coso
project to be damaged, destroyed or rendered unfit for normal use for any
reason whatsoever, other than an Event of Eminent Domain or a Title Event.
"Final Maturity Date" means the latest stated maturity date of any series of
the senior secured notes.
"Financing Documents" means, collectively, the Credit Agreement, the
Guarantees, the Indenture, the Partnership Notes, the Depositary Agreement, the
Security Documents and the senior secured notes.
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"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements by such
other entity as have been approved by a significant segment of the accounting
profession, which are in effect from time to time.
"Geothermal Engineer" means GeothermEx Inc., or another widely recognized
geothermal engineer retained as a geothermal engineer by us.
"Geothermal Engineer's Report" means a geothermal engineer's report, dated
May 1999, prepared by the Geothermal Engineer and attached to this prospectus
as Exhibit C.
"Governmental Approvals" means all governmental approvals, authorizations,
consents, decrees, permits, waivers, privileges and filings with all
Governmental Authorities required to be obtained for the construction,
operation and maintenance of a Coso project.
"Governmental Authority" means the government of any federal, state,
municipal or other political subdivision in which the Coso projects are
located, and any other government or political subdivision thereof exercising
jurisdiction over the Coso projects or any party to any of the Project
Documents, including all agencies and instrumentalities of such governments and
political subdivisions.
"Guarantee Event of Default" means an Event of Default under and as defined
in a Guarantee.
"Indebtedness" of any Person means, at any date, without duplication:
(1) all obligations of such Person for borrowed money;
(2) all obligations of such Person evidenced by senior secured notes,
debentures, notes or other similar instruments (excluding "deposit
only" endorsements on checks payable to the order of such Person);
(3) all obligations of such Person to pay the deferred purchase price of
property or services (except accounts payable and similar obligations
arising in the ordinary course of business shall not be included
herein);
(4) all obligations of such Person as lessee under capital leases to the
extent required to be capitalized on the books of such Person in
accordance with GAAP; and
(5) all obligations of others of the type referred to in clause (1) through
(4) above guaranteed by such Person, whether or not secured by a lien
or other security interest on any asset of such Person;
provided that "Indebtedness" shall exclude obligations of the Coso
partnerships to the California Energy Commission and liens securing such
obligations to the extent that such obligations and liens do not exceed the
dollar amounts paid to, or to be paid, the Coso partnerships pursuant to
AB1890.
"Independent Engineer" means Sandwell Engineering Inc. or another widely
recognized independent engineering firm or engineer retained as independent
engineer by the Issuer.
"Independent Engineer's Base Case Projections" means the base case
projections prepared by the Independent Engineer and included in the
Independent Engineer's Report.
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"Independent Engineer's Report" means the Independent Engineer's Report,
dated May 20, 1999, prepared by Sandwell Engineering Inc. and attached to this
prospectus as Exhibit A.
"Initial Purchaser" means Donaldson, Lufkin & Jenrette Securities
Corporation.
"Interest Account" means the account of such name created under the
Depositary Agreement.
"Interest Payment Date" means each December 15 and June 15, commencing
December 15, 1999, and concluding on the Final Maturity Date.
"Lien" means any mortgage, pledge, hypothecation, assignment, mandatory
deposit arrangement with any Person owning Indebtedness of such Person,
encumbrance, lien (statutory or other), preference, priority or other security
agreement of any kind or nature whatsoever which has the substantial effect of
constituting a security interest, including, without limitation, any
conditional sale or other title retention agreement, any financing lease having
substantially the same effect as any of the foregoing and the filing of any
financing statement or similar instrument under the Uniform Commercial Code or
comparable law of any jurisdiction, domestic or foreign.
"Loss Proceeds" means all net proceeds from an Event of Loss received by a
Coso partnership, including, without limitation, insurance proceeds or other
amounts actually received, except proceeds of delayed opening or business
interruption insurance, on account of an event which causes all or a
substantial portion of the relevant Coso project to be damaged, destroyed or
rendered unfit for normal use.
"Loss Proceeds Account" means the account of such name created under the
Depositary Agreement.
"Major Maintenance" means labor, materials and other direct expenses for any
overhaul of or major maintenance procedure for any Coso project (including
major maintenance such as turbine overhauls) which requires significant
disassembly or shutdown of the relevant Coso project pursuant to manufacturers'
guidelines or recommendations, engineering or operating considerations or the
requirements of any applicable legal requirement; provided that such expenses
are capitalized on the balance sheet of the relevant Coso partnership and not
expensed on the statement of operations of the relevant Coso partnership, all
in accordance with GAAP.
"Management Fees" means fees paid to the Partners or their representatives
pursuant to the partnership agreements of the Coso partnerships as determined
by the management committee of each of the Coso partnerships.
"Management Fees Account" means the Account of such name created under the
Depositary Agreement.
"Material Adverse Effect" means a material adverse effect on:
(1) our financial position or results of operation and that of the Coso
partnerships, taken as a whole;
(2) the Collateral or the validity or priority of the Liens on the
Collateral;
(3) our ability to perform our material obligations under the Indenture,
the senior secured notes or any of the Financing Documents to which we
are a party;
(4) the ability of the Trustee to enforce any of our payment obligations
under the Indenture or the senior secured notes; or
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(5) the ability of the Coso partnerships to perform any of their material
obligations under their respective Partnership Notes or the Financing
Documents to which they are a party.
"Moody's" means Moody's Investors Service, Inc., a corporation organized and
existing under the laws of the State of Delaware, its successors and assigns.
"Navy Contract" means the Original Service Contract N62474-79-C-5382, between
U. S. Naval Weapons Center and California Energy Company, Inc., as Contractor,
as amended and assigned.
"Navy I Partners" means ESCA LLC, a Delaware limited liability company, and
New CLOC Company, LLC, a Delaware limited liability company, the general
partners of the Navy I Partnership.
"Navy I Partnership" means Coso Finance Partners, a California general
partnership.
"Navy I Project" means the ownership, development and operation of the
turbine generators and associated geothermal resource wells operated by the
Navy I Partnership on a portion of the lands described in Exhibit A of the Navy
Contract; and the Navy I Partnership's ownership and operation of the 115kV
transmission line to the Edison substation at Inyokern, California.
"Navy II Partners" means Caithness Navy II Group, LLC., a Delaware limited
liability company, and New CTC Company, LLC, a Delaware limited liability
company, the general partners of the Navy II Partnership.
"Navy II Partnership" means Coso Power Developers, a California general
partnership.
"Navy II Project" means the ownership, development and operation of the
turbine generators and associated geothermal resource wells operated by the
Navy II Partnership on a portion of the lands described in Exhibit A of the
Navy Contract.
"Obligations" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"Operating and Maintenance Costs" means, for any periods, all amounts
disbursed by or on behalf of the Coso partnerships for operation, maintenance
(excluding, after the first Interest Payment Date, Capital Expenditures),
administration, repair, or improvement of their Coso projects, including,
without limitation, premiums on insurance policies, property and other taxes,
payments under the relevant operating and maintenance agreements, leases,
royalty and other land use agreements and fees, expenses and any other payments
required under the Project Documents (excluding the Operating and Maintenance
Fees and the Management Fees).
"Operating and Maintenance Fees" means fees payable to FPL Energy Operating
Services, Inc. and Coso Operating Company, LLC or any successor operators with
respect to the field and plant operations and maintenance agreements.
"Operating and Maintenance Fees Account" means the Account of such name
created under the Depositary Agreement.
"Operating Budget" means a budget of Operating and Maintenance Costs and
Capital Expenditures with respect to the Coso partnerships and the Coso
projects for any given fiscal year, or part thereof, and prepared in good faith
on the basis of estimated requirements, showing such costs by category for such
fiscal year.
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"Outstanding Notes" means, as of the time in question, all senior secured
notes authenticated and delivered under the Indenture, except (i) senior
secured notes theretofore canceled or required to be canceled under the
Indenture; (ii) senior secured notes for which provision for payment shall have
been made in accordance with the Indenture; and (iii) senior secured notes in
substitution for which other senior secured notes have been authenticated and
delivered pursuant to the Indenture.
"Partners" means, collectively, the Navy I Partners, the BLM Partners and the
Navy II Partners.
"Payment Date" means any Interest Payment Date or Principal Payment Date.
"Permitted Additional Senior Lender" shall mean a holder of any Permitted
Indebtedness of the Issuer (other than the senior secured notes and Permitted
Indebtedness described in clause (4) or (5) of the definition of Permitted
Indebtedness) or of any Permitted Partnership Indebtedness of any Coso
partnership described in clause (1) of the definition of Permitted Partnership
Indebtedness (other than Permitted Indebtedness described in clause (4) or (5)
of the definition of Permitted Indebtedness), or any agent, depositary,
collateral agent, security trustee or similar such party acting on behalf of
any such holder or holders.
"Permitted Indebtedness" means:
(1) the senior secured notes;
(2) Indebtedness incurred to finance the making of capital improvements to
the Coso projects required to maintain compliance with applicable law
or anticipated changes therein; provided that no such Indebtedness may
be incurred unless at the time of such incurrence (i) no Default or
Event of Default has occurred and is continuing, (ii) the Independent
Engineer confirms as reasonable a certification by us (containing
customary qualifications) that the proposed capital improvements are
reasonably expected to enable such Coso project to comply with
applicable or anticipated legal requirements, (iii) the calculations
demonstrate that, after giving effect to the incurrence of such
Indebtedness, our minimum projected Debt Service Coverage Ratio (x) for
the next four consecutive fiscal quarters, commencing with the quarter
in which such Indebtedness is incurred, taken as one annual period, and
(y) for each subsequent fiscal year through the Final Maturity Date,
will not be less than 1.25 to 1 and (iv) the Rating Agencies confirm
that the incurrence of such Indebtedness will not result in a Rating
Downgrade;
(3) Indebtedness incurred to finance the making of capital improvements to
the Projects not required by applicable law so long as after giving
effect to the incurrence of such Indebtedness (i) no Default or Event
of Default has occurred and is continuing, (ii) our calculations that
demonstrate that, after giving effect to the incurrence of such
Indebtedness, the minimum projected Debt Service Coverage Ratio (x) for
the next four consecutive fiscal quarters, commencing with the quarter
in which such Indebtedness is incurred, taken as one annual period, and
(y) for each subsequent fiscal year through the Final Maturity Date, in
each case will not be less than (A) 1.3 to 1 if the Indebtedness is on
or before December 30, 2001, or (B) 1.5 to 1 if the Indebtedness is
after December 30, 2001, and (iii) each of the Rating Agencies confirm
that the incurrence of such Indebtedness will not result in a Rating
Downgrade;
(4) (x) Subordinated Indebtedness accrued or incurred by BLM to Coso Land
Company constituting royalty payments pursuant to an agreement
regarding royalties between such parties as in effect on the closing
date of the Series A notes offering, (y) Subordinated
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Indebtedness (other than as specified in subclause (x) of this clause
(y) of this definition of Permitted Indebtedness) from Affiliates in an
amount not to exceed $20.0 million or (z) any other Subordinated
Indebtedness so long as each of the Rating Agencies confirm that the
incurrence of such Subordinated Indebtedness will not result in a Rating
Downgrade, and in the case of both (x) and (y), which amounts shall be
used to finance capital, operating or other costs with respect to the
Projects; provided that all payments of principal of, and premium, if
any, and interest on, any such Subordinated Indebtedness shall
constitute a Restricted Payment under the Indenture; and
(5) Indebtedness not otherwise described under clauses (1) through (4)
hereof incurred solely for working capital and operational needs of the
Coso projects which, when aggregated with the then outstanding
principal balance of Indebtedness of one or more of the Coso
partnerships permitted pursuant to clause (6) of the definition of
Permitted Partnership Indebtedness (but without duplication of
amounts), does not exceed $5.0 million at any time outstanding.
"Permitted Investments" means an Investment in any of the following:
(1) direct obligations of the Department of the Treasury of the United
States of America;
(2) obligations, representing full faith and credit of the United States of
America, of any of the following federal agencies: Export-Import Bank,
Farmers Home Administration, General Services Administration, U.S.
Maritime Administration, Small Business Administration, Government
National Mortgage Association (GNMA), U.S. Department of Housing &
Urban Development (PHA's) and Federal Housing Administration;
(3) obligations issued or fully guaranteed by any state of the United
States of America or any political subdivision of any such state or any
public instrumentality thereof and, at the time of the acquisition,
having one of the two highest ratings obtainable from either S&P or
Moody's;
(4) certificates of deposit and eurodollar time deposits, bankers'
acceptances and overnight bank deposits, in each case with any domestic
or foreign commercial bank having capital and surplus in excess of
$250.0 million;
(5) notes, bonds, collateralized mortgage obligations or other evidences of
indebtedness rated "AAA" by S&P and "Aaa" by Moody's issued by the
Federal Home Loan Bank, the Federal National Mortgage Association or
the Federal Home Loan Mortgage Corporation;
(6) commercial paper rated in any one of the two highest rating categories
by Moody's or S&P;
(7) investment agreements with banks (foreign and domestic),
broker/dealers, and other financial institutions rated at the time of
bid in any one of the three highest rating categories by Moody's and
S&P;
(8) repurchase agreements with banks (foreign and domestic),
broker/dealers, and other financial institutions rated at the time of
bid in any one of the three highest rating categories by Moody's and
S&P, provided, (a) collateral is limited to the securities specified in
clauses (1) through (5) above, (b) the margin levels for collateral
must be maintained at a minimum of 102% including principal and
interest, (c) the Trustee shall have a first perfected security
interest in the collateral, (d) the collateral will be delivered to a
third party custodian, designated by us, acting for the benefit of the
Trustee and all fees and expenses related to collateral custody will be
our responsibility, (e) the collateral must have been or will be
acquired at the market price and marked to market weekly and collateral
level shortfalls cured within 24 hours, (f) unlimited right of
substitution of collateral is allowed provided that substitution
collateral must be permitted collateral substituted at a current market
price and substitution fees of the custodian shall be paid by us;
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(9) asset-backed securities having the highest rating obtainable from
either S&P or Moody's;
(10) forward purchase agreements delivering securities specified in clauses
(1) and (6) above with banks (foreign and domestic), broker/dealers,
and other financial institutions maintaining a long-term rating on the
day of bid no lower than investment grade by both S&P and Moody's
(such rating may be at either the parent or subsidiary level); and
(11) money market funds rated "AAAm" or "AAAm-G" or better by S&P and other
financial funds investing exclusively in investments of the types
described in clauses (1) through this clause (11) of this definition.
"Permitted Lien" means, collectively:
(1) Liens to secure Indebtedness described in clauses (1), (2) and (3) of
the definition of Permitted Indebtedness and described in clauses (1),
(2), (3) and (4) of the definition of Permitted Partnership
Indebtedness;
(2) mechanic's, workmen's, materialmen's, supplier's, construction or other
like Liens arising in the ordinary course of business that, in each
case, have not become the subject of foreclosure or any other action or
proceeding;
(3) servitudes, easements, rights-of-way, restrictions, minor defects or
irregularities in title and such other encumbrances or charges against
real property or interests therein as are of a nature generally
existing with respect to properties of a similar character and which do
not in any material way interfere with the use thereof in the business
of the Coso partnerships; and
(4) other Liens incidental to the conduct of the Coso partnerships'
business or the ownership of properties and assets which were not
incurred in connection with the borrowing of money or the obtaining of
advances or credit (other than vendor's liens for accounts payable in
the ordinary course of business), and which do not in the aggregate
materially impair the use thereof in the operation of their business.
"Permitted Partnership Indebtedness" means:
(1) proceeds of Permitted Indebtedness loaned to any Coso partnerships by
us or, incurred by a Coso partnership;
(2) guarantees by one or more of the Coso partnerships of Permitted
Indebtedness;
(3) the Guarantees;
(4) the Partnership Notes;
(5) Indebtedness of one Coso partnership to another Coso partnership; and
(6) Indebtedness of one or more of the Coso partnerships not otherwise
described under clauses (1) through (5) hereof incurred solely for
working capital and operational needs of the Coso projects which, when
aggregated with the then outstanding principal balance of our
Indebtedness permitted pursuant to clause (5) of the definition of
Permitted Indebtedness (but without duplication of amounts), does not
exceed $5.0 million at any time outstanding.
"Permitted Power Contract Buy-Out" means the termination of a Power Purchase
Agreement or the negotiated reduction of capacity and/or energy or the rates
related thereto to be sold under a Power Purchase Agreement other than pursuant
to such agreement's terms and the payment by Southern California Edison made in
connection therewith.
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<PAGE>
"Person" means any individual, sole proprietorship, corporation, partnership,
joint venture, limited liability partnership, limited liability corporation,
trust, unincorporated association, institution, Governmental Authority or any
other entity.
"Principal Account" means the Account of such name created under the
Depositary Agreement.
"Principal Payment Date" when used with respect to any senior secured note
means the date on which all or a portion of the principal of such senior
secured note becomes due and payable as provided therein or in the Indenture,
whether on a scheduled date for payment of principal at a Redemption Date, the
Final Maturity Date, a date of declaration of acceleration, or otherwise.
"Project Documents" means, individually and collectively, all material
existing agreements and documents which relate to all or any portion of one or
more of the Coso projects.
"Rating" means the rating of the senior secured notes by the Rating Agencies.
"Rating Agency" means any of Moody's, S&P and Duff & Phelps.
"Rating Downgrade" means a lowering by the Rating Agencies of the then
current credit ratings of the senior secured notes.
"Redemption Account" means the account of such name created under the
Depositary Agreement.
"Redemption Date" means the date on which we redeem or shall redeem any
senior secured notes in accordance with the Indenture.
"Reference Treasury Dealer" means any nationally recognized primary U.S.
government securities dealer in New York City selected by us.
"Reference Treasury Dealer Quotations" means, with respect to each Reference
Treasury Dealer and any date of redemption, the average, as determined by the
Trustee, of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) quoted in
writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m. on the
third business day preceding such date of redemption.
"Remaining Average Life" means, with respect to any Series A notes due 2009
and Series B notes due 2009, the principal of which is to be redeemed (the
"Called Principal"), the number of years (calculated to the nearest one-twelfth
year) obtained by dividing:
(1) such Called Principal into
(2) the sum of the products obtained by multiplying:
(a) the principal component of each Remaining Scheduled Payment (as
defined below) with respect to such Called Principal by
(b) the number of years (calculated to the nearest one-twelfth year)
that will elapse between the date on which such Called Principal is
to be redeemed (the "Settlement Date") and the scheduled due date
of such Remaining Scheduled Payment.
For purposes of this definition, the term "Remaining Scheduled Payments" means,
with respect to the Called Principal of any Series A notes due 2009 and Series
B notes due 2009, all payments of
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<PAGE>
such Called Principal and interest thereon that would be due after the
Settlement Date with respect to such Called Principal if no payment of such
Called Principal were made prior to its scheduled due date.
"Required Holders" means, at any time, Persons that at such time hold at
least a majority in aggregate principal amount of the Outstanding Notes.
"Responsible Officer" means, with respect to knowledge of any default under
the Indenture or the Credit Agreement, the chief executive officer, president,
chief financial officer, general counsel, principal accounting officer,
treasurer, or any vice president of ours or a Coso partnership, as applicable,
or other officer of such corporation who in the normal performance of his or
her operational duties would have knowledge of the subject matter relating to
such default.
"Restricted Payment" means, with respect to any Person:
(1) the declaration and payment of distributions or dividends, the issuance
of Equity Interests in such Person or any other payment in respect of
any Equity Interests made in cash, property, obligations or other
notes;
(2) any payment of the principal of or interest on any Subordinated
Indebtedness;
(3) the making of any loans or advances to any Affiliate (other than
Permitted Indebtedness);
provided, however, that "Restricted Payment" shall not include payments under
any of the Project Documents for services rendered.
"Revenue Account" means the account of such name created under the Depositary
Agreement.
"S&P" means Standard & Poor's Rating Group Corporation, a corporation
organized and existing under the laws of the State of New York, its successors
and assigns.
"Secured Parties" means the Trustee, the Collateral Agent, the Depositary,
any Permitted Additional Senior Lender or any other Person that becomes a
Secured Party under any Financing Document.
"Security Agreements" means (1) that certain Security Agreement dated as of
May 28, 1999, executed by the Navy I Partnership in favor of the Collateral
Agent, (2) that certain Security Agreement dated as of May 28, 1999, executed
by the BLM Partnership in favor of the Collateral Agent and (3) that certain
Security Agreement dated as of May 28, 1999, executed by the Navy II
Partnership in favor of the Collateral Agent.
"Security Documents" means, collectively, the Depositary Agreement, the Deeds
of Trust, the Security Agreements, the Pledge Agreements and any other document
providing for any lien, pledge, encumbrance, mortgage or security interest on
(i) any or all of our assets or any or all of the assets of the Coso
partnerships or the ownership interests in the Issuer or the Coso partnerships
or (ii) the assets constituting or related to the Projects.
"Senior Indebtedness" means all of the Permitted Indebtedness of Issuer and
the Coso partnerships other than the Subordinated Indebtedness.
"Subordinated Indebtedness" means Indebtedness (and the note or other
instrument evidencing the same) which has been subordinated, on terms and
conditions substantially the same as those permitted under the Indenture, to
the prior payment of amounts owing under the Indenture and the senior secured
notes and the repayment of which shall be made only from Restricted Payments.
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"Title Event" means the existence of any defect of title or lien or
encumbrance on a Coso project (other than certain permitted liens) in effect on
the closing date of the Series A notes offering that entitles the Collateral
Agent to make a claim under the policy or policies of title insurance required
pursuant to the Financing Documents.
"Title Event Proceeds" means all amounts and proceeds (including instruments)
in respect of any Title Event.
"Transaction Documents" means the Project Documents and the Financing
Documents.
"Treasury Rate" means, with respect to any date of redemption, the rate per
annum equal to the semi-annual equivalent yield to maturity of the Comparable
Treasury Issue, assuming a price for the Comparable Treasury Issue (expressed
as a percentage of its principal amount) equal to the Comparable Treasury Price
for such date of redemption.
"Trustee" means the party named as such above until a successor replaces it
in accordance with the applicable provisions of this Indenture and thereafter
means the successor serving hereunder.
"Voting Stock" of any Person as of any date means the Capital Stock of such
Person that is at the time entitled to vote in the election of the Board of
Directors or otherwise entitled to vote in the determination of the management
of such Person.
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<PAGE>
MATERIAL FEDERAL INCOME TAX CONSEQUENCES
OF THE EXCHANGE OFFER
The exchange of Series A notes for Series B notes pursuant to the exchange
offer should not be treated as a taxable transaction for U.S. federal income
tax purposes because the Series B notes will not be considered to differ
materially from the Series A notes. Rather, any Series B notes you receive
should be treated as a continuation of your investment in the Series A notes.
As a result, you should bear no material U.S. federal income tax consequences
due to the exchange, and you should have the same adjusted issue price,
adjusted basis and holding period in the Series B notes as you had in the
Series A notes immediately prior to the exchange.
You should consult your own tax advisor concerning the consequences of your
exchange of Series A notes for Series B notes, including the tax consequences
under, state, local, foreign or other tax laws, and the possible effects on you
of changes in U.S. federal or other tax laws.
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<PAGE>
PLAN OF DISTRIBUTION
Each broker-dealer that receives Series B notes for its own account as a
result of this exchange offer, sometimes referred to a as participating broker,
must acknowledge that it will deliver a prospectus in connection with any
resale of such Series B notes. This prospectus, as it may be periodically
amended or supplemented, may be used by a participating broker in connection
with any resale of the Series B notes received in exchange for Series A notes
where the Series A notes were acquired as a result of market-making activities
or other trading activities. For a period of 180 days from the completion of
the exchange offer, or a shorter period if all Series B notes have been
disposed of by the participating brokers, we will make this prospectus, as
amended or supplemented, available to any participating broker for use in
connection with the resale of the Series B notes. Until this period ends, we
will send a reasonable number of additional copies of this prospectus and any
amendment or supplement to this prospectus to any participating broker that
requests such documents in the letter of transmittal.
We will not receive any proceeds from the sale of Series B notes by broker-
dealers. Series B notes received by any participating broker may be sold
periodically, in one or more transactions in the over-the-counter market, in
negotiated transactions, through the writing of options on the Series B notes,
or a combination of such methods of resale provided that the Series B notes are
sold at market prices prevailing at the time of resale, at prices related to
such market prices or negotiated prices. Any resale of Series B notes may be
made directly to purchasers or to or through broker-dealers who may receive
compensation in the form of commissions or concessions from a broker-dealer
and/or purchasers of the Series B notes. Any participating broker that resells
the Series B notes that were received by it for its own account pursuant to
this exchange offer and any broker dealer that participates in the distribution
of Series B notes may be deemed to be an underwriter within the meaning of the
Securities Act. Any profit on the resale of Series B notes and any commissions
or concessions received by any such persons may be deemed to be underwriting
compensation under the Securities Act. The letter of transmittal states that by
acknowledging that it will deliver, and by delivering a prospectus as required,
a participating broker will not be deemed to admit that it is an underwriter
within the meaning of the Securities Act.
We will pay all the expenses incident to this exchange offer, which shall not
include the expense of any holder in connection with resales of the Series B
notes. We have agreed to indemnify holders of the Series B notes, including
participating brokers, against certain liabilities, including liabilities under
the Securities Act.
LEGAL MATTERS
Reed Smith Shaw & McClay LLP will opine on the validity of the Series B notes
for us, and, together with Riordan & McKinzie, A Professional Law Corporation,
will opine on the validity of the Guarantees for the Coso partnerships.
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CHANGE IN INDEPENDENT ACCOUNTANTS
Since 1991, Caithness Energy and CalEnergy, the two former co-sponsors of the
Coso projects, had engaged PricewaterhouseCoopers LLP to audit the financial
statements of the Coso partnerships. On February 25, 1999, Caithness
Acquisition, Caithness Energy's wholly owned subsidiary, purchased all of
CalEnergy's interests in the Coso projects, and Caithness Energy engaged KPMG
LLP, its own independent certified public accountants, to audit the financial
statements of the Coso partnerships in the future, rather than to continue to
have PricewaterhouseCoopers LLP audit those financial statements. In connection
with the audits of the financial statements of Coso Finance Partners and Coso
Finance Partners II, Coso Energy Developers and Coso Power Developers for each
of the two years in the period ended December 31, 1998 and through February 25,
1999, (i) Caithness Energy had no disagreements with PricewaterhouseCoopers LLP
on any matter of accounting principles or practices, financial statement
disclosure or auditing scope or procedure, which disagreements if not resolved
to the satisfaction of PricewaterhouseCoopers LLP would have caused them to
make reference thereto in their reports on the financial statements for such
years, and (ii) the reports of PricewaterhouseCoopers LLP on the Coso
partnerships did not contain any adverse opinion or disclaimer of opinion, and
were not modified as to uncertainty, audit scope or accounting principles
except for the reference to the Coso partnerships' adoption in 1998 of
Statement of Position No. 98-5, "Reporting on the Costs of Start-up
Activities."
EXPERTS
The balance sheet of Caithness Coso Funding Corp. as of April 22, 1999, has
been included herein and in this prospectus in reliance upon the report of KPMG
LLP, independent certified public accountants, appearing elsewhere herein, and
upon the authority of said firm as experts in accounting and auditing.
The combining and combined financial statements of Coso Finance Partners and
Coso Finance Partners II and the financial statements of Coso Energy Developers
and Coso Power Developers as of December 31, 1998 and 1997 and for each of the
three years in the period ended December 31, 1998, included in this prospectus,
have been included in reliance on the reports of PricewaterhouseCoopers LLP,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
Sandwell Engineering Inc. has prepared the independent engineer's report
dated May 20, 1999, appearing in Exhibit A to this prospectus. The independent
engineer's report was prepared in connection with the Series A notes offering
and has not been updated since then. You should read the independent engineer's
report in its entirety for additional information about the Coso projects and
the other matters addressed in it. We included the independent engineer's
report in this prospectus in reliance on the conclusions expressed therein by
Sandwell Engineering Inc. and upon that firm's experience in preparing
independent engineer's reports for independent power projects.
Henwood Energy Services, Inc. has prepared the energy markets consultant's
report dated May 20, 1999 appearing in Exhibit B to this prospectus. The energy
markets consultant's report was prepared in connection with the Series A notes
offering and has not been updated since then. You should read the energy
markets consultant's report in its entirety for additional information about
certain industry and regulatory matters affecting the sales of electricity by
the Coso projects and the related matters addressed in it. We included the
energy markets consultant's report in this prospectus in reliance on the
conclusions expressed therein by Henwood Energy Services, Inc. and upon that
firm's experience in providing business advisory and other services and market
forecasts in electricity and gas to international firms and public authorities.
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GeothermEx, Inc. has prepared the geothermal consultant's report dated May
1999, appearing in Exhibit C to this prospectus. The geothermal consultant's
report was prepared in connection with the Series A notes offering and has not
been updated since then. You should read the geothermal consultant's report in
its entirety for additional information about the sufficiency of the geothermal
resources available for use and for conversion to electrical power and the
related matters addressed in it. As we indicated above, we have omitted from
Exhibit C of this prospectus Appendices A through F of the geothermal
consultant's report. Appendices A through F include the production histories
for Navy I, BLM and Navy II production wells and the injection histories for
Navy I, BLM and Navy II injection wells. You can obtain copies of Appendices A
through F of the geothermal consultant's report from us upon request. See
"Available Information."
We included the geothermal consultant's report in this prospectus in reliance
on the conclusions expressed therein by GeothermEx, Inc. and upon that firm's
experience in preparing consultant's reports for geothermal projects.
AVAILABLE INFORMATION
Upon effectiveness of the registration statement of which this prospectus is
a part, we and the Coso partnerships will be subject to the informational
requirements of the Securities Exchange Act, and in accordance therewith we
file reports, proxy and information statements and other information with the
SEC. You can inspect and copy these reports, proxy and information statements
and other information at:
. the public reference facilities maintained by the commission at 450
Fifth Street, N.W., Washington, DC 20549, and
. the regional offices of the SEC located at:
. 500 West Madison Street, Room 1400, Chicago, Illinois 60606, and
. 7 World Trade Center, 13th Floor, New York, New York 10048.
You also can obtain copies of these materials from the public reference
section of the commission at 450 Fifth Street, N.W., Washington, DC 20549 at
prescribed rates. You can obtain electronic filings made through the electronic
data gathering, analysis and retrieval system at the SEC's web site,
http://www.sec.gov.
Whether or not required by the rules and regulations of the SEC, so long as
any Series B notes are outstanding, we will furnish to the holders of Series B
notes, within the time periods specified in the SEC's rules and regulations:
. all quarterly and annual financial information that would be required to
be contained in a filing with the SEC on Forms 10-Q and 10-K if we were
required to file such forms, including a "Management's Discussion and
Analysis of Financial Condition and Results of Operation" and, with
respect to the annual information only, a report thereon by our and the
Coso partnerships' certified independent accountants; and
. all current reports that would be required to be filed with the SEC on
Form 8-K if we were required to file such reports.
In addition, we have agreed that, for so long as any senior secured notes
remain outstanding, we will furnish to the holders and to securities analysts
and prospective investors, upon their request, the information required to be
delivered pursuant to Rule 144A(d)(4) under the Securities Act.
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INDEX TO FINANCIAL STATEMENTS
<TABLE>
<S> <C>
Caithness Coso Funding Corp.
Independent Auditor's Report............................................. F-3
Balance sheet as of April 22, 1999....................................... F-4
Note to balance sheet.................................................... F-5
Coso Finance Partners and Coso Finance Partners II--Combining and Combined
Financial Statements
Report of independent accountants........................................ F-6
Combining and combined balance sheets at December 31, 1997 and 1998...... F-7
Combining and combined statements of operations for each of the three
years in the period ended December 31, 1998............................. F-8
Combining and combined statements of partners' capital for each of the
three years in the period ended December 31, 1998....................... F-9
Combining and combined statements of cash flows for each of the three
years in the period ended December 31, 1998............................. F-10
Notes to combining and combined financial statements..................... F-11
Coso Energy Developers--Financial Statements
Report of independent accountants........................................ F-19
Balance sheets at December 31, 1997 and 1998............................. F-20
Statements of operations for each of the three years in the period ended
December 31, 1998....................................................... F-21
Statements of partners' capital for each of the three years in the period
ended December 31, 1998................................................. F-22
Statements of cash flows for each of the three years in the period ended
December 31, 1998....................................................... F-23
Notes to financial statements............................................ F-24
Coso Power Developers--Financial Statements
Report of independent accountants........................................ F-32
Balance sheets at December 31, 1997 and 1998............................. F-33
Statements of operations for each of the three years in the period ended
December 31, 1998....................................................... F-34
Statements of partners' capital for each of the three years in the period
ended December 31, 1998................................................. F-35
Statements of cash flows for each of the three years in the period ended
December 31, 1998....................................................... F-36
Notes to financial statements............................................ F-37
Caithness Coso Funding Corp.
Unaudited condensed balance sheet as of June 30, 1999.................... F-44
Unaudited condensed statement of operations for the period ending June
30, 1999................................................................ F-45
Unaudited condensed statement of cash flows for the period ending June
30, 1999................................................................ F-46
Notes to the unaudited condensed financial statements.................... F-47
Coso Finance Partners and Coso Finance Partners II
Unaudited condensed balance sheets at December 31, 1998 and June 30,
1999.................................................................... F-48
Unaudited condensed statements of operations for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ...................... ...................... F-49
Unaudited condensed statements of cash flows for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ............................................. F-50
Notes to the unaudited condensed financial statements.................... F-51
</TABLE>
F-1
<PAGE>
<TABLE>
<S> <C>
Coso Energy Developers
Unaudited condensed balance sheets at December 31, 1998 and June 30,
1999.................................................................... F-53
Unaudited condensed statements of operations for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ...................... ...................... F-54
Unaudited condensed statements of cash flows for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ............................................. F-55
Notes to the unaudited condensed financial statements.................... F-56
Coso Power Developers
Unaudited condensed balance sheets at December 31, 1998 and June 30,
1999.................................................................... F-58
Unaudited condensed statements of operations for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ............................................. F-59
Unaudited condensed statements of cash flows for the six months ended
June 30, 1998, the two months ended February 28, 1999 and the four
months ended June 30, 1999 ...................... ...................... F-60
Notes to the unaudited condensed financial statements.................... F-61
</TABLE>
F-2
<PAGE>
INDEPENDENT AUDITOR'S REPORT
The Board of Directors
Caithness Coso Funding Corp.:
We have audited the accompanying balance sheet of Caithness Coso Funding
Corp. as of April 22, 1999. This balance sheet is the responsibility of the
Company's management. Our responsibility is to express an opinion on this
balance sheet based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the balance sheet is free of material
misstatement. An audit of a balance sheet includes examining, on a test basis,
evidence supporting the amounts and disclosures in that balance sheet. An audit
of a balance sheet also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
balance sheet presentation. We believe that our audit of the balance sheet
provides a reasonable basis for our opinion.
In our opinion, the balance sheet referred to above presents fairly, in all
material respects, the financial position of Caithness Coso Funding Corp. as of
April 22, 1999, in conformity with generally accepted accounting principles.
KPMG LLP
New York, NY
April 23, 1999
F-3
<PAGE>
CAITHNESS COSO FUNDING CORP.
BALANCE SHEET
AS OF APRIL 22, 1999
<TABLE>
<S> <C>
Current asset:
Cash................................................................. $ 3
===
Stockholder's equity:
Common stock ($0.01 par value; 1,000 shares authorized; 300 issued
and outstanding).................................................... $ 3
Additional paid-in capital........................................... --
---
Total stockholders' equity............................................. $ 3
===
</TABLE>
See accompanying note to balance sheet.
F-4
<PAGE>
CAITHNESS COSO FUNDING CORP.
NOTE TO BALANCE SHEET
APRIL 22, 1999
(1) General
Caithness Coso Funding Corp. (Funding Corp.) was incorporated on April 22,
1999, in Delaware. Funding Corp. is a special purpose corporation that has been
recently formed for the purpose of issuing senior secured notes on behalf of
Coso Finance Partners, Coso Energy Developers and Coso Power Developers (the
Coso partnerships), affiliates of Funding Corp. If Funding Corp. completes the
offering of the senior secured notes, Funding Corp. will loan all of the
proceeds from the offering to the Coso partnerships, and the Coso partnerships
will guarantee, on a senior secured basis, repayment of the senior secured
notes.
Funding Corp. has no material assets other than the loans that will be made
to the Coso partnerships. Also, Funding Corp. does not conduct any business,
other than issuing the senior secured notes and making the loans to the Coso
partnerships.
F-5
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Finance Partners
and Coso Finance Partners II
In our opinion, the accompanying combining and combined balance sheets and
the related combining and combined statements of operations, of partners'
capital and of cash flows present fairly, in all material respects, the
combining and combined financial position of Coso Finance Partners and Coso
Finance Partners II at December 31, 1997 and 1998, and the combining and
combined results of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Partnerships' management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the combining and combined financial statements,
the Partnerships adopted in 1998 Statement of Position No. 98-5, "Reporting on
the Costs of Start-Up Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-6
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31, 1998
------------------------------------------
December 31, Coso Coso
1997 Finance Finance
Combined Partners Partners II Eliminations Combined
<S> <C> <C> <C> <C> <C>
Assets
Cash.................... $ 2,888 $ -- $ -- $ -- $ --
Restricted cash and
investments (Note 5)... 6,479 7,524 -- -- 7,524
Accounts receivable..... 4,234 5,404 -- -- 5,404
Prepaid expenses and
other assets........... 863 426 -- -- 426
Amounts due from related
parties, net (Note 7).. 4,211 3,782 8,748 (8,748) 3,782
Property, plant and
equipment, net (Note
4)..................... 186,392 180,380 -- -- 180,380
Transfer to related
party (Note 1)......... -- -- 11,995 (11,995) --
Advances to China Lake
Plant Services, Inc.... 3,967 4,139 -- -- 4,139
Deferred financing
costs, net............. 356 233 -- -- 233
-------- -------- ------- -------- --------
$209,390 $201,888 $20,743 $(20,743) $201,888
======== ======== ======= ======== ========
Liabilities and
Partners' Capital
Accounts payable and
accrued liabilities.... $ 793 $ 2,581 $ -- $ -- $ 2,581
Navy sinking fund and
royalties payable
(Note 5)............... $ 7,363 8,808 -- -- 8,808
Amounts due to related
parties (Note 7)....... -- 8,748 -- (8,748) --
Transfer from related
party (Note 1)......... -- 11,995 -- (11,995) --
Project loan (Note 6)... 45,666 40,566 -- -- 40,566
-------- -------- ------- -------- --------
53,822 72,698 -- (20,743) 51,955
Partners' capital....... 155,568 129,190 20,743 -- 149,933
-------- -------- ------- -------- --------
$209,390 $201,888 $20,743 $(20,743) $201,888
======== ======== ======= ======== ========
</TABLE>
The accompanying notes are an integral part of the combining and combined
financial statements.
F-7
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years
ended December For the year ended December 31, 1998
31, -------------------------------------------
----------------- Coso Coso
1996 1997 Finance Finance
Combined Combined Partners Partners II Eliminations Combined
<S> <C> <C> <C> <C> <C> <C>
Revenue
Sales of electricity.... $118,206 $100,431 $53,153 $ -- $ -- $53,153
Royalty................. -- -- -- 493 (493) --
Interest income......... 3,286 1,980 585 -- -- 585
-------- -------- ------- ----- ----- -------
121,492 102,411 53,738 493 (493) 53,738
-------- -------- ------- ----- ----- -------
Expenses
Plant operations (Note
7)..................... 11,763 11,329 13,298 -- -- 13,298
Royalty expense (Note
5)..................... 11,059 9,849 7,317 -- (493) 6,824
Depreciation and
amortization........... 13,325 12,814 11,124 648 -- 11,772
Interest expense........ 8,868 6,260 4,333 -- -- 4,333
-------- -------- ------- ----- ----- -------
45,015 40,252 36,072 648 (493) 36,227
-------- -------- ------- ----- ----- -------
Income (loss) before
cumulative effect of
accounting change...... 76,477 62,159 17,666 (155) -- 17,511
Cumulative effect of
accounting change (Note -- -- (923) -- -- (923)
2)..................... -------- -------- ------- ----- ----- -------
Net income (loss)....... $ 76,477 $ 62,159 $16,743 $(155) $ -- $16,588
======== ======== ======= ===== ===== =======
</TABLE>
The accompanying notes are an integral part of the combining and combined
financial statements.
F-8
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
<TABLE>
<CAPTION>
Coso Finance Partners Coso Finance Partners II
---------------------------------- ---------------------------------
China Lake
ESCA China Lake ESCA II Geothermal
Limited Operating Limited Management
Partnership Company, Inc. Total Partnership Company, Inc. Total Combined
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1995................... $ 74,985 $ 69,251 $144,236 $11,000 $9,345 $20,345 $164,581
Net income.............. 40,790 35,311 76,101 202 174 376 76,477
Distributions to
partners(1)............ (39,249) (33,975) (73,224) -- -- -- (73,224)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1996................... 76,526 70,587 147,113 11,202 9,519 20,721 167,834
Net income.............. 33,222 28,760 61,982 95 82 177 62,159
Distributions to
partners(1)............ (39,892) (34,533) (74,425) -- -- -- (74,425)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1997................... 69,856 64,814 134,670 11,297 9,601 20,898 155,568
Net income (loss)....... 8,974 7,769 16,743 (83) (72) (155) 16,588
Distributions to
partners............... (11,912) (10,311) (22,223) -- -- -- (22,223)
-------- -------- -------- ------- ------ ------- --------
Balance at December 31,
1998................... $ 66,918 $ 62,272 $129,190 $11,214 $9,529 $20,743 $149,933
======== ======== ======== ======= ====== ======= ========
</TABLE>
- ---------------------
(1) Distributions of $14,394 to ESCA Limited Partnership and $12,461 to China
Lake Operating Company, Inc. were declared and paid on January 2, 1996.
Distributions of $16,761 to ESCA Limited Partnership and $14,509 to China
Lake Operating Company, Inc. were declared on December 31, 1996 and paid
on December 31, 1996 and January 2, 1997, respectively.
The accompanying notes are in integral part of the combining and combined
financial statements.
F-9
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
COMBINING AND COMBINED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years ended
December 31, For the year ended December 31, 1998
-------------------- -------------------------------------------
Coso
1996 1997 Finance Coso Finance
Combined Combined Partners Partners II Combined
<S> <C> <C> <C> <C> <C>
Cash flows from
operating activities
Net income............. $ 76,477 $ 62,159 $ 16,743 $ (155) $ 16,588
Adjustments to
reconcile net income
to net cash flows from
operating activities:
Depreciation and
amortization........ 13,325 12,814 11,124 648 11,772
Amortization of
deferred financing
costs............... 287 190 123 -- 123
Cumulative effect of
accounting change... -- -- 923 -- 923
Additional advances
to China Lake Plant
Services, Inc....... (201) (239) (172) -- (172)
Decrease (increase)
in accounts
receivable.......... (679) 13,987 (1,170) -- (1,170)
Decrease (increase)
in prepaid expenses
and other assets.... (738) 476 437 -- 437
Increase (decrease)
in accounts payable
and accrued
liabilities......... (3,705) 2,346 3,233 -- 3,233
Decrease (increase)
in amounts due from
related parties,
net................. (987) (3,193) 922 (493) 429
--------- --------- ------------- ---------- -------------
Net cash flows from
operating
activities........ 83,779 88,540 32,163 -- 32,163
--------- --------- ------------- ---------- -------------
Cash flows from
investing activities
Additions to power
plant and transmission
line.................. (499) (736) (266) -- (266)
Additions to wells and
resource development
costs................. (1,795) (3,853) (6,417) -- (6,417)
Decrease (increase) in
restricted cash....... (855) 22,537 (1,045) -- (1,045)
--------- --------- ------------- ---------- -------------
Net cash flows from
investing
activities........ (3,149) 17,948 (7,728) -- (7,728)
--------- --------- ------------- ---------- -------------
Cash flows from
financing activities
Distributions to
partners.............. (58,715) (88,934) (22,223) -- (22,223)
Repayment of project
financing loans....... (51,284) (30,390) (5,100) -- (5,100)
--------- --------- ------------- ---------- -------------
Net cash flows from
financing
activities........ (109,999) (119,324) (27,323) -- (27,323)
--------- --------- ------------- ---------- -------------
Net change in cash..... (29,369) (12,836) (2,888) -- (2,888)
Cash at beginning of
year.................. 45,093 15,724 2,888 -- 2,888
--------- --------- ------------- ---------- -------------
Cash at end of year.... $ 15,724 $ 2,888 $ -- $ -- $ --
========= ========= ============= ========== =============
Supplemental cash flow
disclosure
Interest paid.......... $ 13,849 $ 6,070 $ 4,210 $ -- $ 4,210
</TABLE>
The accompanying notes are an integral part of the combining and combined
financial statements.
F-10
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Finance Partners and Coso Finance
Partners II
Coso Finance Partners (CFP or the Partnership) and Coso Finance Partners II
(CFP II) were formed on July 7, 1987, in connection with refinancing the
construction of a 30 net megawatt (NMW) geothermal power plant constructed on
behalf of China Lake Joint Venture (CLJV) on land at the China Lake Naval Air
Weapons Station, Coso Hot Springs, China Lake, California, and financing the
expansion of that power plant from 30 net megawatt (NMW) to approximately
80NMW. CFP and CFP II (collectively, the Partnerships) are general partnerships
between China Lake Operating Company (CLOC), a Delaware corporation, and ESCA
Limited Partnership (ESCA), and China Lake Geothermal Management Company
(CLGMC), a Delaware corporation, and ESCA II Limited Partnership (ESCA II),
respectively. ESCA is a California limited partnership between Caithness
Geothermal 1980, Ltd., Caithness Power, L.L.C., and ESI Geothermal, Inc. (a
subsidiary of FPL Group, Inc.). ESCA II is a California limited partnership
between Caithness Geothermal 1980, Ltd., Mojave Power II, Inc. and ESI
Geothermal II, Inc. (a subsidiary of FPL Group, Inc.).
CFP was formed to acquire the assets and assume the liabilities of CLJV
insofar as they related to the first turbine generator set of the power plant
and the related geothermal resources. CFP II acquired the assets and assumed
the liabilities of CLJV insofar as they related to the second and third turbine
generator sets together with the related geothermal resources. The three
turbine generators that comprise the power plant have the capacity to produce
an aggregate of approximately 80NMW. CFP and CFP II were formed as separate
entities in order to facilitate bank financing of the completed power plant and
power plants under construction, respectively. In 1988, CFP II assigned its
assets and liabilities to CFP in exchange for a royalty of 5% of the value of
the steam produced. The "Transfer to/from related party" in the combined and
individual balance sheets represents the unamortized book value of development
costs incurred by CFP II. Such amounts are being amortized by both parties over
30 years on a straight line basis.
The Partnerships sell all electricity produced to Southern California Edison
(Edison) under a 24-year power purchase contract expiring in 2011. Under the
terms of this contract, Edison makes payments to CFP as follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). After the scheduled
energy price period for each unit, the energy payment adjusts to the
actual avoided energy cost experienced by Edison. In August 1997, the
initial unit of the Partnerships completed the ten-year period. At that
time, Edison ceased paying the scheduled energy rates for all three
units. CFP is currently in litigation over this issue (see Note 8). For
the years ended December 31, 1997 and 1998, Edison's average avoided cost
of energy was 3.28 and 2.95 cents per kwh, respectively. Estimates of
Edison's future avoided cost of energy vary substantially from year to
year. The Partnerships cannot predict the likely level of avoided cost of
energy prices under the 24-year power purchase contract and, accordingly,
the revenues generated by the Partnerships could fluctuate significantly;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997 and 1998, the
bonus payments aggregated $2,266, $1,805 and $1,510, respectively.
F-11
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
CalEnergy Company, Inc. (CalEnergy) served as the operator, maintaining the
Partnerships' accounting records and operating the CFP plant on a day-to-day
basis, until February 1, 1999 when Coso Operating Company LLC (COC), a Delaware
limited liability company, became operator pursuant to certain operations and
maintenance agreements with CLOC, the managing general partner (see Note 9).
COC and CLOC are wholly-owned subsidiaries of CalEnergy.
At formation, and as amended, the terms of the partnership agreements
provided that distributable cash flow before "payout" was allocated 10% to CLOC
as managing partner and 90% in proportion to the remaining sums necessary to be
distributed to each partner to achieve payout. "Payout" occurred in June 1996
and was defined as the point at which each partner had received aggregate cash
distributions from the 90% allocation in amounts equal to their accumulated
cash contributions plus amounts equal to 10% simple interest on the cash
contributions. For purposes of allocating net income to partners' capital
accounts, profits and losses are allocated based on the aforementioned
percentages. For income tax purposes, certain deductions and credits are
subject to special allocations as defined in the partnership agreements. Cash
flow after "payout" is allocated 53.6% and 46.4% to ESCA/ESCA II and
CLOC/CLGMC, respectively.
Since the Partnerships operate under common ownership and management control,
the financial statements of the Partnerships have been combined after
elimination of intercompany amounts.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue was recognized based on the payment
rates scheduled in CFP's power purchase contract with Edison until August 1997.
After August 1997, revenue is recognized based on Edison's avoided energy cost.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the operating power plant and transmission line is computed
on the straight line method over their estimated useful life of 30 years and,
for significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
The Partnerships review long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
F-12
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-Up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CFP adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CFP. The cumulative effect of the change in
accounting principle was $923.
Wells and Resource Development Costs
The Partnerships follow the full cost method of accounting for costs incurred
in connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs, the cost of drilling and equipping
production wells, and administrative and interest costs directly attributable
to the project, are capitalized and amortized over their estimated useful lives
when production commences. The estimated useful lives of production wells are
ten years each; exploration costs and development costs, other than production
wells, are amortized over 30 years and, for significant additions, the
remainder of the 30-year life from the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $57 and $9 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $296 and $109 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three to four years from the
point of completion.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CFP and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CFP's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CFP is valued at the
lower of cost or market.
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,795 and $1,918, respectively.
F-13
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
Restricted Cash and Investments
As of December 31, 1997 and 1998, all of the Partnerships' investments were
classified as held-to-maturity and reported at amortized cost. The restricted
cash and investments balance represents primarily a sinking fund related to a
lump sum royalty payment of $25,000 to be paid to the Navy in 2009 (see Note
5). This account is comprised of various mortgage-backed securities with
maturities ranging from 1999 through 2005. The carrying amount of restricted
cash and investments at December 31, 1997 and 1998 approximated fair value,
which is based on quoted market prices as provided by the financial institution
which holds the investments. Also included in restricted cash are various Bank
of America certificates of deposits totaling $142 at both December 31, 1997 and
1998. These deposits have maturities of greater than three months.
Cash Flows
For purposes of the combined statements of cash flows, the Partnerships
consider all money market instruments purchased with an initial maturity of
three months or less to be cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CFP entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 6), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CFP made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $50 (payable to CFP), which
approximated its fair value. The fair value was based on the estimated amount
that CFP would have received to terminate the swap agreement at that date as
provided by the financial institution which was the counterparty to the swap.
F-14
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
<TABLE>
<CAPTION>
December 31,
--------------------
1997 1998
<S> <C> <C>
Power plant and gathering system..................... $ 175,024 $ 173,927
Transmission line.................................... 6,515 6,515
Wells and resource development costs................. 112,057 118,474
--------- ---------
293,596 298,916
Less accumulated amortization and depreciation....... (107,204) (118,536)
--------- ---------
$ 186,392 $ 180,380
========= =========
</TABLE>
5. Royalty Expense
Royalty expense is summarized as follows:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
Unit 1............................................... $ 3,269 $3,437 $3,114
Units 2 and 3........................................ 7,790 6,412 3,710
------- ------ ------
$11,059 $9,849 $6,824
======= ====== ======
</TABLE>
The power plant is located on land owned by the U.S. Navy. Under the terms of
a 30-year contract with the U.S. Navy to develop geothermal energy on its
lands, for the first turbine only, CFP pays the Navy's monthly Edison bill for
specified quantities of electricity and, in return, is reimbursed at a set rate
for such quantities of electricity. During 1996, 1997 and 1998, CFP was
reimbursed for approximately 76%, 75% and 76%, respectively, of the amount of
the Navy's Edison bills paid by CFP. The fee payable for the second and third
turbines increased from 10% of related revenues to 15% in December 1998 and
will increase to 20% in December 2003.
In addition, CFP is required to pay the Navy $25,000 in December 2009, the
date the contract expires. The payment is secured by funds placed on deposit
monthly, which funds plus accrued interest will aggregate $25,000. Currently,
the monthly amount to be deposited is $50.
6. Project Loan
The project loan is as follows:
<TABLE>
<CAPTION>
December 31,
---------------
1997 1998
<S> <C> <C>
Project loan with a weighted average interest rate of
8.76% and 8.79%, respectively, at December 31, 1997 and
1998 with scheduled repayments through December 2001.... $45,666 $40,566
</TABLE>
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of
F-15
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
CFP, Coso Energy Developers (CED) and Coso Power Developers (CPD), collectively
the "Joint Ventures." Pursuant to separate credit agreements executed between
Funding Corp. and each joint venture on December 16, 1992, the proceeds from
Funding Corp.'s note offering were loaned to the Joint Ventures.
The CFP project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Joint Ventures' revenues which will be applied against the
payment of obligations of each joint venture, including the project loans. Each
joint venture's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other joint ventures' credit
agreements. The project loan is non-recourse to any partner in CFP and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CED
or CPD in the event such other joint venture's revenues are insufficient to
meet scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were distributed. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
<TABLE>
<S> <C>
1999.............................................................. $ 9,784
2000.............................................................. 4,267
2001.............................................................. 26,515
-------
$40,566
=======
</TABLE>
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $49,130 and
$43,063, respectively.
F-16
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
7. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CFP. These costs are comprised principally of approved
direct CalEnergy operating costs of the CFP geothermal facility, allocable
general and administration costs, and operator fees and were as follows:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
Operating costs...................................... $2,943 $3,192 $2,748
General and administration costs..................... 1,702 1,702 1,742
Operator fees........................................ 491 491 420
</TABLE>
Both CalEnergy and ESCA are reimbursed at approved amounts for their
respective costs incurred in relation to the CFP Management Committee. The
management committee fees paid were:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
ESCA........................................................ $214 $214 $221
CalEnergy................................................... 143 143 147
</TABLE>
CFP is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The charges to CFP from CLPSI in 1996, 1997 and
1998 were approximately $421, $486 and $532, respectively.
During 1994, the Joint Ventures entered into steam sharing agreements under
which the ventures may transfer steam, with the resulting incremental revenue
and royalty expense shared equally by the ventures. In the second half of 1995,
interconnection facilities between the plants were completed and the transfer
of steam commenced. CFP steam sharing revenue, net of royalties and other
related costs, amounted to $4,898, $10,345 and $17,556 in 1996, 1997 and 1998,
respectively.
The amounts due to (from) related parties as of December 31, 1997 and 1998
consist of the following:
<TABLE>
<CAPTION>
December 31,
----------------
1997 1998
<S> <C> <C>
Due (from) to CalEnergy................................. $ (7) $ 378
Due from CPD for steam sharing.......................... (1,704) (1,902)
Due from CED for steam sharing.......................... (2,500) (2,258)
------- -------
$(4,211) $(3,782)
======= =======
</TABLE>
The December 31, 1997 and 1998 due (from) to CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
In addition, as of December 31, 1997 and 1998 the accrued unpaid royalty due
to CFP II from CFP aggregated $8,255 and $8,748, respectively.
F-17
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO COMBINING AND COMBINED FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
8. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Joint Ventures as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the Joint
Ventures and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Joint Ventures filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in December
1997. As a result of certain procedural actions by the parties and a November
1997 court order, Edison filed an amended complaint on December 16, 1997 and
the Joint Ventures amended their cross-complaint. In addition, the court has
struck Edison's request to terminate the SO4 Agreements and obtain a refund of
all funds paid to the Joint Ventures. The litigation is in its early procedural
stages and the pleadings have not been settled. The Joint Ventures believe that
its claims and defenses are meritorious and that they will prevail if the
matter is ultimately heard on its merits. The Joint Ventures intend to
vigorously defend this action and prosecute all available conterclaims against
Edison.
9. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interests in CFP
and CFP II to Caithness Acquisition Company LLC (Caithness), an affiliate of
ESCA and ESCA II. Upon completion of the sale, COC, Caithness or its designee
will become the operator of CFP and CFP II.
F-18
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Energy Developers
In our opinion, the accompanying balance sheets and the related statements of
operations, of partners' capital and of cash flows present fairly, in all
material respects, the financial position of Coso Energy Developers at December
31, 1997 and 1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Partnership's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the financial statements, the Partnership adopted
in 1998 Statement of Position No. 98-5, "Reporting on the Costs of Start-Up
Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-19
<PAGE>
COSO ENERGY DEVELOPERS
BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31,
-----------------
1997 1998
<S> <C> <C>
Assets
Cash......................................................... $ 873 $ --
Restricted cash and investments (Note 5)..................... 290 290
Accounts receivable.......................................... 18,763 19,835
Prepaid expenses and other assets............................ 1,518 1,526
Property, plant and equipment, net (Note 4).................. 197,709 201,600
Investment in Coso Transmission Line Partners................ 3,222 3,107
Advances to China Lake Plant Services, Inc................... 2,213 1,567
Deferred financing costs, net................................ 324 162
-------- --------
$224,912 $228,087
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities..................... $ 3,563 $ 3,314
Amounts due to related parties, net (Note 6)................. 20,582 23,624
Project loan (Note 5)........................................ 76,654 37,958
-------- --------
100,799 64,896
Partners' capital............................................ 124,113 163,191
-------- --------
$224,912 $228,087
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-20
<PAGE>
COSO ENERGY DEVELOPERS
STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years ended
December 31,
--------------------------
1996 1997 1998
<S> <C> <C> <C>
Revenue
Sales of electricity.............................. $101,923 $102,868 $107,199
Interest and other income......................... 2,520 1,712 1,181
-------- -------- --------
104,443 104,580 108,380
-------- -------- --------
Expenses
Plant operations (Note 6)......................... 18,266 18,830 19,887
Royalty expense (Note 6).......................... 7,820 10,106 10,492
Depreciation and amortization..................... 13,931 14,257 14,308
Interest expense.................................. 13,162 9,105 6,267
-------- -------- --------
53,179 52,298 50,954
-------- -------- --------
Income before cumulative effect of accounting
change........................................... 51,264 52,282 57,426
Cumulative effect of accounting change (Note 2)... -- -- (953)
-------- -------- --------
Net income........................................ $ 51,264 $ 52,282 $ 56,473
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-21
<PAGE>
COSO ENERGY DEVELOPERS
STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
<TABLE>
<CAPTION>
Caithness Coso
Coso Hotsprings
Holdings, Intermountain
L.P. Power, Inc. Total
<S> <C> <C> <C>
Balance, December 31, 1995................... $ 65,208 $ 54,352 $119,560
Distributions to partners(1)................. (30,242) (27,916) (58,158)
Net income................................... 26,657 24,607 51,264
-------- -------- --------
Balance, December 31, 1996................... 61,623 51,043 112,666
Distributions to partners(1)................. (21,234) (19,601) (40,835)
Net income................................... 27,187 25,095 52,282
-------- -------- --------
Balance, December 31, 1997................... 67,576 56,537 124,113
Distributions to partners.................... (9,046) (8,349) (17,395)
Net income................................... 29,366 27,107 56,473
-------- -------- --------
Balance, December 31, 1998................... $ 87,896 $ 75,295 $163,191
======== ======== ========
</TABLE>
- ---------------------
(1) Distributions of $12,793 to Caithness Coso Holdings, L.P. and $11,808 to
Coso Hotsprings Intermountain Power, Inc. were declared and paid on January
2, 1996. Distributions of $13,332 to Caithness Coso Holdings, L.P. and
$12,307 to Coso Hotsprings Intermountain Power, Inc. were declared on
December 31, 1996 and paid on December 31, 1996 and January 2, 1997,
respectively.
The accompanying notes are an integral part of these financial statements.
F-22
<PAGE>
COSO ENERGY DEVELOPERS
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years ended
December 31,
----------------------------
1996 1997 1998
<S> <C> <C> <C>
Cash flows from operating activities
Net income...................................... $ 51,264 $ 52,282 $ 56,473
Adjustments to reconcile net income to net cash
flows from operating activities:
Depreciation and amortization................. 13,931 14,257 14,308
Amortization of deferred financing costs...... 296 240 160
Cumulative effect of accounting change........ -- -- 953
Equity in losses of Coso Transmission Line
Partners..................................... 113 111 115
Additional charges from (advances to) China
Lake Plant Services, Inc. ................... 404 (57) 646
Increase in accounts receivable, prepaid
expenses and other assets.................... (212) (1,718) (1,080)
Increase (decrease) in accounts payable and
accrued liabilities.......................... (6,355) 853 903
Increase (decrease) in amounts due to related
parties...................................... 4,894 (5,020) 3,042
-------- -------- --------
Net cash flows from operating activities.... 64,335 60,948 75,520
-------- -------- --------
Cash flows from investing activities
Additions to power plant and transmission line.. (669) (2,196) (3,460)
Additions to wells and resource development
costs.......................................... (5,364) (1,532) (16,842)
Decrease in restricted cash..................... 235 23,008 --
-------- -------- --------
Net cash flows from investing activities.... (5,798) 19,280 (20,302)
-------- -------- --------
Cash flows from financing activities
Repayment of CalEnergy promissory note.......... (7,981) (10,043) --
Distributions to partners....................... (45,851) (53,142) (17,395)
Repayment of project financing loans............ (31,758) (29,336) (38,696)
-------- -------- --------
Net cash flows from financing activities.... (85,590) (92,521) (56,091)
-------- -------- --------
Net change in cash.............................. (27,053) (12,293) (873)
Cash at beginning of year....................... 40,219 13,166 873
-------- -------- --------
Cash at end of year............................. $ 13,166 $ 873 $ --
======== ======== ========
Supplemental cash flow disclosure
Interest paid................................... $ 15,991 $ 19,570 $ 6,105
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-23
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Energy Developers
Coso Energy Developers (CED or Partnership) was formed on March 31, 1988, in
connection with financing the construction of a geothermal power plant on land
leased from the U.S. Bureau of Land Management (BLM) at Coso Hot Springs, China
Lake, California. CED is a general partnership between Coso Hotsprings
Intermountain Power, Inc. (CHIP), a Delaware corporation, and Caithness Coso
Holdings, L.P. (CCH). CCH is a California general partnership.
The primary BLM geothermal lease has a primary term of 10 years (1998) and
thereafter is subject to automatic extension until October 31, 2035, so long as
geothermal steam is commercially produced. In addition, the lease may be
extended to 2075 at the option of the BLM. The BLM is paid a royalty of 10% of
the value of steam produced. Coso Land Company (CLC), the original leaseholder,
retained a 5% overriding royalty interest based on the value of the steam
produced. CLC is a joint venture between CalEnergy Company, Inc. (CalEnergy)
and an affiliate of CCH.
The Partnership sells all electricity produced to Southern California Edison
(Edison) under a 30-year power purchase contract which expires in 2019. Under
the terms of the contract, Edison makes payments to CED as follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). The scheduled energy
price period for each unit extends until at least March 1999, after which
the energy payment for at least Unit 4 adjusts to the actual avoided
energy cost experienced by Edison at that time. For the year ended
December 31, 1998, Edison's average avoided cost of energy was 2.95 cents
per kwh which is substantially below the contract energy prices earned
for the year ended December 31, 1998. Estimates of Edison's future
avoided cost of energy vary substantially from year to year. The
Partnership cannot predict the likely level of avoided cost of energy
prices under the 30-year power purchase contract at the expiration of the
scheduled energy price period. The revenues generated by the Partnership
could decline significantly after the expiration of the scheduled energy
price period;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997, and 1998, the
bonus payments aggregated $2,228, $2,177 and $2,124, respectively.
CalEnergy served as the operator, maintaining the Partnership's accounting
records and operating the CED plant on a day-to-day basis, until February 1,
1999, when Coso Operating Company LLC (COC), a Delaware limited liability
company, became the operator pursuant to certain operations and maintenance
agreements with CHIP, the managing general partner of CED (see Note 8). COC and
CHIP or wholly owned subsidiaries of CalEnergy.
At formation, and as subsequently amended, the partnership agreement provided
that distributable cash flow before "payout" was allocated 3.81% to CHIP as
managing partner and
F-24
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
96.19% allocated in proportion to the remaining sums necessary to be
distributed to each partner to achieve payout. "Payout" was defined as the
point at which each partner had received aggregate cash distributions from the
96.19% allocation in amounts equal to their accumulated capital contributions.
Cash flow after "payout," which occurred in June 1994, is allocated 48% to CHIP
and 52% to CCH. For purposes of allocating net income to partners' capital
accounts, profits and losses are allocated based on the aforementioned capital
percentages. For income tax purposes, certain deductions and credits are
subject to special allocations as defined in the partnership agreement.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue is recognized based on the payment
rates scheduled in CED's power purchase contract with Edison.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the power plant and transmission line is computed on the
straight line method over their estimated useful life of 30 years and, for
significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
The Partnership reviews long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CED adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CED. The cumulative effect of the change in
accounting principle was $953.
Wells and Resource Development Costs
CED follows the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs,
F-25
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
the cost of drilling and equipping production wells, and administrative and
interest costs directly attributable to the project are capitalized and
amortized over their estimated useful lives when production commences. The
estimated useful lives of production wells are ten years each; exploration
costs and development costs, other than production wells, are amortized over 30
years and, for significant additions, the remainder of the 30-year life from
the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $399 and $669 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $537 and $502 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three years from the point of
completion.
Investment in Coso Transmission Line Partners
Coso Transmission Line Partners (CTLP) is a partnership, between CED and Coso
Power Developers (CPD), which owns the transmission line and facilities
connecting the power plants owned by CED and CPD to the transmission line,
owned by Edison, at Inyokern, California, located 28 miles south of the plants.
CTLP charges CED and CPD for the use of the transmission line. These charges
are recorded by CED as operating expenses and reflected as a reduction in CED's
investment in CTLP.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CED and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CED's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CED is valued at the
lower of cost or market.
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,685 and $1,845, respectively.
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
F-26
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Restricted Cash and Investments
As of December 31, 1997 and 1998, all of the Partnership's investments were
classified as held-to-maturity and reported at amortized cost. Included in
restricted cash are various Bank of America certificates of deposit totaling
$290 at December 31, 1997 and 1998. These deposits have maturities of greater
than three months.
Cash Flows
For purposes of the statements of cash flows, CED considers all money market
instruments purchased with an initial maturity of three months or less to be
cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CED entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 5), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CED made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $42 (payable to CED), which
approximated its fair value. The fair value was based on the estimated amount
that CED would have received to terminate the swap agreement at that date as
provided by the financial institution which was the counterparty to the swap.
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
<TABLE>
<CAPTION>
December 31,
-------------------
1997 1998
<S> <C> <C>
Power plant and gathering system...................... $162,372 $ 164,335
Transmission line..................................... 11,353 10,201
Wells and resource development costs.................. 120,562 137,404
-------- ---------
294,287 311,940
Less accumulated depreciation and amortization........ (96,578) (110,340)
-------- ---------
$197,709 $ 201,600
======== =========
</TABLE>
The transmission line costs represent the Partnership's share of the costs of
construction of transmission lines from Inyokern to the Edison substation at
Kramer and from Kramer to the Edison substation at Victorville.
F-27
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
5. Project Loan
The project loan is as follows:
<TABLE>
<CAPTION>
December 31,
---------------
1997 1998
<S> <C> <C>
Project loan with a weighted average interest rate of 8.63%
and 8.73%, respectively, at December 31, 1997 and 1998
with scheduled repayments through December 2001........... $76,654 $37,958
</TABLE>
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of CED, Coso Finance Partners (CFP) and CPD,
collectively the "Partnerships." Pursuant to separate credit agreements
executed between Funding Corp. and each partnership on December 16, 1992, the
proceeds from Funding Corp.'s note offering were loaned to the Partnerships.
The CED project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Partnerships' revenues which will be applied against the
payment of obligations of each partnership, including the project loans. Each
partnership's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other partnership's credit
agreements. The project loan is non-recourse to any partner in CED and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CFP
or CPD in the event such other partnership's revenues are insufficient to meet
scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were (i) used to retire the promissory
note due CalEnergy and (ii) distributed to the partners. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
<TABLE>
<S> <C>
1999............................................................... $15,658
2000............................................................... 2,472
2001............................................................... 19,828
-------
$37,958
=======
</TABLE>
F-28
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $81,018 and
$39,980, respectively.
6. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CED. These costs are comprised principally of approved
direct CalEnergy operating costs of the CED geothermal facility, allocable
general and administration costs, and operator fees and were as follows:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
Operating costs...................................... $4,204 $3,905 $3,728
General and administration costs..................... 2,125 2,125 2,173
Operator fees........................................ 731 731 727
</TABLE>
Both CCH and CalEnergy are reimbursed at approved amounts for their
respective costs incurred in relation to the CED Management Committee. The
management committee fees paid were:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
CCH......................................................... $222 $218 $223
CalEnergy................................................... 145 145 148
</TABLE>
As indicated in Note 1, CLC is entitled to a royalty of 5% of the value of
the steam used by CED to produce the electricity sold to Edison. The royalty
due CLC for the years ended December 31, 1996, 1997 and 1998 was $2,432, $3,176
and $3,057, respectively. This royalty will be paid when CED has repaid its
project loan.
In addition, as described in Note 2, CED is charged for its use of the
transmission line owned by CTLP. The amount of such net charges was $114, $112
and $115 for the years ended December 31, 1996, 1997 and 1998, respectively.
CED is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The 1996, 1997, and 1998 costs charged to CED from
CLPSI were approximately $974, $606 and $1,350, respectively.
During 1994, the three Coso operating ventures (CED, CPD and CFP) entered
into steam sharing agreements under which the ventures may transfer steam, with
the resulting incremental revenue and royalty expense shared equally by the
ventures. In the second half of 1995, interconnection facilities between the
plants were completed and the transfer of steam commenced. CED steam sharing
revenue, net of royalties and other related costs, amounted to $8,464, $1,584
and $6,430 in 1996, 1997 and 1998, respectively.
F-29
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
The amounts due to (from) related parties at December 31, 1997 and 1998
consist of the following:
<TABLE>
<CAPTION>
December 31,
----------------
1997 1998
<S> <C> <C>
Due to CPD for steam sharing............................. $ 561 $ 259
Due to CFP for steam sharing............................. 2,500 2,258
Due to CalEnergy......................................... 121 702
CLC...................................................... 17,660 20,699
Loan to CLC
Principal.............................................. (141) (141)
Accrued interest....................................... (119) (153)
------- -------
$20,582 $23,624
======= =======
</TABLE>
On December 16, 1992, CED paid $1,531 of principal and all accrued interest
through December 16, 1992 on the promissory note due CalEnergy. A new
promissory note was then signed on December 16, 1992 for the remaining
principal balance. This note bore a fixed interest rate of 12.5%, compounded
semi-annually, and was payable on or before March 19, 2002. The previous note
was signed March 19, 1991 as a result of the partners' arbitration settlement
and accrued interest at a rate defined as the lowest average interest rate
actually charged by the previous project loan lender on any of the Coso
ventures' debt, which was 5.4% through December 16, 1992. Interest on the note
was $2,659 and $250 in 1996 and 1997, respectively. CED made principal payments
on the note of $7,981 during 1996. In January 1997, CED made a principal
payment of $6,442 from funds provided by the partners and in February 1997, the
note and accrued interest were repaid in full.
Additionally, on December 16, 1992, CED retired CLC's promissory note due
CalEnergy, resulting in the loan from CED to CLC of $141. Interest has been
accrued on this loan at 12.5%. Interest on the note was $26 , $29 and $34 in
1996, 1997 and 1998, respectively.
The December 31, 1997 and 1998 due to CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
7. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Partnerships as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the
Partnerships and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Partnerships filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander
F-30
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
and various other tort and contract claims. The actions were effectively
consolidated in December 1997. As a result of certain procedural actions by the
parties and a November 1997 court order, Edison filed an amended complaint on
December 16, 1997 and the Partnerships amended their cross-complaint. In
addition, the court has struck Edison's request to terminate the SO4 Agreements
and obtain a refund of all funds paid to the Joint Ventures. The litigation is
in its early procedural stages and the pleadings have not been settled. The
Partnerships believe that its claims and defenses are meritorious and that they
will prevail if the matter is ultimately heard on its merits. The Partnerships
intend to vigorously defend this action and prosecute all available
counterclaims against Edison.
8. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interest in CED to
Caithness Acquisition Company LLC (Caithness), an affiliate of CCH. Upon
completion of the sale, COC, Caithness or its designee will become the operator
of CED.
F-31
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Partners of Coso Power Developers
In our opinion, the accompanying balance sheets and the related statements of
operations, of partners' capital and of cash flows present fairly, in all
material respects, the financial position of Coso Power Developers at December
31, 1997 and 1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. These financial statements are
the responsibility of the Partnership's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
As discussed in Note 2 to the financial statements, the Partnership adopted
in 1998 Statement of Position No. 98-5, "Reporting on the Costs of Start-Up
Activities."
/s/ PricewaterhouseCoopers LLP
San Francisco, California
February 12, 1999
F-32
<PAGE>
COSO POWER DEVELOPERS
BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31,
-----------------
1997 1998
<S> <C> <C>
Assets
Cash......................................................... $ 1,148 $ 818
Accounts receivable.......................................... 17,873 19,656
Prepaid expenses and other assets............................ 1,592 694
Amounts due from related parties, net (Note 6)............... 1,778 2,848
Property, plant and equipment, net (Note 4).................. 198,483 188,862
Investment in Coso Transmission Line Partners................ 3,929 3,802
Advances to China Lake Plant Services, Inc................... 1,743 2,086
Deferred financing costs, net................................ 403 199
-------- --------
$226,949 $218,965
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities..................... $ 4,269 $ 3,981
Project loan (Note 5)........................................ 97,267 61,323
-------- --------
101,536 65,304
Partners' capital............................................ 125,413 153,661
-------- --------
$226,949 $218,965
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-33
<PAGE>
COSO POWER DEVELOPERS
STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years ended
December 31,
--------------------------
1996 1997 1998
<S> <C> <C> <C>
Revenue
Sales of electricity.............................. $115,126 $112,796 $119,564
Interest and other income......................... 3,174 2,187 1,799
-------- -------- --------
118,300 114,983 121,363
-------- -------- --------
Expenses
Plant operations (Note 6)......................... 13,371 13,146 15,508
Royalty expense................................... 11,486 11,249 11,868
Depreciation and amortization..................... 13,054 13,354 13,744
Interest expense.................................. 12,149 10,532 8,122
-------- -------- --------
50,060 48,281 49,242
-------- -------- --------
Income before cumulative effect of accounting
change........................................... 68,240 66,702 72,121
Cumulative effect of accounting change (Note 2)... -- -- (1,664)
-------- -------- --------
Net income........................................ $ 68,240 $ 66,702 $ 70,457
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-34
<PAGE>
COSO POWER DEVELOPERS
STATEMENTS OF PARTNERS' CAPITAL
(Dollars in thousands)
<TABLE>
<CAPTION>
Caithness Coso
Navy II Technology
Group L.P. Corporation Total
<S> <C> <C> <C>
Balance, December 31, 1995................. $ 70,041.0 $ 70,041.0 $140,082.0
Distributions to partners(1)............... (41,115.0) (41,115.0) (82,230.0)
Net income................................. 34,120.0 34,120.0 68,240.0
---------- ---------- ----------
Balance, December 31, 1996................. 63,046.0 63,046.0 126,092.0
Distributions to partners(1)............... (33,690.5) (33,690.5) (67,381.0)
Net income................................. 33,351.0 33,351.0 66,702.0
---------- ---------- ----------
Balance, December 31, 1997................. 62,706.5 62,706.5 125,413.0
Distributions to partners.................. (21,104.5) (21,104.5) (42,209.0)
Net income................................. 35,228.5 35,228.5 70,457.0
---------- ---------- ----------
Balance, December 31, 1998................. $ 76,830.5 $ 76,830.5 $153,661.0
========== ========== ==========
</TABLE>
- ---------------------
(1) Distributions of $13,769 to Caithness Navy II Group L.P. and $13,769 to
Coso Technology Corporation were declared and paid on January 2, 1996.
Distributions of $16,596 to Caithness Navy II Group L.P. and $16,596 to
Coso Technology Corporation were declared on December 31, 1996 and paid on
December 31, 1996 and January 2, 1997, respectively.
The accompanying notes are an integral part of these financial statements.
F-35
<PAGE>
COSO POWER DEVELOPERS
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the years ended
December 31,
-----------------------------
1996 1997 1998
<S> <C> <C> <C>
Cash flows from operating activities
Net income...................................... $ 68,240 $ 66,702 $ 70,457
Adjustments to reconcile net income to net cash
flows from operating activities:
Depreciation and amortization................. 13,054 13,354 13,744
Amortization of deferred financing costs...... 326 271 204
Cumulative effect of accounting change........ -- -- 1,664
Equity in loss of Coso Transmission Line
Partners..................................... 126 127 127
Additional charges from (advances to) China
Lake Plant Services, Inc..................... (198) 503 (343)
Decrease (increase) in accounts receivable,
prepaid expenses and other assets............ 172 (948) (885)
Increase (decrease) in accounts payable and
accrued liabilities.......................... (7,939) 796 864
Decrease (increase) in amounts due from
related parties.............................. 830 (145) (1,070)
-------- --------- --------
Net cash flows from operating activities.... 74,611 80,660 84,762
-------- --------- --------
Cash flows from investing activities
Additions to power plant and transmission line.. (2,930) (269) (1,411)
Additions to wells and resource development
costs.......................................... (1,403) (7,723) (5,528)
Decrease in restricted cash..................... 450 22,391 --
-------- --------- --------
Net cash flows from investing activities.... (3,883) 14,399 (6,939)
-------- --------- --------
Cash flows from financing activities
Distributions to partners....................... (65,634) (83,977) (42,209)
Repayment of project financing loans............ (31,682) (27,094) (35,944)
Repayment of CalEnergy promissory note.......... -- (973) --
-------- --------- --------
Net cash flows from financing activities.... (97,316) (112,044) (78,153)
-------- --------- --------
Net change in cash.............................. (26,588) (16,985) (330)
Cash at beginning of year....................... 44,721 18,133 1,148
-------- --------- --------
Cash at end of year............................. $ 18,133 $ 1,148 $ 818
======== ========= ========
Supplemental cash flow disclosure
Interest paid................................... $ 18,394 $ 10,877 $ 7,918
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-36
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands)
1. The Partnership and Business of Coso Power Developers
Coso Power Developers (CPD or Partnership) was formed on July 31, 1989, in
connection with financing the construction of a geothermal power plant on land
at the China Lake Naval Air Weapons Station at Coso Hot Springs, China Lake,
California. CPD is a general partnership between Coso Technology Corporation
(CTC), a Delaware corporation, and Caithness Navy II Group L.P. (CNIIG), a New
Jersey limited partnership.
The power plant is located on land owned by the U.S. Navy. Under the terms of
a 30-year contract with the U.S. Navy to develop geothermal energy on its land,
CPD will pay a royalty to the Navy which was initially 4% of revenues, is
currently 10% of revenues, and increases to 20% of revenues after 15 years. The
Navy contract expires in 2009; the Navy has an option to extend it to 2019.
The Partnership sells all electricity produced to Southern California Edison
(Edison) under a 20-year power purchase contract for the Navy II plant expiring
in 2010. Under the terms of the contract, Edison makes payments to CPD as
follows:
. Contractual payments for energy delivered, which payments escalate at an
average rate of approximately 7.6% for the first ten years after the date
of firm operation (scheduled energy price period). The scheduled energy
price period for each unit extends until at least January 2000, after
which the energy payment for at least Unit 7 adjusts to the actual
avoided energy cost experienced by Edison at that time. For the year
ended December 31, 1998, Edison's average avoided cost of energy was 2.95
cents per kwh which is substantially below the contract energy prices
earned for the year ended December 31, 1998. Estimates of Edison's future
avoided cost of energy vary substantially from year to year. The
Partnership cannot predict the likely level of avoided cost of energy
prices under the 20-year power purchase contract at the expiration of the
scheduled energy price period. The revenues generated by the Partnership
could decline significantly after the expiration of the scheduled energy
price period;
. Capacity payments which remain fixed over the life of the contract to the
extent that actual energy delivered exceeds minimum levels of the plant
capacity defined in the contract; and
. Bonus payments to the extent that actual energy delivered exceeds 85% of
the plant capacity stated in the contract. In 1996, 1997 and 1998, the
bonus payments aggregated $2,255, $2,236, and $2,242, respectively.
CalEnergy Company, Inc. (CalEnergy) served as the operator, maintaining the
Partnership's accounting records and operating the CPD plant on a day-to-day
basis, until February 1, 1999, when Coso Operating Company LLC (COC), a
Delaware limited liability company, became operator pursuant to certain
operations and maintenance agreements with CTC, the managing general partner of
CPD (see Note 8). COC and CTC are wholly-owned subsidiaries of CalEnergy.
At formation, and as subsequently amended, the partnership agreement provides
that cash flows before and after "payout" which has occurred, are allocated 50%
each to CTC and CNIIG. "Payout" is defined as the point at which each partner
has received aggregate cash distributions in
F-37
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
an amount equal to their accumulated capital contributions. For purposes of
allocating net income to partners' capital accounts and for income tax
purposes, profits and losses are allocated based on the aforementioned capital
percentages.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
2. Summary of Significant Accounting Policies
Recognition of Revenue
Operating revenues are recognized as income during the period in which
electricity is delivered to Edison. Revenue is recognized based on the payment
rates scheduled in CPD's power purchase contract with Edison.
Fixed Assets and Depreciation
The costs of major additions and betterments are capitalized, while
replacements, maintenance and repairs which do not improve or extend the life
of the respective assets are expensed currently.
Depreciation of the power plant and transmission line is computed on the
straight line method over their estimated useful life of 30 years and, for
significant additions, the remainder of the 30-year life from the plant's
commencement of operations.
The Partnership reviews long-lived assets for impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. An impairment loss would be recognized whenever evidence exists
that the carrying value is not recoverable.
In April 1998, the Accounting Standards Executive Committee issued Statement
of Position (SOP) No. 98-5, "Reporting on the Costs of Start-Up Activities."
SOP No. 98-5 requires that, at the effective date of adoption, costs of start-
up activities previously capitalized be expensed and reported as a cumulative
effect of a change in accounting principle, and further requires that such
costs subsequent to adoption be expensed as incurred. CPD adopted this standard
in 1998 and expensed applicable unamortized costs previously capitalized in
connection with the start-up of CPD. The cumulative effect of the change in
accounting principle was $1,664.
Wells and Resource Development Costs
CPD follows the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal resources. All
such costs, which include dry hole costs, the costs of drilling and equipping
production wells, and administrative and interest costs directly attributable
to the project, are capitalized and amortized over their estimated useful lives
when production commences. The estimated useful lives of production wells are
ten years each; exploration
F-38
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
costs and development costs, other than production wells, are amortized over 30
years and, for significant additions, the remainder of the 30-year life from
the plant's commencement of operations.
Deferred Well Rework Costs
Well rework costs are deferred and amortized over the estimated period
between reworks. These deferred costs of $1,029 and $83 at December 31, 1997
and 1998, respectively, are included in prepaid expenses and other assets.
Currently, both production and injection rework costs are amortized over twelve
months.
Deferred Plant Overhaul Costs
Plant overhaul costs are deferred and amortized over the estimated period
between overhauls. These deferred costs of $0 and $176 at December 31, 1997 and
1998, respectively, are included in prepaid expenses and other assets.
Currently, plant overhauls are amortized over three years from the point of
completion.
Investment in Coso Transmission Line Partners
Coso Transmission Line Partners (CTLP) is a partnership, between CPD and Coso
Energy Developers (CED), which owns the transmission line and facilities
connecting the power plants owned by CPD and CED to the transmission line,
owned by Edison, at Inyokern, California, located 28 miles south of the plants.
CTLP charges CPD and CED for the use of the transmission line at amounts
designed to ensure that CTLP recovers its operating costs. These charges are
recorded by CPD as operating expenses and reflected as a reduction in CPD's
investment in CTLP.
Advances to China Lake Plant Services, Inc.
China Lake Plant Services, Inc. (CLPSI) is a wholly-owned subsidiary of
CalEnergy. CLPSI purchases, stores and distributes spare parts to CPD and two
other affiliated operating ventures. Also, certain other facilities utilized by
all three operating ventures are held by CLPSI. CPD's advances to CLPSI
represent funds advanced for the purchase of spare parts inventory and other
assets. Spare parts inventory held by CLPSI on behalf of CPD is valued at the
lower of cost or market.
Deferred Financing Costs
Deferred financing costs consist of loan fees and are amortized over the term
of the related financing using the effective interest method. Accumulated
amortization at December 31, 1997 and 1998 was $1,823 and $2,027, respectively.
Income Taxes
There is no provision for income taxes since those taxes are the
responsibility of the partners.
F-39
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
Cash Flows
For purposes of the statements of cash flows, CPD considers all money market
instruments purchased with an initial maturity of three months or less to be
cash equivalents.
3. Interest Rate Swap Agreement
In January 1993, CPD entered into a five-year deposit interest rate swap
agreement which, until certain investments were liquidated in February 1997
(see Note 5), effectively converted notional deposit balances from a variable
rate to a fixed rate. Under the agreement, which matured on January 11, 1998,
CPD made payments to the counterparty each January 11 and July 11 at variable
rates based on LIBOR, reset and compounded every three months, and in return
received payments based on a fixed rate of 6.34%. The effective LIBOR rate
ranged from 5.5313% to 5.8125% during 1997 and was 5.7500% at December 31, 1997
and at January 11, 1998, the termination date. The counterparty to this
agreement was a large international financial institution. The carrying amount
of the interest rate swap at December 31, 1997, was $41 (payable to CPD), which
approximated its fair value. The fair value was based on the estimated amount
that CPD would have received to terminate the swap at that date as provided by
the financial institution which was the counterparty to the swap.
4. Property, Plant and Equipment
Property, plant and equipment are comprised of the following:
<TABLE>
<CAPTION>
December 31,
------------------
1997 1998
<S> <C> <C>
Power plant and gathering system......................... $165,708 $164,952
Transmission line........................................ 9,484 8,332
Wells and resource development costs..................... 108,977 114,505
-------- --------
284,169 287,789
Less accumulated depreciation and amortization........... (85,686) (98,927)
-------- --------
$198,483 $188,862
======== ========
</TABLE>
The transmission line costs represent the costs of construction of
transmission lines from Inyokern to the Edison substation at Kramer and from
Kramer to the Edison substation at Victorville.
5. Project Loan
The project loan is as follows:
<TABLE>
<CAPTION>
December 31,
---------------
1997 1998
<S> <C> <C>
Project loan with a weighted average interest rate of 8.61%
and 8.65%, respectively, at December 31, 1997 and 1998
with scheduled repayments through December 2001........... $97,267 $61,323
</TABLE>
The project loan is a loan from Coso Funding Corp. (Funding Corp.). Funding
Corp. is a single-purpose corporation formed to issue notes for its own account
and as an agent acting on behalf of
F-40
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
CPD, Coso Finance Partners (CFP) and CED, collectively the "Partnerships."
Pursuant to separate credit agreements executed between Funding Corp. and each
partnership on December 16, 1992, the proceeds from Funding Corp.'s note
offering were loaned to the Partnerships.
The CPD project loan is collateralized by, among other things, the power
plant, geothermal resource, letters of credit, pledge of contracts and an
assignment of all Partnerships' revenues which will be applied against the
payment of obligations of each partnership, including the project loans. Each
partnership's assets collateralize only its own project loan, and are not
cross-collateralized with assets pledged under other partnership's credit
agreements. The project loan is non-recourse to any partner in CPD and Funding
Corp. shall solely look to such Partnership's pledged assets for satisfaction
of such project loan. However, the Partnership, after satisfying a series of
its own obligations, has agreed to advance support loans to the extent of its
available cash flow and, under certain conditions its letters of credit, to CFP
or CED in the event such other partnership's revenues are insufficient to meet
scheduled principal and interest on its separate project loan from Funding
Corp.
Until February 1997 the Partnership maintained a debt service fund which was
legally restricted as to its use and which required the maintenance of a
specific balance. The fund, comprised of investments of U.S. government and
corporate debt and various mortgage-backed securities with maturities from 1997
through 2024, was required by the terms and conditions of the project financing
and was maintained by First Trust of California in its capacity as the trustee
for the project lender. The securities comprising the fund were categorized as
held-to-maturity and valued at amortized cost. In February 1997 the project
lenders allowed the Partnership to replace the cash and investment balance in
the debt service fund with irrevocable letters of credit. The fund was then
liquidated and the resulting proceeds were (i) used to retire the promissory
note due CalEnergy and (ii) distributed to the partners. Proceeds from the sale
of these securities approximated their carrying value plus interest accrued
through the date of sale.
The annual project loan repayments are summarized as follows:
<TABLE>
<S> <C>
1999............................................................... $39,322
2000............................................................... 1,828
2001............................................................... 20,173
-------
$61,323
=======
</TABLE>
Based on quoted market rates of the Funding Corp. notes, the fair value of
the project loan as of December 31, 1997 and 1998 was approximately $102,495
and $63,912, respectively.
F-41
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
6. Related Party Transactions
CalEnergy, as operator, is reimbursed monthly for non-third-party costs
incurred on behalf of CPD. These costs are comprised principally of approved
direct CalEnergy operating costs of the CPD geothermal facility, allocable
general and administration costs and operator fees and were as follows:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
Operating costs...................................... $3,076 $3,312 $3,026
General and administration costs..................... 1,911 1,911 1,955
Operator fees........................................ 517 517 513
</TABLE>
Both CalEnergy and CNIIG are reimbursed at approved amounts for their
respective costs incurred in relation to the CPD Management Committee. The
management committee fees paid were:
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
CNIIG....................................................... $218 $218 $223
CalEnergy................................................... 145 145 148
</TABLE>
As discussed in Note 2, CPD is charged for its use of the transmission line
owned by CTLP. The amount of such net charges was $126, $127 and $127 for the
years ended December 31, 1996, 1997 and 1998, respectively.
CPD is charged by CLPSI for both its inventory usage and its portion of the
expenses of operating CLPSI. The charges to CPD from CLPSI in 1996, 1997 and
1998 were approximately $381, $1,227 and $361, respectively.
During 1994, the three Coso operating ventures (CPD, CED and CFP) entered
into steam sharing agreements under which the ventures may transfer steam, with
the resulting incremental revenue and royalty expense shared equally by the
ventures. In the second half of 1995, interconnection facilities between the
plants were completed and the transfer of steam commenced. CPD steam sharing
revenue, net of royalties and other related costs, amounted to $3,566, $1,750
and $342 in 1996, 1997 and 1998, respectively.
The amounts due to (from) related parties at December 31, 1997 and 1998
consist of the following:
<TABLE>
<CAPTION>
December 31,
----------------
1997 1998
<S> <C> <C>
Due from CalEnergy........................................ $ (42) $(1,241)
Due from CED for steam sharing............................ (561) (259)
Due to CFP for steam sharing.............................. 1,704 1,902
Loan to China Lake Joint Venture
Principal............................................... (1,562) (1,562)
Accrued interest........................................ (1,317) (1,688)
------- -------
$(1,778) $(2,848)
======= =======
</TABLE>
On December 16, 1992, CPD signed a promissory note with CalEnergy for $973,
which represents the principal on the previous promissory note of $869 plus
accrued interest through December 16, 1992, of $104. This note bore a fixed
interest rate of 12.5%, compounded semi-
F-42
<PAGE>
COSO POWER DEVELOPERS
NOTES TO FINANCIAL STATEMENTS--(Continued)
(Dollars in thousands)
annually, and was payable on or before March 19, 2002. The previous note was
signed March 19, 1991 as a result of the partners' arbitration settlement and
accrued interest at a rate defined as the lowest average interest rate actually
charged by the previous project loan lender on any of the Coso ventures' debt,
which was 5.4% through December 16, 1992. During February 1997, this note and
accrued interest were paid in full. Interest on the note was $181 and $27 in
1996 and 1997, respectively.
Additionally, on December 16, 1992, CPD retired China Lake Joint Venture's
(CLJV) promissory note due CalEnergy, resulting in the loan from CPD to CLJV of
$1,562 at December 31, 1992. CLJV is an affiliated venture. Interest has been
accrued on this loan at 12.5%. Interest on the loan was $291, $329 and $371 in
1996, 1997 and 1998, respectively.
The December 31, 1997 and 1998 due from CalEnergy balances relate to the
venture reimbursing CalEnergy for the costs of operating the plant. This amount
fluctuated in concert with the timing of billings and incurring of costs.
7. Commitments and Contingencies
On June 9, 1997, Edison filed a complaint alleging breach of the power
purchase agreements (SO4 Agreements) between Edison and the Partnerships as a
result of alleged improper venting of certain noncondensible gases at the Coso
geothermal energy project. In the complaint, Edison seeks unspecified damages,
including the refund of certain amounts previously paid under the SO4
Agreements, and termination of the SO4 Agreements. In September 1997, the
Partnerships and CalEnergy filed a cross-complaint against Edison and its
affiliates, The Mission Group and Mission Power Engineering Company, alleging,
among other things, that Edison's lawsuit violates the 1993 settlement
agreement which settled certain litigation arising from the construction of
certain units at the Coso geothermal project by Edison affiliates. In addition,
the Partnerships filed a separate complaint against Edison alleging breach of
the SO4 Agreements, unfair business practices, slander and various other tort
and contract claims. The actions were effectively consolidated in December
1997. As a result of certain procedural actions by the parties and a November
1997 court order, Edison filed an amended complaint on December 16, 1997 and
the Partnerships amended their cross-complaint. In addition, the court has
struck Edison's request to terminate the SO4 Agreements and obtain a refund of
all funds paid to the Joint Ventures. The litigation is in its early procedural
stages and the pleadings have not been settled. The Partnerships believe that
its claims and defenses are meritorious and that they will prevail if the
matter is ultimately heard on its merits. The Partnerships intend to vigorously
defend this action and prosecute all available counterclaims against Edison.
8. Subsequent Event
On January 25, 1999, CalEnergy agreed to sell its indirect interest in CPD to
Caithness Acquisition Company LLC (Caithness), an affiliate of CNIIG. Upon
completion of the sale, COC, Caithness or its designee will become the operator
of CPD.
F-43
<PAGE>
CAITHNESS COSO FUNDING CORP.
UNAUDITED CONDENSED BALANCE SHEET
(Dollars in thousands)
<TABLE>
<CAPTION>
At
June 30,
1999
<S> <C>
Assets
Project loan to Coso Finance Partners................................. $151,550
Project loan to Coso Energy Developers................................ 107,900
Project loan to Coso Power Developers................................. 153,550
--------
$413,000
========
Liabilities and Stockholder's Equity
Senior secured notes:
6.80% notes due 2001.................................................. $110,000
9.05% notes due 2009.................................................. 303,000
--------
Total liabilities..................................................... 413,000
Stockholder's equity.................................................. --
--------
$413,000
========
</TABLE>
See accompanying notes to the unaudited condensed combined financial
statements.
F-44
<PAGE>
CAITHNESS COSO FUNDING CORP.
UNAUDITED CONDENSED STATEMENT OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the
period ended
June 30, 1999
<S> <C>
Interest income................................................... $4,986
------
Interest expense.................................................. 4,986
------
Net income........................................................ $ --
======
</TABLE>
See accompanying notes to the unaudited condensed combined financial
statements.
F-45
<PAGE>
CAITHNESS COSO FUNDING CORP.
UNAUDITED CONDENSED STATEMENT OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
For the
period ended
June 30, 1999
<S> <C>
Cash flows from investing activities ............................. $(413,000)
Cash flows from financing activities.............................. 413,000
---------
Net change in cash................................................ $ --
=========
</TABLE>
See accompanying notes to the unaudited condensed combined financial
statements.
F-46
<PAGE>
CAITHNESS COSO FUNDING CORP.
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS
1. Organization and Operations
Caithness Coso Funding Corp. (Funding Corp.) was incorporated on April 22,
1999, in Delaware. Funding Corp. is a special purpose corporation that was for
the purpose of issuing senior secured notes on behalf of Coso Finance Partners,
Coso Energy Developers and Coso Power Developers (the Coso partnerships),
affiliates of Funding Corp. Funding Corp. has loaned all of the proceeds from
the offering of 6.80% senior secured notes due 2001 and 9.05% senior secured
notes due 2009 (for a total of $413 million) to the Coso partnerships, and the
Coso partnerships have jointly and severally guaranteed on a senior secured
basis, repayment of the senior secured notes.
Funding Corp. has no material assets other than the loans that have been made
to the Coso partnerships. Also, Funding Corp. does not conduct any business,
other than issuing the senior secured notes and making the loans to the Coso
partnerships.
F-47
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
(Note) (New basis)
<S> <C> <C>
Assets
Cash................................................... $ -- $ 3,049
Restricted cash and investments........................ 7,524 26,600
Accounts receivable.................................... 5,404 8,958
Prepaids and other assets.............................. 426 219
Amounts due to related parties......................... 3,782 --
Property, plant and equipment.......................... 180,380 157,953
Power purchase agreement............................... -- 14,284
Advances to China Lake Plant Services, Inc. ........... 4,139 4,200
Deferred financing costs, net.......................... 233 3,750
-------- --------
$201,888 $219,013
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 11,389 $ 14,517
Amounts due to related parties......................... -- 2,945
Project loan........................................... 40,566 151,550
-------- --------
51,955 169,012
Partners' capital...................................... 149,933 50,001
-------- --------
$201,888 $219,013
======== ========
</TABLE>
Note: The condensed combined balance sheet at December 31, 1998 has been
derived from the audited financial statements at that date but does not
include all of the information and footnotes required by generally
accepted accounting principles for complete financial statements.
See accompanying notes to the unaudited condensed combined financial
statements.
F-48
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
Six Months Two Months Four Months
Ended Ended Ended
June 30, February 28, June 30,
1998 1999 1999
(prior
basis) (new basis)
<S> <C> <C> <C>
Revenue
Sales of electricity...................... $23,296 $8,572 $17,037
Interest and other income................. 293 824 1,074
------- ------ -------
23,589 9,396 18,111
------- ------ -------
Expenses
Plant operations.......................... 7,244 3,125 3,914
Royalty expense........................... 2,377 987 2,585
Depreciation and amortization............. 5,911 1,604 3,174
Interest and other expense................ 2,232 663 5,952
------- ------ -------
17,764 6,379 15,625
------- ------ -------
Income before extraordinary item.......... 5,825 3,017 2,486
Extraordinary item-loss on extinguishment
of debt.................................. -- -- 2,374
------- ------ -------
Net income................................ $ 5,825 $3,017 $ 112
======= ====== =======
</TABLE>
See accompanying notes to the unaudited condensed combined financial
statements.
F-49
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
UNAUDITED CONDENSED COMBINED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
Six months Two months Four months
Ended Ended Ended
June 30 , February 28, June 30,
1998 1999 1999
(New basis)
<S> <C> <C> <C>
Net cash provided by operating
activities.............................. $ 13,475 $ 6,592 $ 2,716
Net cash used by investing activities.... (2,566) (538) (21,194)
Net cash provided (used) by financing
activities.............................. (13,013) (1,926) 17,399
-------- ------- --------
Net change in cash and cash equivalents.. $ (2,104) $ 4,128 $ (1,079)
======== ======= ========
</TABLE>
See accompanying notes to the unaudited condensed combined financial
statements.
F-50
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed combined financial statements have been
prepared in accordance with generally accepted accounting principles for
interim financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the combined financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
On May 27, 1999 Coso Finance Partners II was merged into Coso Finance
Partners to form one partnership.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Finance Partners (CFP) has
experienced significant quarterly fluctuations in operating results and it
expects that these fluctuations in energy revenues, expenses and net income
will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition), a wholly owned subsidiary of Caithness Energy LLC, purchased all
of CalEnergy Company, Inc.'s (CalEnergy's) interest in CFP for approximately
$62.0 million. The acquisition was accounted for under the purchase method, and
no goodwill was recorded. After Caithness Acquisition's purchase of CalEnergy's
interest in CFP, a new basis of accounting was adopted. The purchase price was
allocated to the portion of the assets and liabilities purchased from CalEnergy
based upon their fair values, with the amount of fair value of net assets in
excess of the purchase price being allocated to long-lived assets on a pro-rata
basis.
In order to complete the purchase of CalEnergy's interest in CFP, Caithness
Acquisition arranged for short-term debt financing of approximately $77.6
million. This short-term debt was repaid on May 28, 1999 from a portion of the
proceeds from the offering of the senior secured notes. Financing costs
associated with the short-term financing is included in interest expense-
acquisition debt, during the three months ending June 30, 1999.
F-51
<PAGE>
COSO FINANCE PARTNERS AND COSO FINANCE PARTNERS II
NOTES TO THE UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS--(Continued)
The following unaudited pro forma financial information for the six months
ended June 30, 1998 and 1999 present the combined results of operations of CFP
as if the acquisition had occurred as of January 1, 1999, after giving effect
to certain adjustments including amortization of intangible assets, reduced
depreciation and operating expense and increased interest expense. The pro
forma financial information does not necessarily reflect the results of
operations that would have occurred had the acquisition been completed on
January 1, 1999.
<TABLE>
<CAPTION>
Six Months Ended
----------------
June 30, June 30,
1998 1999
------- --------
<S> <C> <C>
Total revenues........................................... $23,589 $27,507
======= =======
Net income............................................... $ 5,675 $ 5,653
======= =======
</TABLE>
3. Debt Financing
On May 28, 1999 Caithness Coso Funding Corp. loaned approximately, $151.6
million, to CFP from a portion of the proceeds from the offering of senior
secured notes. The loan consists of one note of $29.0 million at 6.80% and
another note of $122.6 million at 9.05% with maturity dates of December 15,
2001 and December 15, 2009, respectively. Through this financing all prior
project loans of approximately, $118.0 million were repaid and an extraordinary
loss from the early extinguishment of this debt was incurred for approximately
$2.4 million. The extraordinary loss was due to a premium and other costs
incurred to pay the existing senior secured debt before its maturity date.
F-52
<PAGE>
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
(Note) (New basis)
<S> <C> <C>
Assets
Cash................................................... $ -- $ 8,153
Restricted cash and investments........................ 290 13,507
Accounts receivable.................................... 19,835 8,303
Prepaids and other assets.............................. 1,526 365
Amounts due from related parties....................... -- 312
Property, plant and equipment.......................... 201,600 161,111
Power purchase agreement............................... -- 20,241
Investment in Coso Transmission Line Partners.......... 3,107 3,930
Advances to China Lake Plant Services, Inc. ........... 1,567 1,434
Deferred financing costs, net.......................... 162 2,676
-------- --------
$228,087 $220,032
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 3,314 $ 3,611
Amounts due to related parties......................... 23,624 21,185
Project loan........................................... 37,958 107,900
-------- --------
64,896 132,696
Partners' capital...................................... 163,191 87,336
-------- --------
$228,087 $220,032
======== ========
</TABLE>
Note: The condensed balance sheet at December 31, 1998 has been derived from
the audited financial statements at that date but does not include all of
the information and footnotes required by generally accepted accounting
principles for complete financial statements.
See accompanying notes to the unaudited condensed financial statements.
F-53
<PAGE>
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
Two months Four months
Six months Ended Ended
Ended June February 28, June 30,
30, 1998 1999 1999
(New basis)
<S> <C> <C> <C>
Revenue
Sales of electricity...................... $49,741 $17,533 $10,687
Interest and other income................. 473 78 372
------- ------- -------
50,214 17,611 11,059
------- ------- -------
Expenses
Plant operations.......................... 10,815 4,039 5,516
Royalty expense........................... 4,825 1,592 679
Depreciation and amortization............. 7,264 2,550 5,087
Interest and other expense................ 3,556 616 4,864
------- ------- -------
26,460 8,797 16,146
------- ------- -------
Income (loss) before extraordinary item... 23,754 8,814 (5,087)
Extraordinary item-loss on extinguishment
of debt.................................. -- -- 1,822
------- ------- -------
Net income (loss)......................... $23,754 $ 8,814 $(6,909)
======= ======= =======
</TABLE>
See accompanying notes to the unaudited condensed financial statements.
F-54
<PAGE>
COSO ENERGY DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
Six months Two months Four months
Ended Ended Ended
June 30, February 28, June 30,
1998 1999 1999
(New basis)
<S> <C> <C> <C>
Net cash provided by operating
activities............................... $ 31,253 $10,367 $ 8,810
Net cash provided (used) by investing
activities............................... (8,742) 120 (15,480)
Net cash provided (used) by financing
activities............................... (20,755) 425 3,911
-------- ------- --------
Net change in cash and cash equivalents... $ 1,756 $10,912 $ (2,759)
======== ======= ========
</TABLE>
See accompanying notes to the unaudited condensed financial statements.
F-55
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed financial statements have been prepared
in accordance with generally accepted accounting principles for interim
financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Energy Developers (CED) has
experienced significant quarterly fluctuations in operating results and it
expects that these fluctuations in energy revenues, expenses and net income
will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition), a wholly owned subsidiary of Caithness Energy LLC, purchased all
of CalEnergy Company, Inc.'s (CalEnergy's) interest in CED for approximately
$69.0 million. The acquisition was accounted for under the purchase method, and
no goodwill was recorded. After Caithness Acquisition's purchase of CalEnergy's
interest in CED, a new basis of accounting was adopted. The purchase price was
allocated to the portion of the assets and liabilities purchased from CalEnergy
based upon their fair values, with the amount of fair value of net assets in
excess of the purchase price being allocated to long-lived assets on a pro-rata
basis.
In order to complete the purchase of CalEnergy's interest in CED, Caithness
Acquisition arranged for short-term debt financing of approximately $55.2
million. This short-term debt was repaid on May 28, 1999 from a portion of the
proceeds from the offering of the senior secured notes. Financing costs
associated with the short-term financing is included in interest expense-
acquisition debt, during the three months ending June 30, 1999.
The following unaudited pro forma financial information for the six months
ended June 30, 1998 and 1999 present the combined results of operations of CED
as if the acquisition had occurred as of January 1, 1999, after giving effect
to certain adjustments including amortization of intangible assets, reduced
depreciation and operating expense and increased interest expense. The pro
forma financial information does not necessarily reflect the results of
operations that would have occurred had the acquisition been completed on
January 1, 1999.
<TABLE>
<CAPTION>
Six Months
Ended
---------------
June June
30, 30,
1998 1999
------- -------
<S> <C> <C>
Total revenues............................................ $50,214 $28,670
======= =======
Net income................................................ $24,990 $ 4,963
======= =======
</TABLE>
F-56
<PAGE>
COSO ENERGY DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS--(Continued)
3. Debt Financing
On May 28, 1999, Caithness Coso Funding Corp. loaned $107.9 million, to CED
from a portion of the proceeds from the offering of senior secured notes. The
loan consists of one note of $11.65 million at 6.80% and another note of $96.25
million at 9.05% with maturity dates of December 15, 2001 and December 15,
2009, respectively. Through this financing all prior project loans of
approximately $93.2 million were repaid and an extraordinary loss from the
early extinguishment of this debt was incurred for approximately $1.8 million.
The extraordinary loss was due to a premium and other costs incurred to pay the
existing senior secured debt before its maturity date.
F-57
<PAGE>
COSO POWER DEVELOPERS
UNAUDITED CONDENSED BALANCE SHEETS
(Dollars in thousands)
<TABLE>
<CAPTION>
December 31, June 30,
1998 1999
(Note) (New basis)
<S> <C> <C>
Assets
Cash................................................... $ 818 $ 13,042
Restricted cash and investments........................ -- 18,676
Accounts receivable.................................... 19,656 20,870
Prepaids and other assets.............................. 694 326
Amounts due to related parties......................... 2,848 5,021
Property, plant and equipment.......................... 188,862 147,056
Power purchase agreement............................... -- 28,750
Investment in Coso Transmission Line Partners.......... 3,802 3,704
Advances to China Lake Plant Services, Inc. ........... 2,086 2,099
Deferred financing costs, net.......................... 199 3,782
-------- --------
$218,965 $243,326
======== ========
Liabilities and Partners' Capital
Accounts payable and accrued liabilities............... $ 3,981 $ 6,859
Project loan........................................... 61,323 153,550
-------- --------
65,304 160,409
Partners' capital...................................... 153,661 82,917
-------- --------
$218,965 $243,326
======== ========
</TABLE>
Note: The condensed balance sheet at December 31, 1998 has been derived from
the audited financial statements at that date but does not include all of
the information and footnotes required by generally accepted accounting
principles for complete financial statements.
See accompanying notes to the unaudited condensed financial statements.
F-58
<PAGE>
COSO POWER DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(Dollars in thousands)
<TABLE>
<CAPTION>
Two months Four months
Six months Ended Ended
Ended June February 28, June 30,
30, 1998 1999 1999
(New basis)
<S> <C> <C> <C>
Revenue
Sales of electricity...................... $54,658 $17,509 $35,188
Interest and other income................. 780 150 733
------- ------- -------
55,438 17,659 35,921
------- ------- -------
Expenses
Plant operations.......................... 8,670 3,195 4,410
Royalty expense........................... 5,400 1,806 3,936
Depreciation and amortization............. 7,016 2,339 4,754
Interest and other expense................ 4,452 953 6,446
------- ------- -------
25,538 8,293 19,546
------- ------- -------
Income before extraordinary item.......... 29,900 9,366 16,375
Extraordinary item-loss on extinguishment
of debt.................................. -- -- 2,147
------- ------- -------
Net income................................ $29,900 $ 9,366 $14,228
======= ======= =======
</TABLE>
See accompanying notes to the unaudited condensed financial statements.
F-59
<PAGE>
COSO POWER DEVELOPERS
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in thousands)
<TABLE>
<CAPTION>
Six months Two months Four months
Ended Ended Ended
June 30, February 28, June 30,
1998 1999 1999
(New basis)
<S> <C> <C> <C>
Net cash provided by
operating activities... $ 36,048 $12,016 $ 16,941
Net cash used by
investing activities... (2,735) (1,126) (19,468)
Net cash provided by
financing activities... (33,212) 1,766 2,075
-------- ------- --------
Net change in cash and
cash equivalents....... $ 101 $12,656 $ (452)
======== ======= ========
</TABLE>
See accompanying notes to the unaudited condensed financial statements.
F-60
<PAGE>
COSO POWER DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS
1. Basis of presentation
The accompanying unaudited condensed financial statements have been prepared
in accordance with generally accepted accounting principles for interim
financial information. Accordingly, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to such rules. Management believes that the disclosures are adequate
to make the information presented not misleading when read in conjunction with
the financial statements and the notes thereto included in the audited
financial statements for the year ended December 31, 1998.
The financial information herein presented reflects all adjustments,
consisting only of normal recurring adjustments, which are, in the opinion of
management, necessary for a fair statement of the results for interim periods
presented. The results for the interim periods are not necessarily indicative
of results to be expected for the full year. Coso Power Developers (CPD) has
experienced significant quarterly fluctuations in operating results and it
expects that these fluctuations in energy revenues, expenses and net income
will continue.
2. Acquisition of CalEnergy's interest in the Coso Partnerships
On February 25, 1999, Caithness Acquisition Company, LLC (Caithness
Acquisition), a wholly owned subsidiary of Caithness Energy LLC, purchased all
of CalEnergy Company, Inc. (CalEnergy's) interest in CPD for approximately
$75.0 million. The acquisition was accounted for under the purchase method, and
no goodwill was recorded. After Caithness Acquisition's purchase of CalEnergy's
interest in CPD, a new basis of accounting was adopted. The purchase price was
allocated to the portion of the assets and liabilities purchased from CalEnergy
based upon their fair values, with the amount of fair value of net assets in
excess of the purchase price being allocated to long-lived assets on a pro-rata
basis.
In order to complete the purchase of CalEnergy's interest in CPD, Caithness
Acquisition arranged for short-term debt financing of approximately $78.6
million. This short-term debt was repaid on May 28, 1999 from a portion of the
proceeds from the offering of the senior secured notes. Financing costs
associated with the short term financing is included in interest expense-
acquisition debt, during the three months ending June 30, 1999.
The following unaudited pro forma financial information for the six months
ended June 30, 1998 and 1999 present the results of operations of CPD as if the
acquisition had occurred as of January 1, 1999, after giving effect to certain
adjustments including amortization of intangible assets, reduced depreciation
and operating expense and increased interest expense. The pro forma financial
information does not necessarily reflect the results of operations that would
have occurred had the acquisition been completed on January 1, 1999.
<TABLE>
<CAPTION>
Six Months
Ended
---------------
June June
30, 30,
1998 1999
------- -------
<S> <C> <C>
Total revenues............................................ $55,438 $53,580
======= =======
Net income................................................ $31,055 $26,896
======= =======
</TABLE>
F-61
<PAGE>
COSO POWER DEVELOPERS
NOTES TO THE UNAUDITED CONDENSED FINANCIAL STATEMENTS--(Continued)
3. Debt Financing
On May 28, 1999 Caithness Coso Funding Corp. loaned $153.6 million, to CPD
from a portion of the proceeds from the offering of senior secured notes. The
loan consists of one note of $69.4 million at 6.80% and another note of $84.2
million at 9.05% with maturity dates of December 15, 2001 and December 15,
2009, respectively. Through this financing all prior project loans of
approximately, $139.9 million were repaid and an extraordinary loss from the
early extinguishment of this debt was incurred for approximately $2.1 million.
The extraordinary loss was due to a premium and other costs incurred to pay the
existing senior secured debt before its maturity date.
F-62
<PAGE>
Exhibit A
Coso Geothermal Projects
Independent Engineer's Report
Caithness Coso
Funding Corp.
New York, New York
20 May 1999
[Logo of Sandwell]
<PAGE>
Project 263105
Coso Geothermal Projects
Independent Engineer's Report
For
Caithness Coso Funding Corp.
New York, New York
20 May 1999
Prepared by: /s/ R. G. Low
----------------------------------------
Richard G. Low, P.Eng.
Approved by: /s/ Dick A. Davis
----------------------------------------
Dick A. Davis, P.E.
1
<PAGE>
TABLE OF CONTENTS
1. Executive Summary And Conclusions
2. Scope Of Services By Sandwell
3. Coso Facilities Overview
3.1 General
3.2 Description of Equipment and Operation.
. Navy I
. Navy II
. BLM
3.3 Steam Gathering Systems
3.4 Turbine-Generator Failures, Unit 1 Generator Failures, And Remedial
Actions.
3.5 Dow Sulferox H2S Abatement Systems.
4. Management and Organization.
4.1 General
4.2 Safety
4.3 Training
4.4 Maintenance
4.5 Spares Inventory
4.6 Review of FPLEOSI as Operator
5. Overview of Power Purchase Agreements.
6. Permitting and Environmental Compliance (Not included at this time)
7. Comments on 1999 O&M Financial Projections and Capital Expenditure Forecast.
8. Assessment of Financial Projections.
8.1 General
8.2 Revenues
8.3 Operating And Maintenance Expenses
8.4 Capital Expenditures
APPENDICES
Appendix A - Principal Considerations And Assumptions
Appendix B - Documents Reviewed
Appendix C - Financial Projections
2
<PAGE>
1.0 EXECUTIVE SUMMARY AND CONCLUSIONS
1.1 Executive summary
Sandwell Engineering Inc. (Sandwell) has prepared this report as an
independent engineer's review of the Coso Geothermal Projects, namely
Navy I, Navy II, and BLM ("the plants" or "the facilities"), in
connection with the financing of the plants and for inclusion in the
offering circular therefor. Sandwell has been associated with the Coso
Projects as independent engineer for ten years, and this report
therefore reflects information gathered over that period of time, in
addition to information provided by Caithness Energy L.L.C.
(Caithness) and by FPL Energy Operating Services, Inc. ("FPLEOSI" or
"FPL Operating") specifically for the report.
The Coso Geothermal Projects consist of three separate, but
interlinked, geothermal power projects located at the Naval Weapons
Center in Inyo County, California. Nine turbine generator units (three
for each project) produce a total net rated electrical power
generation of approximately 240 MW using geothermal steam derived from
deep production wells drilled in the geothermal resource known as the
Coso Known Geothermal Resources Area (KGRA). The steam gathering
systems for all three projects are linked together so that optimum use
may be made of the available steam.
The power plants and wellfields are operated by FPL Operating under
separate Operation and Maintenance (O&M) agreements with the owners of
each project (the Partnerships). The geothermal resource is maintained
by Coso Operating Company, Inc, an affiliate of Caithness Energy.
Electrical power generated by the plants is sold to Southern
California Edison (SCE) under three separate 30-year California
Standard Offer No. 4 power purchase agreements. After an initial ten-
year fixed price period expires, the electricity is sold to SCE at a
much lower "Avoided Cost of Energy" rate. SCE has taken the position
that the ten-year fixed price periods expired for Navy I in August
1997, for BLM in March 1999 and for Navy II in January 2000.
FPL Operating and Caithness maintain all permits and approvals
required for current operation of the plants.
The geothermal steam from the resource contains small quantities of
hydrogen sulfide. In order to meet the conditions of the Air Quality
Permits, hydrogen sulfide abatement equipment is required. Normal
operation of the facilities therefore also includes operation of
hydrogen sulfide abatement equipment at each power plant that
processes the hydrogen sulfide into elemental sulfur, which can be
sold. At Navy I and Navy II LO-CAT II primary abatement equipment
units are used. At the BLM plants Dow Sulferox equipment is installed;
the Sulferox units have had an unsatisfactory record in terms of
operational reliability, and the high consumption, and therefore cost,
of the treatment chemicals consumed. Recent modifications, and an
agreement reached with Dow, have improved the operation, and reduced
the operating and maintenance costs to a satisfactory level.
3
<PAGE>
The modifications to the Dow Sulferox systems were required, and the
decision to proceed with the modifications was reasonable, and
prudent.
Eight of the nine turbine generator units were designed and
manufactured by Fuji Electric. The ninth unit (and the first to be
operated at the projects) is of Mitsubishi design and manufacture.
After four years of operation, cracks were detected in one of the Fuji
turbine rotors, and similar faults have since occurred in two other
rotors in Coso project Fuji turbines, in one case causing a blade to
become detached, which damaged other parts of the turbine. After
extensive investigations, modifications designed to avoid the problems
have been made to four of the nine turbine rotors, and will be made to
the remainder as they undergo scheduled overhauls. The modifications
appear to have been successful, in that no cracking or other defects
in the modified rotors have been reported to us. We therefore conclude
that these modifications are an acceptable means of preventing the
cracking as previously detected. We understand that the Partnerships
are in litigation with Fuji regarding the cause and responsibility for
the failures.
The modifications to the Fuji turbine rotors have apparently been
successful in overcoming the cracking previously experienced, and may
reasonably be expected to prevent future similar failures.
The Mitsubishi turbine generator recently suffered an electrical
ground fault in the generator. The generator is being rewound, using a
modification designed to avoid recurrence of the fault. It is reported
that the repaired generator is scheduled to return to service in 5 - 9
weeks. The repair to the Mitsubishi Unit 1generator stator was
necessary, and the decision to incorporate modifications was
reasonable and prudent.
Sandwell's review has included commenting on the 1999 O&M pro forma
and capital expenditure forecasts for the plants and an assessment of
the eleven-year financial projections provided by Caithness Energy.
1.2 Conclusions
On the basis of our review of the plant, of the information provided
to us, and the assumptions set forth in this report, we are of the
opinion that:
. The current operations and maintenance practices employed by FLP
Operating as operator for the plants are reasonable for operation
and maintenance of plants of this type, to maintain compliance with
all relevant environmental and other permits and approvals
required, and to produce the predicted revenues and cash flow of
the plants.
. FPL Operating, as operator, has the geothermal plant operating
experience and resources necessary to operate the plants so as to
produce the predicted revenues and cash flow of the plants.
. The 1999 operating and maintenance financial projections and
capital expenditures forecasts proposed by or on behalf of the Coso
4
<PAGE>
partnerships for the plants are consistent with the operation and
maintenance needs of the plants, are prudent, and are reasonably
designed to produce the predicted revenues and cash flow of the
plants.
. If the plants, including power plants, wellfields and gathering
systems are maintained and operated in accordance with current
practices, and if the quality and quantity of the geothermal
resources for the plants are as projected by Caithness Coso Funding
Corporation, then the eleven year financial projections of
operating and maintenance expenditures, and of capital
expenditures, for the plants, (provided by or on behalf of
Caithness Coso Funding Corporation), are consistent with the
operation and maintenance needs of the plants. Based on these
operating assumptions, the projected revenues and cash flows of the
plants, as shown in the financial projections, are reasonable.
. All major permits and approvals required from federal, state and
local agencies for current operation of the plants have been
obtained, and all required environmental reporting is being carried
out.
. The management organization for operation of the Coso projects is
acceptable. The attention given to safety matters, and the safety
programs being implemented, are reasonable and acceptable. The
training and certification program for plant operators and
maintenance staff is acceptable.
. Assuming interest rates of 6.80% for the senior secured notes due
2001 and 9.05% for the senior secured notes due 2009, then the
debt service coverage ratios ("DSCR") will be:
<TABLE>
<CAPTION>
For the period through 2001:
<S> <C> <C>
Navy I : Minimum DSCR 1.32
Average DSCR 1.32
Navy II: Minimum DSCR 1.32
Average DSCR 1.34
BLM: Minimum DSCR 1.28
Average DSCR 1.32
</TABLE>
<TABLE>
<CAPTION>
For the period from 2002 to 2009:
<S> <C> <C>
Navy I Minimum DSCR 1.50
Average DSCR 1.58
Navy II Minimum DSCR 1.53
Average DSCR 1.59
BLM: Minimum DSCR 1.49
Average DSCR 1.58
</TABLE>
5
<PAGE>
2. SCOPE OF SERVICES BY SANDWELL
Sandwell Engineering Inc. (Sandwell) has performed an independent
engineer's review of the Coso Geothermal Projects: Navy I, Navy II, and BLM
(the facilities). Sandwell is familiar with the technical and financial
aspects of these projects, having served as independent engineer for the
banks that initially provided construction financing for the projects in
1988, having provided an independent engineers review which was included in
the 1992 financing offering circular for Coso Funding Corporation, and
having performed annual technical and budget reviews of the projects for
ten years, to date. In preparing this report, Sandwell has obtained
information from project files and contract documents gathered over ten
years, from discussions with facility operating, maintenance, and
administrative staff, and from information and documents provided by
Caithness Energy L.L.C. (Caithness) and by FPL Energy Operating Services,
Inc. (FPLEOSI).
The scope of this review is as listed below:
. Coso Facilities overview, including:
. Description of equipment and operations
. Description of the steam gathering system
. Turbine generator failures and remedial actions
. Dow Sulferox H2S abatement systems
. Management and organization, including comments on:
. Safety
. Training
. Operating procedures
. Maintenance
. Spares inventory
. Review of FPLEOSI as operator
. Overview of power purchase agreements
. Permitting and environmental compliance
. Comments on 1999 O&M and capital expenditure budgets
. Assessment of financial projections (review of existing data provided by
Caithness).
In the preparation of this report and the opinions that follow, Sandwell
has made certain assumptions with respect to conditions which may exist or
events which may occur in the future. A listing of assumptions and
documentation relied upon by Sandwell in the preparation of this report are
given in Appendix A.
6
<PAGE>
3. COSO FACILITIES OVERVIEW
3.1 General
The Coso Geothermal Projects consist of three separate, but
interlinked, geothermal power projects located at the U.S. Naval
Weapons Center in Inyo County, California. The three projects are
identified as Navy I, Navy II and BLM (Bureau of Land Management).
Information on the equipment and other details of each project are set
out below, but, to summarize, the three projects use a total of nine
turbine generator units to produce a net rated electrical power
generation of approximately 240 MW from high temperature geothermal
brines derived from deep production wells drilled into the geothermal
resource on which the projects are situated, which is identified as
the Coso Known Geothermal Resources Area (KGRA).
The three projects were originally operated independently, with each
project's geothermal resource feeding steam only to the generators in
that project's power block(s). In 1995 inter-project steam transfer
lines were installed which allow sharing of the resources to make
optimum use of the available steam to maximize the project revenues.
The electrical power generated by the projects is conveyed by separate
115 kV (for Navy I) and 230 kV (for Navy II and BLM) transmission
lines, approximately 28.86 miles long, to the Southern California
Edison (SCE) substation at Inyokern, California. The power generated
is purchased by SCE under long term contracts.
The power generating plants and the geothermal resource wellfields are
operated and maintained by FPL Energy Operating Services, Inc.
(FPLEOSI). Operation of the three projects as a single interlinked
group brings the benefits of economies of scale in provision of
maintenance and operating staff, and in using a common inventory of
spare parts. Responsibility for the geothermal resource is carried by
Coso Operating Company, Inc. an affiliate of Caithness Energy, who
carries out the drilling of new wells and maintenance of existing
wells.
Normal operation of the power plants for all three projects is carried
out by operators in a centralized control room located at the Navy II
power plant. A distributed control system allows all normal power
plant operations to be monitored and controlled from this point.
Local control equipment at each power plant can be used to maintain
operation in the event of a failure of the central system.
Figure 3-1 is a map that shows the location of the Coso geothermal
projects. Figure 3-2 is a more detailed map that indicates the
project boundaries and the power plant and well pad locations.
7
<PAGE>
Regional Geothermal Activity
============================
[MAP APPEARS HERE]
Fig. 3-1
8
<PAGE>
[Figure 3-2 map]
9
<PAGE>
3.2 Description of equipment and operation
Navy I
------
The Navy I facility is located on the U.S. Naval Weapons Center at
China Lake and the steam resource is also located on Naval Weapons
Center property, being part of the Coso KGRA. Exploration of the
resource and utilization of its energy are secured under a 30-year
contract with the Navy (terminating in 2009, but with an option for
the Navy to extend the contract for an additional 10 years), and in
return the Navy receives royalty payments and discounted power.
The Navy I power block comprises three separate turbine generator
sets, Coso Units 1,2 and 3. The combined generating capacity of the
three units is approximately 80 megawatts (MW).
The geothermal production wells tap the geothermal resource, which is
a fractured formation of rocks heated by the heat of the earth's
interior. High-pressure water flowing through the rock formations
becomes a mixture of high temperature brine and steam as it travels up
the well bores. Pressure generated in the resource forces the mixture
to flow through the production wells into the steam gathering systems.
The brine, and the steam, from the Coso KGRA contain silica, carbonate
compounds, some metals, carbon dioxide and hydrogen sulfide. The
geothermal resource is a renewable source of energy, so long as
natural ground water flows and reinjection of extracted brine are
adequate to replenish the fluids withdrawn.
A mixture of brine and steam, under pressure from the geothermal
reservoir, is obtained at the wellhead. Piping systems transport the
two-phase flow to separators where the brine is separated from the
steam. Brine that does not flash into steam is collected and
injected back into the resource through injection wells. Returning
this water helps to maintain the characteristics of the resource for
continued power production. Two flows of steam leave the separators,
one at high pressure (approx. 90 psia) and one at low pressure
(approx. 20 psia). These relatively low steam pressures (and
temperatures) allow the use of standard wall carbon steel pipe. The
steam expands through the turbines, which drive generators to produce
electrical power. The steam gathering, and brine piping systems
associated with Navy I have metered cross-connections to the Navy II
system which allow steam and brine to be transferred between the
projects.
The Coso Unit 1 turbine generator was manufactured by Mitsubishi, and
the turbine is a single-cylinder type with high and low pressure
inlets. Coso Units 2 and 3 turbine generators, of Fuji Electric
manufacture, also have dual inlets. These units are similar in type
and configuration to Coso Units 4 through 9 located at Navy II and
BLM.
The exhaust steam from each turbine unit flows to a horizontal shell-
and-tube type surface condenser. Condenser vacuum is maintained by a
system containing steam-jet ejectors together with electrically driven
Nash vacuum pumps. There is an additional, all steam-jet ejector as a
back-up system. The noncondensible gases drawn off by the vacuum
pumps are comprised mostly of carbon dioxide but include small
quantities of hydrogen sulfide, which is carried out of the resource
with the brine and steam. Hydrogen sulfide is an environmentally
regulated substance, and the concentrations of the gas are such that
it cannot be released to
10
<PAGE>
the atmosphere under normal operating conditions without violating
environmental permit limits. A hydrogen sulfide abatement system is
therefore required. During the early years of plant operation the
gases were compressed and reinjected into the resource along with the
brine. However, over time the gas concentrations in the steam began to
increase, reducing condenser vacuum and power generation efficiency. A
LO-CAT II abatement system was installed to treat the noncondensible
gases by a process that converts the hydrogen sulfide to elemental
sulfur, which can be sold for industrial or agricultural use. This
hydrogen sulfide abatement system is now well proven and reliable. To
ensure that permit violations do not occur in the event of a failure,
or during LO-CAT overhauls, a batch-processing abatement system, known
as the Hondo system, is also installed, and provides adequate
abatement backup. The noncondensible gas Roots blowers and TVC
compressors are also still in place and are maintained to allow
reinjection of the noncondensible gases, if necessary.
A four-cell Hamon cooling tower of mechanical draft evaporative
cooling type supplies cooling water for the surface condenser on each
unit. Condensate from the surface condenser supplies make-up water
for the cooling system, and for other plant uses.
Excess condensate is mixed with the spent brine and reinjected into
the geothermal resource.
The cooling towers are equipped with fire-protection systems fed from
a plant firemain. Diesel-driven fire pumps, supplied from a firewater
pond, provide safety system backup during plant shutdowns. The plant
fire protection systems are adequate and in line with normal practice
for this type of facility.
Navy II
-------
The Navy II facility is located on the U.S. Naval Weapons Center at
China Lake, and the steam resource is also located on the Naval
Weapons Center property. Exploration of the resource and utilization
of its energy are secured under a 30-year contract with the Navy
(terminating in 2009, but with an option for the Navy to extend the
contract for an additional 10 years), and in return, the Navy receives
royalty payments and discounted power.
The Navy II power block comprises three separate turbine generator
sets, Coso Units 4, 5 and 6. The combined nominal generating capacity
of the three units is approximately 80 MW.
Coso Units 4, 5 and 6 turbine generators are Fuji Electric units
similar to Units 2 and 3 described above. The wellfield steam
gathering system is also similar to that described for Navy I. The
steam supply systems are cross-connected with the Navy I and BLM steam
systems via metered transfer lines to allow optimum use to be made of
the available steam.
The auxiliary plant and systems for the Navy II power block are
similar to those already described for Navy I. Hydrogen sulfide
abatement is provided by a LO-CAT II unit with ample capacity to
process all the hydrogen sulfide produced when all three Units are
operating at full power output. A second, smaller, LO-CAT II unit
provides additional stand-by abatement capacity, and provides adequate
back-up
11
<PAGE>
capacity. A back up Hondo abatement system was formerly
installed, but has now been moved to provide additional back-up
capacity at Navy I. The noncondensible gas system Roots blowers are
still in place and are maintained, but the TVC compressors at Navy II
have been removed.
As mentioned above, the central control room, from where the operation
of the Navy I, Navy II and BLM power plants is monitored and
controlled, is located at Navy II.
The plant fire protection systems are adequate and in line with normal
practice for this type of facility.
BLM
---
The BLM facility and steam resource are located on U.S. Bureau of Land
Management (BLM) property, within the boundaries of the U.S. Naval
Weapons Center at China Lake. The steam resource is part of the Coso
KGRA. Exploration of the resource and utilization of its energy is
secured under a 40-year lease with BLM (terminating in 2025), and in
return BLM receives royalty payments. Some additional steam
resources, located on property to the West and North of the Navy I and
Navy II projects, also form part of the available BLM geothermal
resource, and are designated as BLM North. Steam from BLM North will
be fed into the Navy I or Navy II gathering systems, and will be
considered to "pass-through" the Navy I and Navy II systems to
generate power in the BLM generating units.
The BLM power generating facilities comprise three separate turbine
generator sets, Coso Units 7, 8 and 9. The combined generating
capacity of the three units is approximately 80 NMW. Units 7 and 8 are
located on one power block designated BLM East, while Unit 9 is
located on a separate power block designated BLM West, located
approximately 1.3 miles west of BLM East.
Coso Units 7, 8 and 9 turbine generators are Fuji Electric units
similar to the Navy I and Navy II Fuji machines described above. The
wellfield steam supply system, and brine systems, are also similar to
those described for Units 2 through 6, and are linked to Navy II via a
metered transfer line.
The auxiliary plant and systems for the BLM East and West power blocks
are similar to those already described for Navy I and Navy II. Dow
Sulferox units provide hydrogen sulfide abatement at both plants.
These units perform the same function as the LO-CAT II equipment at
Navy I and Navy II, converting the hydrogen sulfide gas to elemental
sulfur. (Additional information about the Sulferox systems is given in
Section 3.5 below.) A back up Hondo abatement system is installed at
BLM East.
The plant fire protection systems are adequate and in line with normal
practice for this type of facility.
3.3 Description of the steam gathering system.
Steam from the production geothermal wells associated with each
project is transported by piping systems to the power plants, where it
is used to power the steam turbine generators which produce
electricity. Fig. 3-2 gives an indication of
12
<PAGE>
the number of wells and the relative locations of the wells and power
plants. The extensive piping systems and associated equipment is known
as the steam gathering system.
The mixture of brine and steam obtained at each wellhead, under
pressure from the geothermal reservoir, is controlled by wellhead
valves. The two-phase flow of brine and steam is transported via a
piping system to a separator vessel located, in most cases, close to
the wellpad. In the separator vessel some of the hot brine flashes to
steam. The brine that does not flash to steam is collected in a
retention pond, and is eventually pumped back into the resource
through injection wells.
Steam is used at two pressures, approximately 90 psia and 20 psia.
The two pressures allow for most efficient use of all the available
steam, since some wells produce steam and brine at relatively low
pressure and temperature. Steam is transported from the separators to
the power plant turbines through insulated and metal-jacketed carbon
steel pipes. Since the steam pressures and temperatures are
relatively low, carbon steel standard wall pipe can be used.
The steam gathering systems for Navy I and Navy II have a metered
cross-connection which allows for interchange of steam between the
projects, and there is a similar metered cross-connection between
Navy II and BLM. Steam produced from East Flank Navy I wells is fed
into the Navy II gathering system, due to the geographical locations
of the wells and the piping systems. Similarly, steam from the future
BLM North production wells will be tied into the Navy I gathering
system.
The brine and steam from the resource carry silica and carbonates that
can cause scaling in the piping systems. A number of different
methods have been used to remove scale, including passing a "pig" (a
cleaning device) through the piping system, and "hydroblasting" which
removes the scale with high pressure water jets. Acidification of the
liquid phase (i.e. the brine) has been tested at Coso as a means of
mitigating scaling, and FPLEOSI plans to continue using this method of
scale control. Acidification for scale control has been successfully
used at other geothermal projects and it is reasonable to expect that
it will be successful at Coso. Other parts of the gathering system
also require regular maintenance, including the valves at wellheads,
and elsewhere in the piping systems, separator vessels (which tend to
corrode due to the corrosive/erosive action of the brine and steam),
and the instrumentation and control equipment necessary to monitor and
control the gathering system operation.
From observation of the gathering system and wellpads, it is our
opinion that the system is well maintained and in line with the normal
practices of the industry. Wellheads and valves are painted, there are
very few steam leaks, and the insulation and jacketing on the piping
systems is in good repair.
3.4 Turbine generator rotor failures, Unit 1 generator failures, and
remedial actions.
During a normal scheduled overhaul of the Fuji turbine generator Unit
9 in the spring of 1993 (when the unit and the rotor had been in
service for 4 years), cracks were found in the rotor blade roots and
wheel steeples at the second from the last (L-2) stage. Evaluations
by various parties led to consensus that corrosion fatigue was
involved, but there was uncertainty as to the exact cause. It was
agreed that
13
<PAGE>
the corrosive, high sulfur, geothermal steam environment was probably
a factor, and that blade resonance was also probably involved. This
rotor was repaired and rebuilt to the original Fuji design.
During routine overhaul of Unit 8 in the spring of 1997, similar blade
root and wheel steeple cracking was found in the L-1 and L-2 stages of
the rotor. At this time, this rotor had been in service for 8 years.
The Partnerships made the decision to repair this rotor incorporating
modifications to the design which had been evolved in conjunction with
TurboCare, a specialist turbine repair company. Modifications
included replacing the turbine blades in these two stages with
titanium blades incorporating a modified root designed to reduce peak
stresses and increase fatigue life, shrouding the L-2 blades to reduce
resonance, tuning the diaphragms to reduce blade resonance stimulus,
and repairing the rotor wheels with 12 - chrome material for better
corrosion resistance.
In March 1998 a failure occurred in Unit 9, when a blade from the L-2
stage was thrown off during operation and caused damage to other parts
of the turbine. It should be noted that this rotor was not the same
one that had previously shown cracking after service in Unit 9, as the
spare rotor had been installed at that time. It was determined that
the failure had occurred due to the same type of cracking as had been
found previously. This rotor was rebuilt, incorporating the
modifications already described, and the Partnerships made the
decision to rebuild all the Fuji rotors to the modified design as
scheduled overhauls took place. To date, three rotors have been
rebuilt and installed, one is being modified and will be returned to
Coso as the current spare in early April 1999, and five rotors remain
to be modified in the future. The modifications appear to have been
successful, in that no cracking or other defects in the modified
rotors have been reported to us.
The schedule for modification of the remaining five Fuji rotors is as
follows:
Unit 4: May 1999
Unit 6: October 1999
Unit 3: January 2000
Unit 7: May 2000
Unit 8: October 2000
The costs of these modifications (approximately $1,350,000 per rotor)
have been included in the eleven-year financial projections.
Sandwell has observed and monitored these rotor failures, and the
proposed and implemented solutions, since 1993. In our opinion, the
management and staff at Coso have handled this matter in an exemplary
manner throughout, showing a high level of engineering expertise while
making management decisions designed to maintain operation of the
plant and maximize revenues. We conclude that these modifications are
an acceptable means of preventing the cracking as previously reported.
In our opinion, these modifications were required to minimize the
possibility of future rotor failures, and the decision by the
Partnerships to modify all the Fuji rotors was reasonable and prudent.
We understand that the Partnerships are in litigation with Fuji, the
rotor designers and manufacturers, claiming costs associated with the
failures and the modifications as warranty items. Fuji has not made
any counter-claim, and the financial forecasts reviewed have not
included any amounts that may be received from Fuji in the future.
14
<PAGE>
A completely separate failure, affecting the Mitsubishi Unit 1
generator, occurred on 3 January 1999, when a stator coil ground fault
caused the unit to shut down automatically. It was subsequently
determined that the wedges holding the stator coils had loosened,
allowing the coils to move slightly, penetrating the coils' insulation
and eventually causing the ground fault. This unit had been in
service since 1987, and has been regularly inspected and overhauled.
Reports of the last overhaul inspection in 1995 had noted no damage or
other significant findings. The stator has been rewound by a reputable
repair shop incorporating modifications designed to prevent
recurrence of the wedge loosening. This repair was necessary, and the
decision to incorporate modifications was reasonable and prudent.
Unit 1 was scheduled to return to service on 23 March 1999, but latest
reports indicate that electrical faults recurred during start-up of
the generator. As it appeared the electrical faults that occurred
during start-up after the repair may have been due to faulty
workmanship by the repairer, the Partnerships chose to use a different
repair shop to carry out the latest repairs to the generator. It is
anticipated that the generator will be back in service in 5 - 9 weeks.
In our opinion, this duration is reasonable for this type of repair.
It is reported that the equipment repairs and any additional downtime
will be fully insured, the insurance deductibles (25 days business
interruption, and $500,000 for the equipment) having already been
satisfied for this incident, so there will not be any further impact
on project revenues. In our opinion this failure could not have been
foreseen, nor prevented, by the operators, and the subsequent actions
and decisions by Coso management and staff have been designed to
minimize the potential loss of revenues involved.
3.5 Dow Sulferox H2S abatement systems.
The BLM East and BLM West units were modified at the direction of Dow
Chemical, and per Coso Operating Company's technical specification.
The modified units were placed back into service at the beginning of
the first quarter of 1999. Currently, the units are operating as
expected with less operator intervention and less maintenance than
before the modifications were made. Longer-term operations are needed
to fully determine the benefits of the modifications.
The modifications were intended to mitigate poor operating
efficiencies related to each unit that included:
. High chemical consumption
. Low equipment availability
. High pluggage rates
. Poor process controllability
The modifications to both units included installation of:
. Redesigned sparged contactor vessels
. Redesigned stack mist eliminators
. Improved chemical storage facilities
. Upgraded control systems and logic
. Backup capabilities to the old pipeline contactor vessels and
separators
. Improved continuous emissions monitoring (CEM) systems
15
<PAGE>
Remaining remedial work includes plant cleanup of chemical over spray
from previous operations. Future consumption and costs of the
chemicals are fixed under an agreement with Dow Chemicals Company.
In our opinion these modifications to the Sulferox units were required
to improve the efficiency of operation and reduce cost. The decision
to proceed with the modifications was reasonable and prudent.
16
<PAGE>
4.0 MANAGEMENT AND ORGANIZATION
4.1 General
The Coso projects were formerly operated and maintained by CalEnergy
Company Inc. (CECI) under O&M Agreements with China Lake Operating
Company (CLOC), Coso Technology Corporation (CTC) and Coso Hotsprings
Intermountain Power (CHIP), the Managing General Partners of the Navy
I, Navy II and BLM plants, respectively. CECI also operated and
maintained the 230 kV and 115 kV transmission lines, and was
responsible for maintenance of the geothermal resource, including
drilling of new wells, well workovers, etc.
From 26 February 1999, CECI ceased to be the operator of the projects,
and FPL Energy Operating Services, Inc. (FPLEOSI) assumed that role.
Amended and Restated O&M Agreements between FPLEOSI and the Managing
General Partners, now known as New CLOC, New CTC and New CHIP, were
implemented. FPLEOSI also took over operation of the transmission
lines. Under the new arrangements, Coso Operating Company, Inc, an
affiliate of Caithness Energy became responsible for maintenance of
the geothermal resource.
Most of the Coso projects operating, maintenance and management staff
transferred from CECI to FPLEOSI when the transition of ownership and
operating company occurred. It was reported that the CECI Coso
Projects General Manager will become the Production Manager in the
FPLE organization, reporting to FPLEOSI's Plant General Manager, who
will have responsibilities for other geothermal plants in addition to
Coso. FPLEOSI's West Region organization operates out of a regional
office in Livermore, California, with responsibility for all
operations of the FPL Energy geothermal plants in the region. In our
opinion, the proposed management organization for operation of the
Coso Projects is typical for facilities of this type and is
acceptable.
From conversations with FPLEOSI's Coso management, it appears that
significant change in the organization and staffing of the projects is
unlikely in the short term. In the future, FPLEOSI will seek to
improve the efficiency and profitability of the projects, as it has
done with the other FPLEOSI geothermal plants. FPLEOSI resources and
staff expertise are available to assist in efficient operation of the
projects.
4.2 Safety
CECI had an established safety program for the projects, which was
based on a Safety Manual and safety procedures which were considered
to be consistent with general industry practices. However in the
first quarter of 1998 the number of OSHA Recordable Injuries increased
sharply, compared to comparable statistics for the previous three
years, and this led CECI management to implement the "Coso Safety
Recovery Plan", which addressed the causes of the accidents that had
occurred and also sought to increase the general safety awareness of
the staff. This plan included daily tailgate safety meetings, Job
Safety Analyses and documented pre-job safety planning for high-risk
and new jobs, an increased number of formal safety meetings, increased
safety training, etc. These actions were an indication of the high
priority given to safety by CECI's local management.
17
<PAGE>
The same management, operating, maintenance and support personnel are
continuing to operate the projects under FPLEOSI management direction,
and it is anticipated that the existing emphasis on proper safety
procedures and safety awareness will also continue, and will even be
enhanced by additional input from FPLEOSI. FPLEOSI management makes
safety a priority and has initiated an aggressive safety policy
designated the "Safety 2000 Program". The stated objective of this
plan is to achieve zero injuries by the year 2000. In 1997, the six
plants operated by FPLEOSI had 13 OSHA Recordable Injuries (with
contractors included); in 1998 the same six plants reduced the number
of recordable injuries to eight, a 38% improvement.
The attention given to safety matters, the safety programs being
implemented, and the results achieved to date, appear to be in line
with the standards normally found in the power industry and are
acceptable.
4.3 Training
CECI had, for several years, actively supported a program for training
and certification of operators and maintenance personnel at the
projects. The comprehensive program provides training materials,
testing and certification for five classifications of operators. This
training and certification program appears to be similar to those
normally found in the power industry and is acceptable.
FPLEOSI has not announced any proposed changes to the training and
certification procedures. FPLEOSI management has stated a general
commitment, to develop a multi-functional, team-driven and flexible
work force where employees are well-trained, involved, engaged and
accountable to meet and/or exceed plant performance objectives. It
therefore appears probable that the established training programs will
be continued, and may be enhanced, by FPLEOSI. If, as implied,
"cross-training" of staff takes place in the future, this can be
expected to improve the overall productivity of the personnel.
4.4 Maintenance
At present, as under the former CECI management, maintenance
activities are under the direction of a Maintenance Manager, and a
staff of qualified technicians performs normal maintenance activities.
Maintenance activities for the projects are scheduled and recorded
using a computerized system that produces detailed work orders for
planned and requested plant maintenance and repair activities, and is
also linked to the spare parts inventory and procurement system.
Specialized maintenance and repairs, such as turbine generator
overhauls, are performed by outside contractors, assisted by CECI
staff. Major equipment overhauls are scheduled by the Maintenance
Manager (with management approval) to ensure maximum availability
during periods of peak power demand. The normal practice has been to
schedule major turnarounds of one or more turbine generator units,
together with associated maintenance and cleaning of associated
auxiliary equipment and systems, in the spring of each year, in
preparation for the summer peak demand period. These major
turnarounds are generally scheduled to last ten to twelve days. As
mentioned in 3.4 above, the need to preclude possible Fuji turbine
rotor failures has required some additional major unit turnarounds to
be scheduled in 1998 and 1999. Short two to three day outages of
additional units, for
18
<PAGE>
minor repairs, are usually also scheduled during the same pre-peak
periods. The availability of the plants has historically been very
high, demonstrating the effectiveness of the maintenance and overhaul
scheduling practices.
It is not anticipated that any immediate changes in these procedures
will be made by FPLEOSI. In the long term, it appears that the
availability of additional resources from within FPLEOSI is likely to
further improve the reliability and availability of the plant.
Sandwell's independent engineer's reviews of the plants, wellfields
and transmission lines during numerous site visits over ten years have
consistently reported the facilities to be clean and well maintained
and in line with the general standards of the industry.
4.5 Spares Inventory
Availability of spare parts and materials needed for maintenance and
repairs is reported to be satisfactory. Review of the spare parts
Inventory Catalog dated 2 March 1999 showed an acceptable inventory
level in line with what we would expect for facilities of this type.
The spare parts are properly stored and catalogued for quick retrieval
when required. Agreements with some material suppliers (notably the
well-casing supplier) to hold certain quantities of materials in stock
have allowed inventory levels at the projects to be reduced, with a
corresponding reduction in cost.
A single extra Fuji turbine rotor has been held as a common spare for
the eight Fuji units. Due to the plans for modification of the
turbine rotors (as described in 3.4 above) as each unmodified rotor is
changed out for a modified one, in accordance with the planned outage
schedule, the unmodified rotor becomes the spare, and may not be
immediately available while the modifications are carried out in the
turbine specialist's workshop. This period is not expected to exceed
seventy days, and although five rotors remain to be modified, the
probability of any significant loss of revenue for this cause is low,
in our opinion.
4.6 Review of FPLEOSI as operator
In preparing this report Sandwell has reviewed information supplied by
FPLEOSI and has also interviewed FPLEOSI management staff. FPL Energy
Operating Services was formed in 1997 to provide operating and
maintenance (O&M) services for generating plants owned by FPL Energy.
FPLEOSI is part of Florida Power & Light's Power Generation Business
Unit, which gives FPLEOSI access to the processes, skills and
experience of the parent company's many years of experience on
operation and maintenance of power generating plants. FPL Energy has
been associated with the Coso Projects from their inception, as one of
the partners in ownership of the Navy I project. FPLEOSI already
successfully operates five other geothermal power generation projects
in California and Nevada (Brady Units 1 & 2, Calistoga, Green Ridge,
East Mesa, and Posdef), and has a stated commitment to maximize the
profitability of each project in a safe and environmentally sound
manner. FPLEOSI's West Regional Office in Livermore, California,
provides support in resources and talents which can be shared among
the Western facilities. This regional concept should provide savings
for all the
19
<PAGE>
facilities involved, by having team members functionally accountable
across several sites, providing the optimum level of service to each
plant, on an "as needed" basis.
In a document entitled "FPL Energy Operating Services Performance
Story" it is stated that:"FPLEOSI focuses on the objectives of
safety, environmental, operational excellence, and economic value in
providing its O&M services. Safety is a priority of FPLEOSI
management, which pursues an aggressive safety policy. Responsible
environmental stewardship aims at increasing the value of each project
by minimizing the incidence of Notices of Violation. Operational
excellence focuses on continuous improvement of the skills, knowledge
and competencies of each individual member of the staff, so as to
improve the overall productivity of the workforce. The economic value
of each project is maximized by finding ways to continuously improve
the total cost performance and availability of each generating unit;
results quoted for the six FPLEOSI West Region geothermal plants in
1997 and 1998 indicate significant reductions in O&M costs and "best-
in-class" availability performance since FPLEOSI took over the
operation of the plants."
20
<PAGE>
5.0 OVERVIEW OF POWER PURCHASE AGREEMENTS, ETC.
Power Purchase Agreements
The Coso partnerships sell 100% of their net electrical energy to SCE
pursuant to three separate 30-year California Standard Offer No. 4
power purchase agreements. Each Power Purchase Agreement is
independent of the others, and the performance requirements included
in one such agreement apply only to the facilities owned by the Coso
partnership which is a party to that Agreement. Under these Power
Purchase Agreements, the Coso partnerships receive capacity payments
for being able to produce electricity at certain levels, capacity
bonus payments if they are able to produce above a specified higher
level and energy payments based on the amount of electricity they
actually produce. The capacity and capacity bonus payment rates are
fixed throughout the terms of the Power Purchase Agreements and the
energy payments are fixed for the first ten years of the Power
Purchase Agreements.
After the ten-year fixed price period expires, the Coso partnerships
sell electricity to SCE based on SCE's "Avoided Cost of Energy", or
SCE's cost to generate electricity if SCE were to produce it itself or
buy it from another power producer rather than buy it from the Coso
partnerships. SCE has taken the position that the fixed energy price
period under the Power Purchase Agreements expired in August 1997 at
Navy I and March 1999 at BLM. The fixed energy price period at Navy II
will expire in early 2000. The Power Purchase Agreements for Navy I,
BLM and Navy II expire in August 2011, March 2019 and January 2010,
respectively.
Subsidy payments
In addition to these contracted payments, the Coso Projects qualify
for subsidy payments legislated under California Assembly Bill 1890
("AB1890") because geothermal energy has been classified as a
renewable source of energy. AB1890 provides for these payments through
the end of 2001.
Capacity payments
The Coso projects also qualify for Capacity payments. A plant
qualifies for an annual capacity payment by meeting specified
performance requirements on a monthly basis during an approximately
four-month long on-peak period, which currently runs during the months
of June through September of each year. The basic performance
requirement is that the Plant deliver an average kWh output during
specified on-peak hours of each month in the on-peak period at a rate
equal to at least an 80% Contract Capacity Factor. The "Contract
Capacity Factor" equals (1) a Plant's actual electricity output,
measured in kWhs, during the hours of measurement, divided by (2) the
product obtained by multiplying the Plant's "Contract Capacity," as
stated in the SO4 Agreement applicable to such Plant, by the number of
hours in the measurement period. If a Plant maintains the required 80%
Contract Capacity Factor during the applicable periods, the annual
capacity payment will be equal to the product of the capacity payment
per kWh stated in the SO4 Agreement and the Contract Capacity.
21
<PAGE>
The Navy I Plant has a Contract Capacity of 75 MW, and a capacity
payment per kW year of $161.20, for an annual maximum capacity payment
of $12,090,000. The BLM Plant and the Navy II Plant each have a
Contract Capacity of 67.5 MW, and capacity payments per kW year of
$175.00 and $176.00, respectively, yielding annual maximum capacity
payments of $11,812,500 and $11,880,000, respectively. Although
capacity prices per kWh remain constant throughout the life of each
SO4 Agreement, capacity payments are disbursed by SCE on a monthly
basis in accordance with a tariff schedule filed with the CPUC.
Payments are made unevenly throughout the year, and are weighted
toward the on-peak periods; currently, approximately 84% of the
capacity payments received by the Partnerships from SCE are paid in
respect of on-peak months, and approximately 16% in respect of non-
peak months. As of the end of the 1992 on-peak season, each of the
Plants earned, for the first time, the maximum capacity payments
available under its respective SO4 Agreement for the on-peak months
and has continued to earn the maximum capacity payment in each year up
to and including 1998.
Capacity bonus payments
Each Partnership is entitled to receive capacity bonus payments during
both on-peak and non-peak months by operating at a Contract Capacity
Factor of between 85% and 100% during on-peak hours of each month. A
Plant qualifies for capacity bonus payments in respect of on-peak
months provided the Plant operates at least at an 85% Contract
Capacity Factor during the on-peak hours of the month, and qualifies
in respect of non-peak months if performance requirements for on-peak
months have been satisfied and the Plant also operates at a Contract
Capacity Factor of at least 85% during on-peak hours of the non-peak
month. Capacity bonus payments for each month increase with the level
of kWhs delivered between the 85% and 100% Contract Capacity Factor
levels during the month. The annual capacity bonus payment for each
month is equal to a percentage based on the Plant's on-peak Contract
Capacity Factor (which percentage may not exceed 18% of the annual
capacity payment). All the plants have received the maximum capacity
bonus payments since 1992, except for Navy I in 1998. In 1998, Navy I
did not receive the maximum bonus because overall project performance
was optimized by diverting steam to those projects which were still
operating on the ten-year fixed energy price agreements. Once the
ten-year fixed energy price agreement period has expired for all the
projects, it is projected that all the plants will receive the maximum
capacity bonus during the eleven-year period through 2009.
Energy payments
The energy price component for all electricity delivered to SCE is
subject to a different pricing mechanism during the first 10 years of
each SO4 Agreement than is applicable during the remaining term of
each agreement. During the first 10 years following the commencement
of firm power delivery, the energy price per kWh varies between so-
called "on-peak" and "non-peak" periods, but the average of these
prices equals a fixed price per kWh specified in the SO4 Agreements.
SCE has taken the position that this period ended in August 1997 for
the Navy I Partnership, and will end in March 1999 for the BLM
Partnership and January 2000 for the Navy II Partnership. Based on
CPUC precedent and the circumstances surrounding the execution of the
Navy II and the BLM Partnerships' SO4
22
<PAGE>
Agreements, management of the Partnerships believes that the energy
prices in 1999 and 2000 will be at least 14.6 cents per kWh, but not
more than 15.6 cents per kWh and 16.6 cents per kWh, respectively.
After the initial 10-year period under each SO4 agreement expires, the
energy price paid for electricity delivered under the agreement will
be based upon SCE's short-run Avoided Cost, which is currently
determined and published from time to time by the CPUC.
23
<PAGE>
6.0 PERMITTING AND ENVIRONMENTAL COMPLIANCE
Sandwell has reviewed copies of the major permits and approvals
required from federal, state and local agencies for current operation
of the facilities. Copies of relevant permits and approvals have been
in Sandwell's files during our ten years or involvement with the
projects as independent engineer, and we have recently received updated
lists and copies from FPLEOSI.
The U.S. Naval Air Weapons Station (NAWS) and the U.S. Bureau of Land
Management (BLM) have issued permits to the Partnerships for the
projects, including Utilization Permits for the design, construction
and operation of the Projects and Geothermal Drilling Permits for the
geothermal wells drilled. Representatives of NAWS and BLM have
verbally represented to us that the projects have all the permits
required for current operations, that all the permits are currently in
force, and that they are not aware of any violations or defaults.
State and local air quality regulations affecting the projects are
administered by the Great Basin Unified Air Pollution Control District
(GBUAPCD). GBUAPCD has issued to each project the Authorities to
Construct (ATOs) and Permits to Operate (PTOs) for equipment (including
two above-ground gasoline storage tanks )producing emissions to the
atmosphere. Air monitoring under the permits is performed
automatically with the use of remote data gathering systems. The
projects self-report to GBUAPCD any instances of emissions exceeding
the permit limits. A Title V operating permit application for the
projects was submitted to GBUAPCD in May 1996, and effectively
functions as the operating permit pending final action by GBUAPCD.
Representatives of GBUAPCD have verbally represented to us that no
other air quality permits are required for the current operations of
the projects.
Certain air permit violations have occurred at the projects, and the
GBUAPCD issues Notices of Violation (NOVs) when GBUAPCD rules or permit
violations occur. Our experience has been that the majority of NOVs in
recent years have been related to equipment failures or operator errors
which result in venting of hydrogen sulfide to the atmosphere. A
single equipment breakdown incident may not result in issue of an NOV,
but if more than three breakdowns in a single category of equipment
occur within a twelve month period an NOV will be issued. Not all
violations result in action by the GBUAPCD, and not all NOVs result in
the levy of fines. NOVs issued within the last two years, and fines
levied, have been as follows:
<TABLE>
<CAPTION>
Project NOVs Fines ($)
------- ------ ---------
<S> <C> <C> <C>
1997: Navy I 4 8,000
Navy II 7 24,000
BLM 12 38,000
1998: Navy I 5 34,000
Navy II 1 3,000
BLM 9 11,000
</TABLE>
24
<PAGE>
Water quality at the projects is under the regulatory control of the
Lahontan Regional Water Quality Control Board (LRWQCB). Waste
Discharge Requirement Permits (WDRs) for the projects were issued and
are reported by FPLEOSI to cover all current waste discharge
activities. FPLEOSI has also reported that a national pollution
discharge elimination system (NPDES) permit is not required because
there are no discharges into navigable waters. Representatives of
LRWQCB have verbally represented to us that the projects have all the
permits that are required for current operations, that all the permits
are currently in force and that they are not aware of any violations
or defaults.
The projects generate hazardous wastes and must obtain a hazardous
waste generator identification number from the U.S. Environmental
Protection Agency (EPA). This number has been obtained and we believe
that all hazardous wastes continue to be handled, stored and disposed
of in accordance with regulations.
In Sandwell's opinion, all the appropriate regulatory approvals and
permits for current operation of the facilities are in place. We also
believe that all required environmental reporting is being carried
out.
Sandwell is not aware of any other existing or potential environmental
hazards which might impact future operation or profitability of the
facilities. It is not anticipated that the number of NOVs will
increase in the future, unless significant changes occur in the permit
requirements. If proper operation and maintenance of the hydrogen
sulfide abatement systems continues, and the facilities continue to be
operated in compliance with normal industry practices, there should
not be any environmental deficiencies or limitations.
25
<PAGE>
7.0 COMMENTS ON 1999 O&M FINANCIAL PROJECTIONS AND CAPITAL
EXPENDITURE FORECAST
Sandwell has reviewed the Coso 1999 financial projections for operating and
maintenance expenses of each project, and for the three projects combined.
A comparison of major line items was also made with the CECI budgets
reviewed in October 1998 and the actual expenditures in 1998 and 1997. The
financial projection figures are consistent with the known costs of plant
operation and maintenance and reflect the best available information. The
documents reviewed are listed in Appendix B.
Sandwell has also reviewed the 1999 Capital Expenditure Forecast dated
3/16/99, and has compared this to the projects' budget capital expenditure
figures reviewed in October 1998. The expenditures proposed reflect major
overhaul schedules and the costs of turbine generator rotor repairs. The
documents reviewed are listed in Appendix B.
We find that the operating and maintenance financial projections and the
capital expenditure forecasts proposed by FPLEOSI and Caithness Energy are
consistent with the operation and maintenance needs of the facilities, are
prudent, and are reasonably designed to produce the predicted revenues and
cash flows of the facilities.
26
<PAGE>
8.0 ASSESSMENT OF FINANCIAL PROJECTIONS
8.1 General
Sandwell reviewed the financial projections model provided by
Caithness, which contains an eleven-year projection, beginning in
1999, of revenues, expenses, initial and long-term expenditures,
royalties, capital additions, and cash flows. The financial model
predicts the financial performance of each project and consolidates
the results to measure aggregate debt service coverage. A copy of the
document reviewed is included in Appendix C.
Assumptions on which the financial model is based include information
related to the quantity and quality of the geothermal resources for
the facilities and the predicted decline in resource availability's
from different parts of the wellfields.
8.2 Power availability and production
The steam produced by the geothermal resource associated with each
project is shared between the projects to make optimum use of the
available steam and to achieve projected overall project revenues.
From the information provided by Caithness, the projected annual
average power available for each project over eleven years from 1999,
based on optimum sharing of the available steam and the projected
average annual power delivered by each project, are as shown in Table
8-1. The general trend is for the project power available to decline
over time, due to the corresponding decline in the geothermal
resource. This trend may be reversed for short periods, on individual
projects, when additional steam-producing wells are brought on line,
or when the amounts of steam transferred between projects are changed
to optimize performance. On the basis of the information given by
Caithness regarding the quality and quantity of steam from the
resource, in our opinion, the assumptions made concerning the
projections of power available and power delivered are reasonable.
Table 8-1
<TABLE>
<CAPTION>
Year Project Power Available (MW) Project Power Delivered (MW)
- ------------------------------------------------------------------------------------------------------------------------
Navy I Navy II BLM Total Navy I Navy II BLM Total
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1999 94.26 81.75 96.97 272.98 89.05 88.84 88.86 266.75
- ------------------------------------------------------------------------------------------------------------------------
2000 91.45 80.44 96.84 268.72 88.09 89.52 86.91 264.52
- ------------------------------------------------------------------------------------------------------------------------
2001 88.80 78.34 100.43 267.56 90.07 88.15 86.38 264.60
- ------------------------------------------------------------------------------------------------------------------------
2002 86.30 77.60 103.52 267.41 90.07 88.21 86.04 264.31
- ------------------------------------------------------------------------------------------------------------------------
2003 83.93 81.55 102.58 268.06 90.07 88.32 86.59 264.98
- ------------------------------------------------------------------------------------------------------------------------
2004 81.69 77.81 108.00 267.50 89.05 86.89 86.07 262.02
- ------------------------------------------------------------------------------------------------------------------------
2005 79.57 74.40 114.01 267.98 88.09 88.32 86.53 262.94
- ------------------------------------------------------------------------------------------------------------------------
2006 77.56 71.27 118.32 267.15 90.07 88.24 85.84 264.14
- ------------------------------------------------------------------------------------------------------------------------
2007 75.64 68.39 118.19 262.22 90.07 85.23 83.86 259.16
- ------------------------------------------------------------------------------------------------------------------------
2008 73.82 65.74 112.91 252.47 90.07 80.55 78.90 249.52
- ------------------------------------------------------------------------------------------------------------------------
2009 72.08 63.29 108.10 243.47 87.18 74.36 79.08 240.63
- ------------------------------------------------------------------------------------------------------------------------
</TABLE>
27
<PAGE>
8.3 Revenues
The projected revenues for each project are based upon the resource
availability information provided by Caithness and by Geothermex, the
independent geothermal engineer, and the power purchase agreements
with Southern California Edison Company, which purchases all the power
generated by the projects. Geothermex, in their report, express the
opinion that the projections of resource availability and projected
revenues are reasonable. Henwood Energy Services prepared the
forecasts of future electric energy prices used in the financial
projections. Henwood's forecasts considered the base case and also two
alternate cases, namely the "Low Gas Case" (using a gas price 10%
lower than for the base case) and the "Low Gas Case 2" (using a gas
price 15% lower than for the base case). The lower gas prices would
result in correspondingly lower electrical energy prices. The
financial projections model was used to project figures for the base
case and also in performing a sensitivity analysis to examine the
ability to maintain debt coverage levels under the two low gas cases.
The financial projections for the three cases are summarized in
Appendix C to this report.
Additional factors used in arriving at the net revenues include
revenue generated by steam "shared " from the other projects. The
components of revenue, as mentioned in Section 5.0 above, include
Capacity Payments and Capacity Bonus payments, in addition to the
Energy Payments. The net revenues for each project, projected over
eleven years from 1999, have been calculated by Caithness, and are
shown in Table 8-2 below (for the base case). In our opinion the
assumptions made in projecting these net revenues are reasonable.
Table 8-2
<TABLE>
<CAPTION>
Year Net Annual Revenue ($000s)
- ----------------------------------------------------------------------------------------------------------
Navy I Navy II BLM
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1999 51,629 123,341 47,459
- ----------------------------------------------------------------------------------------------------------
2000 43,881 40,885 33,917
- ----------------------------------------------------------------------------------------------------------
2001 43,683 37,255 35,771
- ----------------------------------------------------------------------------------------------------------
2002 45,088 38,974 38,149
- ----------------------------------------------------------------------------------------------------------
2003 46,241 41,052 39,886
- ----------------------------------------------------------------------------------------------------------
2004 47,267 40,965 41,268
- ----------------------------------------------------------------------------------------------------------
2005 48,661 42,752 44,694
- ----------------------------------------------------------------------------------------------------------
2006 49,672 42,803 47,069
- ----------------------------------------------------------------------------------------------------------
2007 49,536 41,710 48,083
- ----------------------------------------------------------------------------------------------------------
2008 49,234 39,699 48,027
- ----------------------------------------------------------------------------------------------------------
2009 49,830 39,011 47,429
- ----------------------------------------------------------------------------------------------------------
</TABLE>
28
<PAGE>
8.4 Operating and maintenance expenses
FPLEOSI is now operator of the projects under O&M agreements with each
project owner. The previous operator, CECI, had prepared operating
and maintenance budgets for 1999, which were reviewed by Sandwell, as
independent engineer, in October 1998. As indicated in Section 7
above, these budgets have been subsequently revised, and Sandwell has
again reviewed the revised budgets.
The eleven-year financial model includes projected operating and
maintenance expense figures for each project. Sandwell has reviewed
these figures and believes them to be reasonable, on the basis of past
experience with the projects, and the stated intentions of FPLEOSI to
continue with improvements to the efficiency and profitability of
operation. FPLEOSI's record in maximizing the profitability of other
similar geothermal generating plants supports the belief that the
projections are reasonable.
A significant additional expense in operating these facilities is the
royalty payments payable to the U.S. Navy and to BLM for use of the
geothermal resources.
8.5 Capital expenditures
The eleven-year financial model includes projected capital
expenditures for each project. Items include projected expenditures
for plant overhauls, resource well drilling, workovers, etc. Sandwell
has reviewed these projected expenditures and believes them to be
reasonable, on the basis of past experience with the projects and
reported actual expenditures in past years. The schedule for the
capital expenditures over the eleven-year period also appears to be
reasonable, based on past experience and the ongoing planned schedules
of plant overhauls, well drilling and workovers.
8.6 Escalation
Where relevant, expenses in the eleven-year financial projections have
been escalated at an assumed rate of 3.0 percent.
8.7 Cash flow
The financial projections prepared by Caithness includes projections
of cash flow for each project over eleven years from 1999. Total
projected operating expenses, royalty payments, capital expenses,
etc., are subtracted from the project operating income to determine
the cash flow available for debt service. The minimum and average
debt service coverage ratios for each project from 1999 to 2009 are as
follows:
<TABLE>
<CAPTION>
For the period through 2001:
<S> <C> <C>
Navy I: Minimum DSCR 1.32
Average DSCR 1.32
</TABLE>
29
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Navy II: Minimum DSCR 1.32
Average DSCR 1.34
BLM: Minimum DSCR 1.28
Average DSCR 1.32
For the period from 2002 to 2009:
Navy I: Minimum DSCR 1.50
Average DSCR 1.58
Navy II: Minimum DSCR 1.53
Average DSCR 1.59
BLM: Minimum DSCR 1.49
Average DSCR 1.58
</TABLE>
The cash flow projections for each project are included in the
financial projections in Appendix C.
30
<PAGE>
APPENDIX A
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
In the preparation of this report and the opinions given, Sandwell has made
certain assumptions with respect to conditions which may exist or events which
may occur in the future. While we believe these assumptions to be reasonable
and customary for the purposes of this report, they are dependent upon future
events, and actual conditions may differ from those assumed. In addition, we
have used and relied upon certain information provided to us by sources which we
believe to be reliable. We believe the use of such information and assumptions
is reasonable for the purposes of our report. However, some assumptions may
vary significantly due to unanticipated events and circumstances. To the extent
that actual future conditions differ from those assumed herein, or provided to
us by others, the actual results will vary from those forecast. This report
summarizes our work up to the date of this report. Thus, changed conditions
occurring or becoming known after such date could affect the material presented
to the extent of such changes.
Opinions of financial evaluations, technical, and economic analyses, and
utilitarian considerations of operations and maintenance costs prepared by
Sandwell herein are made on the basis of our experience and qualifications and
represent our best judgment as experienced and qualified professional engineers.
It is recognized, however, that Sandwell does not have control over the quality
or quantity of the geothermal resource or over the cost of labor, material,
equipment, or services furnished by others or over market conditions or
contractors' and vendors' methods of determining their prices, and that
Sandwell's evaluation of future facility operations and maintenance or work to
be performed must, of necessity, be speculative. Accordingly, Sandwell does not
guarantee that actual costs will not vary from the opinions and evaluations we
have prepared herein.
In preparation of this report, we have reviewed work prepared by others and have
not prepared any original engineering products. We have reviewed certain
documents for engineering issues and their possible impact on commercial issues.
We have not addressed legal or regulatory issues associated with the projects,
nor the impact of legal or regulatory issues on commercial issues. In the
course of ten years' association with the Coso projects as independent
engineers, we have regularly visually inspected all units on all three
projects, all well pads, all gathering and injection pipelines and the
electrical transmission lines. We have done no form of investigation,
inspecting or testing to ascertain the existence of latent problems, flaws, or
defects. Although our most recent site inspection did not identify any
problems, flaws, or defects, any statements made in this report relating to the
physical condition of the facilities is totally based upon a review of
information contained in our files gathered over ten years, and upon visual
observations made during visits to the site of the facilities. Visits have been
made by one or more professional engineers with experience in a wide variety of
electrical power generation projects.
The principal conditions and assumptions made by us in developing the
conclusions and the principal information provided to us by others include the
following:
1. As Independent Engineer, we have made no determination as to the validity
and enforceability of any contract, agreement, rule, or regulation
applicable to the facilities or their operations. However, for the purposes
of this report, since these are operating facilities, we have assumed that
all such contracts, agreements, rules, and regulations are
31
<PAGE>
fully enforceable in accordance with their terms and that all parties will
continue to comply with the provisions of their respective agreements.
2. Certain information used in performing our review, specifically that
related to the quantity and quality of the geothermal resources for the
facilities, was provided by others and relied upon by us. We have relied
upon the analyses and projections of geothermal resources provided to us,
and believe the use of such information is reasonable for the purposes of
this report. In particular, we have relied upon the predictions by
Geothermex that the corrosive and scaling nature of the steam from the
resource will not deteriorate.
3. The operator will continue to maintain the facilities in accordance with
good engineering practice, will continue to make all required renewals and
replacements in a timely manner, and will continue to operate the equipment
in a manner consistent with equipment manufacturers' recommendations and
the normal practices of the industry.
4. The operator will continue to employ qualified and competent personnel who
will properly operate and maintain the equipment in accordance with the
manufacturers' recommendations and generally accepted engineering practice
for the industry, and will generally operate the facilities in a sound and
businesslike manner.
32
<PAGE>
APPENDIX B
DOCUMENTS REVIEWED
Documents reviewed by Sandwell while preparing this report included:
1. Permits, etc:
Great Basin Unified Pollution Control Permits:
Listing of current permits for Navy I, Navy II and BLM
California Regional Water Quality Board - Lahonton Region:
Listing of current Board Orders for Navy I, Navy II and BLM
California Energy Commission :
Listing of current Orders and Decisions for Navy I, Navy II and BLM
Federal Energy Regulatory Commission:
Recertification orders for Navy I, Navy II and BLM
2. Drawings:
Coso Operating Company - Coso Geothermal Project
Gathering, Injection and transfer systems.
Coso Operating Company.
Drawing showing Navy contract lands and Coso KGRA leases
3. Coso Operating Company - Operating Expenses
Actual and budget figures for 1997 and 1998
Budget and pro forma figures for 1999
4. Coso 1999 Budget - Account Summary by Departments
5. Coso 1999 Capital Expenditures Forecast
6. Coso Monthly Status Reports to January 1999.
7. 1998/1999 preliminary Outage Schedule dated 6/23/98.
8. Coso 1999 Drilling Plan dated 7/28/98
9. Amended and Restated O&M Agreements for Navy I, Navy II and BLM.
10. Assignment and Assumption Agreements for Plants, Wellfields and
Transmission Lines.(Effective 1 February 1999)
11. Coso Projects - Inventory of Spare Parts - 2 March 1999.
33
<PAGE>
12. Coso Safety Recovery Plan Memorandum - 5 May 1998
13. TurboCare report "Redesign of Coso BLM Unit 8 Stage 5 and Stage 6 Blades
for CalEnergy." Draft dated 5 January 1998.
14. Progress reports (to 8 March 1999) and preliminary insurance report (21
January 1999) on Unit 1 stator failure.
15. Document: FPL Energy Operating Services Performance Story.
16. Sandwell Independent Engineer's Report on the Coso Geothermal Projects
26 August 1992.
34
<PAGE>
APPENDIX C
FINANCIAL PROJECTIONS
35
<PAGE>
<TABLE>
<CAPTION>
Caithness Coso Funding Corp.
Consolidated Base Case Projected Operating Results
($ in thousands)
May-Dec Year Ended December 31,
------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
<S> <C> <C> <C> <C> <C> <C>
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $68.01 $32.65 $31.80 $34.20 $36.25 $37.76
Revenue
Capacity Revenue $37,909 $42,830 $42,803 $42,808 $42,806 $42,815
Energy Revenue 107,445 75,852 73,906 79,403 84,372 86,686
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 118,682 116,709 122,211 127,178 129,500
Royalty Payments 15,703 13,040 12,300 12,774 13,424 15,364
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,317
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,963
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 42,432 43,090 48,086 53,272 54,174
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,733 3,723 3,876 4,066 4,102
--------- --------- --------- --------- --------- ---------
Net Income $68,892 $15,259 $17,932 $24,935 $32,387 $35,891
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 82,364 83,621 89,217 94,045 93,865
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,792 1,168 221 289 624
Cash Flow Available for Debt Service 96,213 81,190 74,217 73,403 80,227 82,715
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,313 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.33x 1.33x 1.50x 1.53x 1.54x
Average Debt Service Coverage through 2001 1.33x
Average Debt Service Coverage Ratio from 2002 through 2009 1.59x
<CAPTION>
May-Dec Year Ended December 31,
---------------------------------------------------------------------------
2005 2006 2007 2008 2009
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $40.39 $41.70 $42.43 $43.03 $44.34
Revenue
Capacity Revenue $42,811 $42,794 $42,745 $42,646 $42,556
Energy Revenue 93,295 96,750 96,585 94,314 93,714
--------- --------- --------- --------- ---------
Gross Electric Revenue 136,106 139,544 139,329 136,960 136,270
Royalty Payments 16,643 17,330 17,680 17,677 17,144
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,392 1,433 1,435 1,413 1,407
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,422 60,773 61,290 61,500 59,418
--------- --------- --------- --------- ---------
Operating Income 59,041 61,440 60,359 57,783 59,708
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,347 4,504 4,370 4,359 4,424
--------- --------- --------- --------- ---------
Net Income $43,914 $49,732 $52,146 $53,884 $60,376
========= ========= ========= ========= =========
EBITDA (1) 98,760 101,005 99,666 96,654 96,349
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 81 483 946 1,219 546
Cash Flow Available for Debt Service 85,706 87,207 97,196 94,720 93,610
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.56x 1.60x 1.62x 1.65x 1.68x
</TABLE>
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
<PAGE>
Caithness Coso Funding Corp.
Consolidated Low Gas Case 1 Projected Operating Results
($ in thousands)
<TABLE>
<CAPTION>
May-Dec Year Ended December 31,
------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
<S> <C> <C> <C> <C> <C> <C>
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20
BLM $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00
Navy II $ 176.00 $ 176.00 $ 176.00 $ 176.00 $ 176.00 $ 176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $ 68.01 $ 32.08 $ 31.00 $ 32.22 $ 33.71 $ 35.18
Revenue
Capacity Revenue $ 37,909 $ 42,830 $ 42,803 $ 42,808 $ 42,806 $ 42,815
Energy Revenue 107,445 74,542 72,048 74,812 78,470 80,775
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 117,372 114,851 117,620 121,277 123,590
Royalty Payments 15,703 12,897 12,095 12,266 12,772 14,620
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,319
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,964
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 41,265 41,437 44,004 48,023 49,006
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,731 3,699 3,817 3,989 4,027
--------- --------- --------- --------- --------- ---------
Net Income $ 68,892 $ 14,089 $ 16,255 $ 20,793 $ 27,062 $ 30,648
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 81,194 81,944 85,074 88,719 88,622
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,958 1,238 568 455 625
Cash Flow Available for Debt Service 96,213 80,187 72,610 69,607 75,068 77,472
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,603 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.31x 1.30x 1.43x 1.43x 1.44x
Average Debt Service Coverage through 2001 1.31x
Average Debt Service Coverage Ratio from 2002 through 2009 1.49x
</TABLE>
<TABLE>
<CAPTION>
May-Dec Year Ended December 31,
-----------------------------------------------------------
2005 2006 2007 2008 2009
<S> <C> <C> <C> <C> <C>
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $ 161.20 $ 161.20 $ 161.20 $ 161.20 $ 161.20
BLM $ 175.00 $ 175.00 $ 175.00 $ 175.00 $ 175.00
Navy II $ 176.0 $ 176.00 $ 176.00 $ 176.00 $ 176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $ 37.79 $ 38.89 $ 39.95 $ 40.11 $ 40.96
Revenue
Capacity Revenue $ 42,811 $ 42,794 $ 42,745 $ 42,646 $ 42,556
Energy Revenue 87,286 90,228 90,937 87,911 86,578
--------- --------- --------- --------- ---------
Gross Electric Revenue 130,098 133,022 133,682 130,558 129,134
Royalty Payments 15,867 16,462 16,907 16,755 16,114
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,395 1,433 1,443 1,412 1,399
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,425 60,773 61,299 61,500 59,410
--------- --------- --------- --------- ---------
Operating Income 53,805 55,788 55,476 52,303 53,610
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,271 4,421 4,299 4,279 4,335
--------- --------- --------- --------- ---------
Net Income $ 38,602 $ 43,997 $ 47,192 $ 48,324 $ 54,190
========= ========= ========= ========= =========
EBITDA (1) 93,448 95,271 94,712 91,094 90,162
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 94 548 835 1,314 639
Cash Flow Available for Debt Service 80,406 81,537 92,131 89,256 87,516
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.46x 1.50x 1.54x 1.55x 1.57x
Average Debt Service Coverage through 2001
Average Debt Service Coverage Ratio from 2002 through 2009
</TABLE>
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
<PAGE>
Caithness Coso Funding Corp.
Consolidated Low Gas Case 2 Projected Operating Results
($ in thousands)
<TABLE>
<CAPTION>
May-Dec Year Ended December 31,
-------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004
<S> <C> <C> <C> <C> <C> <C>
Contract Capacity 210 210 210 210 210 210
Net Plant Output (MWh) 1,579,903 2,323,352 2,324,010 2,321,842 2,327,803 2,295,820
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 111.1% 110.2% 110.2% 110.1% 110.4% 109.2%
Average Energy Payment ($/MWh) $68.01 $32.03 $30.76 $31.66 $33.06 $34.29
Revenue
Capacity Revenue $37,909 $42,830 $42,803 $42,808 $42,806 $42,815
Energy Revenue 107,445 74,409 71,496 73,498 76,953 78,734
--------- --------- --------- --------- --------- ---------
Gross Electric Revenue 145,354 117,239 114,299 116,306 119,759 121,548
Royalty Payments 15,703 12,879 12,032 12,124 12,604 14,375
Operating & Maintenance Expense
Operations 4,024 6,032 5,990 5,947 5,902 6,079
Maintenance & Engineering 3,842 5,569 5,527 5,483 5,439 5,602
Coso Services and G&A 3,788 5,491 5,448 5,405 5,360 5,521
Subordinated O&M Fees 1,600 1,500 1,250 1,250 1,250 1,250
Audit & Legal 3,150 2,417 989 1,019 1,049 1,081
Insurance 907 1,211 1,248 1,157 1,191 1,227
Property Tax 1,221 2,560 1,810 1,572 1,303 1,313
SCE Transmission Line Fee 544 816 816 816 816 816
Other 593 1,416 1,433 1,448 1,464 1,481
Depreciation Expense 25,689 36,199 36,808 37,254 36,707 35,589
--------- --------- --------- --------- --------- ---------
Total Expense 45,358 63,211 61,319 61,351 60,482 59,959
--------- --------- --------- --------- --------- ---------
Operating Income 84,293 41,149 40,949 42,831 46,673 47,215
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Interest Income 4,147 3,730 3,692 3,800 3,969 4,000
--------- --------- --------- --------- --------- ---------
Net Income $68,892 $13,973 $15,760 $19,603 $25,692 $28,831
========= ========= ========= ========= ========= =========
EBITDA (1) 114,129 81,079 81,448 83,885 87,349 86,805
Capital Expenditures 18,814 8,466 11,822 17,285 15,356 13,024
Changes in Working Capital (702) 5,975 1,291 664 481 692
Cash Flow Available for Debt Service 96,213 80,088 72,168 68,514 73,724 75,722
Annual Debt Service
Principal Outstanding (end of year) 360,335 330,067 303,000 281,229 253,611 222,279
Interest Expense 19,548 30,906 28,881 27,027 24,950 22,385
Principal Repayment 52,665 30,268 27,067 21,771 27,618 31,332
Total Annual Debt Service 72,213 61,174 55,948 48,798 52,568 53,717
Debt Service Reserve Balance (end of year) 34,633 30,108 26,379 28,763 29,708 30,704
Major Maintenance Reserve Balance (end of year) 8,466 11,822 17,285 15,356 13,024 14,386
Navy Sinking Fund Balance (end of year) 8,420 9,679 11,012 12,426 13,925 15,513
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.33x 1.31x 1.29x 1.40x 1.40x 1.41x
Average Debt Service Coverage through 2001 1.31x
Average Debt Service Coverage Ratio from 2002 through 2009 1.45x
</TABLE>
<TABLE>
<CAPTION>
May-Dec Year Ended December 31,
---------------------------------------------------------
2005 2006 2007 2008 2009
<S> <C> <C> <C> <C> <C>
Contract Capacity 210 210 210 210 210
Net Plant Output (MWh) 2,309,576 2,320,129 2,276,478 2,191,802 2,113,680
Capacity Payment ($/kWyr)
Navy I $161.20 $161.20 $161.20 $161.20 $161.20
BLM $175.00 $175.00 $175.00 $175.00 $175.00
Navy II $176.00 $176.00 $176.00 $176.00 $176.00
Average Capacity Factor (based on 240 MW) 109.6% 110.1% 108.0% 104.0% 100.3%
Average Energy Payment ($/MWh) $36.57 $37.20 $37.85 $38.80 $39.48
Revenue
Capacity Revenue $42,811 $42,794 $42,745 $42,646 $42,556
Energy Revenue 84,454 86,318 86,174 85,031 83,456
--------- --------- --------- --------- ---------
Gross Electric Revenue 127,266 129,112 128,919 127,678 126,012
Royalty Payments 15,496 15,956 16,246 16,353 15,699
Operating & Maintenance Expense
Operations 6,261 6,449 6,643 6,842 7,047
Maintenance & Engineering 5,770 5,943 6,121 6,305 6,494
Coso Services and G&A 5,686 5,857 6,033 6,214 6,400
Subordinated O&M Fees 1,250 1,250 1,250 1,250 1,250
Audit & Legal 1,113 1,147 1,181 1,217 1,253
Insurance 1,264 1,302 1,341 1,381 1,422
Property Tax 1,382 1,408 1,410 1,399 1,383
SCE Transmission Line Fee 816 816 816 816 816
Other 1,498 1,515 1,533 1,551 1,111
Depreciation Expense 35,372 35,061 34,938 34,512 32,217
--------- --------- --------- --------- ---------
Total Expense 60,412 60,748 61,265 61,486 59,393
--------- --------- --------- --------- ---------
Operating Income 51,358 52,408 51,408 49,839 50,920
Interest Expense 19,474 16,212 12,582 8,259 3,755
Interest Income 4,235 4,372 4,239 4,243 4,295
--------- --------- --------- --------- ---------
Net Income $36,119 $40,568 $43,065 $45,824 $51,460
========= ========= ========= ========= =========
EBITDA (1) 90,965 91,841 90,585 88,594 87,432
Capital Expenditures 14,386 15,532 4,666 4,403 4,535
Changes in Working Capital 194 684 943 1,076 670
Cash Flow Available for Debt Service 78,023 78,244 88,112 86,517 84,817
Annual Debt Service
Principal Outstanding (end of year) 186,799 148,513 101,094 51,833 0
Interest Expense 19,474 16,212 12,582 8,259 3,755
Principal Repayment 35,480 38,286 47,419 49,261 51,833
Total Annual Debt Service 54,954 54,498 60,001 57,520 55,588
Debt Service Reserve Balance (end of year) 30,732 34,313 33,272 32,569 0
Major Maintenance Reserve Balance (end of year) 15,532 4,666 4,403 4,535 0
Navy Sinking Fund Balance (end of year) 17,197 18,982 20,874 22,879 25,000
Unrestricted Cash Balance (end of year) 3,000 3,000 3,000 3,000 3,000
Debt Service Coverage Ratio 1.42x 1.44x 1.47x 1.50x 1.53x
Average Debt Service Coverage through 2001
Average Debt Service Coverage Ratio from 2002 through 2009
</TABLE>
(1) EBITDA is defined as net income plus interest expense plus depreciation
expense.
<PAGE>
EXHIBIT B
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 - 2009
Prepared for:
Caithness Coso Funding Corp.
Date Submitted:
May 20, 1999
Prepared by:
Henwood Energy Services, Inc.
2710 Gateway Oaks Way, Suite 300N
Sacramento, CA 95833
http://www.hesinet.com
<PAGE>
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 - 2009
Prepared for:
Caithness Coso Funding Corp.
Date Submitted:
May 20, 1999
Prepared by:
[Logo of HESI]
Henwood Energy Services, Inc.
2710 Gateway Oaks Way, Suite 300 North
Sacramento, CA 95833
(916) 569-0985 - Phone
(916) 569-0999 - Fax
http://www.hesinet.com
----------------------
Contact:
Keith Durand, Project Manager
<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
TABLE OF CONTENTS
- -----------------
<TABLE>
<CAPTION>
SECTION PAGE
- ------- ----
<S> <C>
EXECUTIVE SUMMARY ES-1
- ------------------------------------------------------------------------------------------------
1 THE U.S. ELECTRIC POWER MARKET 1-1
1.1 Introduction 1-1
1.2 Federal Legislative and Regulatory Initiatives 1-1
1.2.1 Public Utility Regulatory Policies Act - 1978 1-1
1.2.2 Energy Policy Act - 1992 1-1
1.2.3 FERC Order 888 - 1996 1-2
1.3 California Legislative Initiatives 1-2
1.3.1 Assembly Bill 1890 1-2
2 THE CALIFORNIA WHOLESALE POWER MARKET 2-1
- ------------------------------------------------------------------------------------------------
2.1 The Market 1998 and Beyond 2-1
2.1.1 Market Size 2-2
2.1.2 Diversity of Energy Supply 2-2
2.1.3 California Investor Owned Utilities 2-3
2.1.4 Treatment of Qualifying Facilities (QFs) 2-4
2.2 California Municipal Utilities and Authorities 2-4
2.3 System Reliability 2-5
2.4 The California PX 2-5
2.4.1 California PX Prices 2-6
2.4.2 Short Run Avoided Costs 2-7
2.5 PX Prices as a Measure of Avoided Cost 2-9
3 SOUTHERN CALIFORNIA MCP FORECAST: KEY ASSUMPTIONS AND METHODOLOGY 3-1
- ------------------------------------------------------------------------------------------------
3.1 Modeling Methodology and Techniques 3-1
3.2 Assumptions Regarding the California Market Transition Period 3-2
3.3 Key Assumptions for Modeling the WSCC Power Market 3-3
3.3.1 Forecast Horizon 3-3
3.3.2 Market Structure 3-3
3.3.3 Existing Resource Base 3-3
3.3.4 Resource Retirements 3-3
3.3.5 Generic Resource Additions 3-4
3.3.6 Loads 3-4
3.3.7 Load Shape 3-5
3.3.8 Load Growth 3-5
</TABLE>
- --------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
i
<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
<TABLE>
<S> <C>
3.3.9 Inflation 3-5
3.3.10 Fuel Prices 3-5
3.3.11 Natural Gas 3-5
3.3.12 Operations & Maintenance 3-16
3.3.13 Property Taxes 3-16
3.3.14 Insurance 3-16
3.3.15 Other Costs 3-16
3.4 WSCC Transmission System Configuration 3-17
3.5 Hydro Power 3-17
3.5.1 Median Year Case 3-17
3.5.2 Transactions 3-18
4 SOUTHERN CALIFORNIA MCP FORECAST : RESULTS 4-1
- ------------------------------------------------------------------------------------------------
4.1 Base Case Southern California MCP Forecast, 2000-2009 4-1
4.2 Sensitivity Cases 4-2
4.2.1 Low Gas Price Case 1 4-2
4.2.2 Low Gas Price Case 2 4-3
5 THE PROJECT AND THE CALIFORNIA MARKET 5-1
- ------------------------------------------------------------------------------------------------
5.1 Market Analysis Results 5-1
5.2 Southern California MCP Forecast and the Market Position of the Project 5-5
6 THE RENEWABLE RESOURCE FUNDING PROGRAM 6-1
- ------------------------------------------------------------------------------------------------
</TABLE>
LIST OF TABLES
--------------
<TABLE>
<S> <C>
TABLE 2-1 1997 NET SYSTEM POWER (ELECTRIC GENERATION) 2-3
TABLE 2-2 MONTHLY AVERAGE CALIFORNIA PX PRICES - APRIL 1998 TO
JANUARY 1999 ($/MWH) 2-7
TABLE 2-3 SCE ANNUAL AVERAGE SHORT-RUN AVOIDED COSTS OF ENERGY 2-9
TABLE 3-1 GENERIC RESOURCE CHARACTERISTICS (1996 DOLLARS) 3-4
TABLE 3-2 PROJECTED GAS COMMODITY PRICE GROWTH BY PRODUCER
BASIN (AVERAGE ANNUAL REAL PERCENT CHANGE) 3-10
TABLE 3-3 HESI BASE CASE SAN JUAN AND ALBERTA COMMODITY
PRICE FORECAST $98/MMBTU 3-11
TABLE 3-4 HESI BASE CASE NATURAL GAS CITY-GATE PRICE FORECAST $1998/MMBTU 3-15
TABLE 4-1 BASE CASE SOUTHERN CALIFORNIA MCP FORECAST 2000 -
2009 $/MWH 4-2
TABLE 4-2 MCP FORECAST UNDER THE LOW GAS PRICE CASE 1 4-3
TABLE 4-3 MCP FORECAST UNDER THE LOW GAS PRICE CASE 2 4-4
</TABLE>
- --------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
ii
<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
<TABLE>
<S> <C>
TABLE 5-1 AVERAGE OPERATING COSTS BY PLANT TYPE IN THE WSCC
FROM PROSYM MODEL SIMULATION IN 2005 5-2
TABLE 5-2 MCP FREQUENCY ANALYSIS IN SOUTHERN CALIFORNIA
TRANSMISSION AREA, 2005 5-6
TABLE 6-1 AB 1890 ACCOUNTS - TOTAL FUNDING ALLOCATIONS BY
TECHNOLOGY $MILLIONS 6-1
TABLE 6-2 EXISTING RENEWABLE RESOURCE ACCOUNT - ALLOCATIONS BY
TIER $MILLIONS 6-2
TABLE 6-3 NEW RENEWABLE RESOURCE ACCOUNT - ALLOCATIONS BY YEAR, $MILLIONS 6-4
</TABLE>
LIST OF FIGURES
---------------
<TABLE>
<S> <C>
FIGURE 2-1 CALIFORNIA PX DAILY PRICES - HIGH, LOW AND AVERAGE 2-8
FIGURE 3-1 ALBERTA GAS COMMODITY PRICE FORECASTS 3-7
FIGURE 3-2 SAN JUAN GAS COMMODITY PRICE FORECASTS 3-8
FIGURE 3-3 ACTUAL AND ESTIMATED MONTHLY GAS PRICE VARIATION AT
TOPOCK 3-12
FIGURE 3-4 WSCC TRANSMISSION SYSTEM CONFIGURATION 3-17
FIGURE 5-1 BASE CASE ANNUAL AVERAGE MCP AND PROJECT OPERATING
COSTS 5-3
FIGURE 5-2 BASE CASE ANNUAL OFF-PEAK MCP AND PROJECT OPERATING
COSTS 5-4
FIGURE 5-3 LOW GAS PRICE CASE 2 ANNUAL OFF-PEAK MCP AND PROJECT OPERATING COSTS 5-5
</TABLE>
LIST OF APPENDICES
------------------
A Southern California Base Case MCP Forecast
B Southern California Low Gas case 1 MCP Forecast
C Southern California Low Gas case 2 MCP Forecast
D Southern California Edison SRAC Price and Tier 3 Renewable Energy Subsidy
Forecast
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
EXECUTIVE SUMMARY
- --------------------------------------------------------------------------------
Caithness Coso Funding Corp. has retained Henwood Energy Services, Inc (HESI) to
provide a detailed assessment of the Coso Project (hereafter the "Project"). The
Project is an existing geothermal power plant located in southern California. It
has a take-or-pay Purchase Power Agreement (PPA) that requires it to operate
continuously.
In HESI's opinion, such an assessment includes consideration of the important
regulatory developments and power market fundamentals that influence the
southern California market, in addition to a forecast of wholesale power prices
over the long term. While the PPA ensures that the Project has a guaranteed
market for its output, thus lessening competitive issues in the future, HESI has
briefly examined the cost competitiveness of the Project with respect to other
generators operating in the Southern California market.
The analysis and conclusions presented here are based upon assumptions developed
and tested by HESI and the power price forecast is derived from HESI's
proprietary Electric Market Simulation System (EMSS) software. The assessment
and forecast contained in this report are presented in both quantitative and
qualitative fashion as listed below:
1. A brief discussion of the key regulatory and market developments that affect
the California wholesale electricity market.
2. A detailed description of the key assumptions used in assessing the market
and utilized as EMSS inputs.
3. Average monthly time-of-day market clearing prices (MCP) in the Southern
California transmission area for the years 2000 to 2009.
4. Two alternative MCP forecasts that assume low gas prices and which are
designed to assess the Projects' sensitivity to changes in power prices over
the long-term.
5. Estimates of Southern California Edison monthly SRAC prices between 1999 and
2001 using the current Transition Period formula.
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1999 - 2009
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6. A specific competitive assessment of the Project on a stand-alone basis
using the Southern California MCP forecast and Project cost estimates
provided by the Project Operator.
7. An assessment of the Project within the context of the competitive market
and how the Project compares with other generators.
8. An assessment and estimate of renewable energy subsidy payments available
from the California government.
Based on our analyses, the report's major conclusions are summarized below:
1. HESI's MCP forecast indicates that the Southern California annual average
power price will increase from $26.9/MWh in 2000 to $44.3/MWh by 2009 -
which translates into an average annual rate of increase of about 5.7
percent over that period (inflation is included in all prices and is equal
to 3 percent per year).
2. However, there are three distinct periods of price movement. Between 2000
and 2002, the "Transition Period" in California, prices increase at an
annual average rate of 12.6 percent. During this period, prices bid into the
California Power Exchange (PX) reflect short run marginal fuel costs because
most utility-owned generators receive payments for capacity from "Must-Run"
contracts, if in California, or through traditional tariffs, if outside of
California.
3. After the Transition Period ends in March 2002, the PX should cease to
behave as a marginal cost pool. This change is reflected in the forecast.
The average MCP increases from $34.1/MWh in 2002 to $40.4/MWh by 2005 - an
average rate of increase of about 5.7 percent per year. Price increases in
this period reflect attempts by generators in California to recover at least
a portion of fixed capacity costs through market sales.
4. Beyond 2005, prices are forecast to increase gradually but steadily, about
2.3 percent per year, which is less than the inflation rate. The growth rate
during the 2005 to 2009 period is influenced largely by the introduction
into the generation market of high efficiency gas-fired combined cycle
plants. These plants are frequently on the margin. That is, they establish
the market-clearing price, and thus are in a position to
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1999 - 2009
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push power prices down gradually over time as they replace less efficient
thermal generation plants.
5. Based on HESI's long-run natural gas price forecast (described in Section
3.3.11 below) and a 3 percent annual inflation rate, we estimate Southern
California Edison SRAC prices of $31.3/MWh for the remaining months of 1999
(May - December), $32.4/MWh in 2000 and $33.4/MWh in 2001. These prices are
higher than HESI's forecast of power prices on the California Power Exchange
during the same period.
6. We expect the Project to be a low cost producer in all years of the study.
According to data provided by the Project Operator, the annual average
operating cost in 2005 is $10.83/MWh. About 70 percent of the electricity
produced in the Western Systems Coordinating Council (WSCC) in 2005 - the
first year of full competition, is generated from units with higher costs.
Of all the generation in the region, only hydro and wind generators have
lower operating costs (hydro and wind power account for about 24 and 1
percent, respectively, of all electric generation in California).
7. The Project's annual average operating costs are 69 percent below annual
Southern California power prices, averaged over all years of the forecast.
In fact, the Projects' operating costs are significantly below even the off-
peak MCP in all forecast years.
8. The low-cost relationship between the MCP forecast and Project operating
costs continues in the Low Gas Price sensitivity cases. Under the worst-case
scenario, Low Gas Price Case 2, the Project's operating costs are, on
average, 58 percent below off-peak prices.
9. We estimate that the Southern California MCP will be greater than or equal
to $19.7/MWh in 96 percent of all hours in 2005. This means that the
Project, with an average operating cost of $10.8/MWh, will be below the MCP
in each of those hours and, in the absence of a PPA, would be dispatched
accordingly.
10. The Project is eligible for AB 1890 sponsored renewable energy subsidies
under Tier 3 of the Existing Renewable Energy category. However, based on
client and HESI assumptions, the Transition Period SRAC price exceeds 3.0
cents per kWh (the floor price guaranteed by
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1999 - 2009
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AB 1890) during most months of 2000 and 2001. Consequently, although subsidy
funds are available, SRAC prices are forecast to be sufficiently high that
Tier 3 producers will not require a subsidy in most months. In the event
that future SRAC prices are lower than forecast here, HESI believes that the
AB 1890 program has ample funds to ensure that Tier 3 producers receive the
minimum of 3.0 cents per kWh until the end of 2001
11. HESI has reviewed the methodology and assumptions used by Caithness to
estimate AB 1890 subsidy payments. We believe their assumptions to be
reasonable and their methodology and calculations consistent with and
similar to HESI's own procedures.
The Report is organized as follows. Section 1 presents a brief overview of the
important federal and California regulatory initiatives that affect electric
power generation. The key features of the California power market, including the
Power Exchange and the SRAC Transition Formula, are described in Section 2.
Section 3 contains a discussion of the assumptions and methodology incorporated
into HESI's forecast of power prices in the Southern California market. The Base
Case and Low Gas Price Case forecast results are presented in Section 4. The
Project's competitive position within the California power market is analyzed in
Section 5. Last, Section 6 presents a brief overview of the AB 1890 sponsored
renewable energy subsidy programs and an estimate of subsidy payments applicable
to the Project.
The MCP forecasts by month and time of day are shown in Appendix A through C.
Appendix D contains SRAC price forecasts and renewable energy subsidy estimates
by month between 1999 to 2001.
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
1 THE U.S. ELECTRIC POWER MARKET
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1.1 INTRODUCTION
The U.S. electric power industry is undergoing a profound transformation. The
industry is evolving from a vertically integrated and cost-regulated monopoly to
one that is market-based with competitive prices. The transition began with the
passing of the Public Utility Regulatory Policies Act (PURPA) in 1978, which
made it possible for non-utility generators to enter the wholesale power market.
As a result, non-utility capacity additions grew 54 percent from 1990 to 1996
while utility capacity additions during the same period grew only 2 percent. The
deregulation process is likely to continue at the state level far into the next
decade.
1.2 FEDERAL LEGISLATIVE AND REGULATORY INITIATIVES
This section briefly discusses the major federal legislation and regulation that
established a framework for electric power industry deregulation and set the
stage for further legislative initiatives at the state level.
1.2.1 Public Utility Regulatory Policies Act - 1978
PURPA is one of five bills signed into law on November 9, 1978, as part of the
National Energy Act. It is the only one remaining in force. Enacted to combat
the "energy crisis," and the perceived shortage of petroleum and natural gas,
PURPA requires utilities to buy power from non-utility generating facilities
that use renewable energy sources or "cogeneration," i.e. the use of steam both
for heat and to generate electricity. The Act stipulates that electric utilities
must interconnect with and buy, at the utilities' avoided cost, the capacity and
energy offered by any non-utility facility ("Qualifying Facility") meeting
certain ownership, operating and efficiency criteria established by the Federal
Energy Regulatory Commission (FERC).
1.2.2 Energy Policy Act - 1992
The Energy Policy Act of 1992 (EPACT) opened access to transmission networks and
exempted certain non-utilities from the restrictions of the Public Utility
Holding Company Act of 1935 (PUHCA). EPACT therefore has made it even easier for
non-utility generators to enter the wholesale market for electricity.
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The Act also created a new category of power producers, called exempt wholesale
generators (EWGs). By exempting them from PUHCA regulation, the law eliminated a
major barrier for utility-affiliated and nonaffiliated power producers wanting
to compete to build new non-rate-based power plants. EWGs differ from PURPA QFs
in two ways. First, they are not required to meet PURPA's utility ownership,
cogeneration, or renewable fuels limitations. Second, utilities are not required
to purchase power from EWGs.
In addition to giving EWGs and QFs access to distant wholesale markets, EPACT
provides transmission-dependent utilities the ability to shop for wholesale
power supplies, thus releasing them - mostly municipals and rural cooperatives -
- - from their dependency on surrounding investor-owned utilities for wholesale
power requirements. The transmission provisions of EPACT have led to a
nationwide open-access electric power transmission grid for wholesale
transactions.
1.2.3 FERC Order 888 - 1996
With the passage of EPACT, Congress opened the door to wholesale competition in
the electric utility industry by authorizing FERC to establish regulations to
provide open access to the nation's transmission system. FERC's subsequent
rules, issued in April 1996 as Order 888, is designed to increase wholesale
competition in the nation's transmission system, remedy undue discrimination in
transmission, and establish standards for stranded cost recovery. A companion
ruling, Order 889, requires utilities to establish electronic systems to share
information about available transmission capacity.
1.3 CALIFORNIA LEGISLATIVE INITIATIVES
1.3.1 Assembly Bill 1890
The legislation that introduced electric power deregulation to California is
Assembly Bill 1890 (AB 1890). The Bill, which was passed in September 1996,
established a number of goals, including:
. An immediate 10 percent rate reduction for residential and small commercial
users.
. A new power market structure with an Oversight Board (OB), an Independent
System Operator (ISO) and a PX.
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. Limits the amount of costs (e.g. stranded assets) that are recoverable in the
transition to a deregulated market.
. Preserves public programs supporting energy efficiency, research &
development and low-income households.
. Provides approximately $540 million in subsidies to support renewable energy
programs, including geothermal power generation, such as the Project.
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2 THE CALIFORNIA WHOLESALE POWER MARKET
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AB 1890 established a four-year Transition Period between January 1998 and March
2002 during which the California power market would undergo the transition from
a regulated to a competitive industry. The ISO and PX were scheduled to commence
operations on January 1, 1998 but technical problems delayed their start until
March 31, 1998. At the end of the Transition Period, most of the protections
afforded California's investor owned-utilities (IOUs) for past uneconomic
investments and power contracts will be removed. It is anticipated that,
eventually, municipal utilities will also permit their retail customers to enter
into direct supply agreements with competitive power suppliers.
2.1 THE MARKET 1998 AND BEYOND
With deregulation, a steadily increasing percentage of customers will be allowed
to purchase power in an open market. Customers will have direct access to
generators. No longer restricted to buying power only from their local utility
company, they can freely select the power arrangement that suits their
preferences.
On March 31, 1998, the PX began operating the Day-ahead energy market, a
wholesale market-clearing auction into which PX participants bid energy supply
and demand for each of the next day's 24 hours. On the same date, the ISO took
control of the electric grid, and began operating a complementary set of
competitive auctions. The ISO relies on these auctions to manage transmission
line congestion, to procure a portion of the needed ancillary services (for
reliability purposes), and to balance physical generation with load in real
time.
During the Transition Period, utilities are afforded the opportunity to recover
certain "stranded costs" for generation-related investments. These costs had
been previously authorized by the CPUC for inclusion in rates, but are not
likely to be recoverable through the prices that emerge in the competitive
market. The mechanism for this cost recovery is an unavoidable Competition
Transition Charge (CTC) assessed against all customers served by the
distribution system of California IOUs.
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2.1.1 Market Size
California's electric power market is very large, with a summer peak demand of
53,217 MW and total power consumption of 275,876 GWh in 1997. The average retail
cost of electricity is about 9.5 cents/kWh. Electric sales by California
utilities equaled $21.75 billion in 1997. According to the WSCC, peak demand for
electricity is forecast to reach 58,305 MW by 2007 - a growth rate of about 1.0
percent per year between 1997 and 2007. /1/
Electricity sales by California's three largest IOU's - PG&E, SCE, and SDG&E,
equaled about 169,045 GWh in 1997, or approximately 74 percent of California's
statewide energy consumption. /2/
2.1.2 Diversity of Energy Supply
During the 1970s, over two-thirds of California's electricity was generated from
oil and natural gas. This decade, however, California has developed a more
diverse resource mix of electricity generation. As Table 2-1 shows, over half of
the state's 258,801 GWh of electricity production is now met with non-fossil
fuel sources. Further, over 11 percent of power generation is fueled by
renewable energy, mainly geothermal, small hydro and biomass (but excluding
large hydro).
California leads in developing new generation technologies. It has 40 percent of
the world's geothermal power plants, 30 percent of the installed wind capacity,
and 90 percent of the world's solar generation. The state also leads the nation
in the amount of electricity supplied by non-utility generators.
Table 2-1 also shows that just over 32 percent of electricity generation is
supplied by natural gas. Because of its cheap price and clean-burning
characteristics, natural gas has become California's fuel of choice,
particularly for electricity generation. According to the California Energy
Commission, natural gas will account for 38 percent of energy used for power
generation by 2009.
- ---------------------------------
/1/ Peak demand forecast from "WSCC 1998 Information Summary," Western Systems
Coordinating Council.
/2/ Electricity consumption and revenue data from the California Energy
Commission..
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Table 2-1
1997 Net System Power
(Electric Generation)
<TABLE>
<CAPTION>
Fuel Type GWh Percent of Total
- ----------------------------------------------------------------
<S> <C> <C>
Hydroelectric* 61,718 24.4%
- ----------------------------------------------------------------
Nuclear 36,741 14.5%
- ----------------------------------------------------------------
Coal* 51,543 20.3%
- ----------------------------------------------------------------
Oil 173 0.1%
- ----------------------------------------------------------------
Natural Gas* 81,256 32.1%
- ----------------------------------------------------------------
Geothermal 11,950 4.7%
- ----------------------------------------------------------------
Organic Waste 5,701 2.3%
- ----------------------------------------------------------------
Wind 2,739 1.1%
- ----------------------------------------------------------------
Solar 810 0.3%
- ----------------------------------------------------------------
Other 896 0.4%
- ----------------------------------------------------------------
Total 253,526 100.0%
- ----------------------------------------------------------------
</TABLE>
*Includes out of state imports.
Source: California Energy Facts, California Energy Commission
Natural gas pipeline capacity into California stood at about 8 Bcf/day in 1996.
Between 1990 and 1996, interstate pipeline capacity into California increased by
65 percent. The major sources of new capacity during this period were the
Mojave, El Paso and Tuscarora pipelines. /3/
2.1.3 California Investor Owned Utilities
As California's utility market moves toward free competition, over 17,800 MW of
generating assets owned by IOUs have been sold, or will be in the near future.
However, despite this divestiture of generation resources, the IOUs are expected
to retain ownership and control of substantial nuclear, QF, and hydropower
generation in California and jointly owned thermal coal-fired generation outside
of California.
The IOUs also buy and sell power from each other, as well as engage in
transactions with other utilities in California and the surrounding Western
states. Each has assumed responsibility for matching load and resources to
- ---------------------------------
/3/ Deliverability on the Interstate Natural Gas Pipeline System, Energy
Information Administration , May 1998.
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maintain frequency, and matching scheduled and actual flows at the tie points by
which utilities are connected to other power producers. Because of their
obligation to serve within their service territories, they also developed
generation and demand forecasts, operated generating plants, and entered into
long-term procurement contracts for the fuel used to generate electricity. They
also participated in short- and long-term bilateral contracts for electric power
in order to meet changes in demand and demand growth, respectively.
2.1.4 Treatment of Qualifying Facilities (QFs)
With the exception of those with fixed price contracts, most other California
QFs are currently compensated under a Transition Formula that calculates the
Short Run Avoid Cost (SRAC) of each of California's three major IOUs. This
formula links changes in utility SRAC directly to changes in the price of
natural gas. However, the formula approach to estimating utility avoided costs
is unlikely to last much longer. The California Public Utilities Commission
(CPUC), which has the regulatory authority to determine SRAC, in Decision 96-12-
028, stated its intention to change the formula to one based on the California
PX price once certain conditions are satisfied. These conditions are that the PX
is functioning properly and that either the IOUs have divested 90 percent of
their gas-fired fossil generation, or the fossil-fired generation units owned
directly or indirectly by the IOUs are recovering all of their going forward
costs from PX based prices. HESI believes these conditions will be met by the
beginning of 2000.
2.2 CALIFORNIA MUNICIPAL UTILITIES AND AUTHORITIES
While it is anticipated that municipal utilities and other governmental
authorities will participate in the PX and ISO, there is no regulatory
requirement for them to do so. The largest municipal utilities are the Los
Angeles Department of Water and Power (LADWP) and the Sacramento Municipal
Utility District (SMUD), which in combination own or control over 15,000 MW of
generating resources. To date, they have not announced plans regarding their
participation nor have they submitted their transmission resources to ISO
control. The Imperial Irrigation District has also not as yet announced plans to
relinquish its transmission system to ISO control.
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2.3 SYSTEM RELIABILITY
The ISO is the entity responsible for the security and operating reliability of
the statewide electric grid. In this function, the ISO will adhere to the North
American Electric Reliability Council (NERC) and Western Systems Coordinating
Council (WSCC) standards for reliable operation.
In the near term, the new market is designed to accommodate this centralized,
third-party control structure through the combined use of two mechanisms. One is
the ISO-conducted, competitive auction for eligible ancillary services, such as
operating (spinning and non-spinning) reserve, replacement reserve, and
regulation capacity that can be controlled electronically by the ISO.
The other mechanism available to the ISO for procurement of generating services
is the use of long-term contracts with generating facilities that are designated
as "reliability Must-Run" facilities. A Must-Run facility refers to an IOU
generation plant that has a contract with the ISO for the purposes of
maintaining system reliability. These contracts provide for a capacity payment
to the owners during all, or part, of the Transition Period.
As with the ancillary service auction, the ISO will use reliability Must-Run
contracts to obtain operating reserve, replacement reserve, "black start"
capability, voltage support, and regulation capacity. The prices established in
these must-run contracts are unrelated to PX market prices. Instead, they are
based on the actual costs of the generating units under contract. Most of the
IOU-owned generators in California were declared must-run by their owners. The
ISO will examine each must-run contract during the Transition and retain those
required for system reliability. The ISO's use of must-run contracts through the
Transition Period was authorized by AB 1890. Service procured under must-run
contracts will be replaced by those procured competitively after the end of the
AB 1890-specified Transition Period.
2.4 THE CALIFORNIA PX
The PX is responsible for managing the transactions for all power auctioned
through, and purchased by, market participants except those bound by contract.
It was mandated by AB 1890 and set-up as a private,
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non-profit corporation subject to regulation by FERC. The different auctions
include the Day-ahead Market, Hour-ahead Market, Real-time Market, and an
Ancillary Services Market.
The Day-ahead Market is the most forward-looking of the scheduled markets, and
is the largest in terms of total volume. It will give participants the
opportunity to buy and sell energy for each hour of the 24-hour trading day on a
day-ahead basis.
The Hour-ahead Market is also a forward-looking, scheduled market, but its scale
is much smaller in terms of both ahead-time and total volume. It will give
participants the opportunity to adjust their schedules two hours before the hour
of operation.
The Real-time Market is dramatically different from the scheduled Day-ahead and
Hour-ahead markets, in that it is not forward-looking. Rather, it seeks to
balance the real-time differences actually experienced between scheduled and
metered values for load and generation.
2.4.1 California PX Prices
Actual monthly average California PX prices are shown in Table 2-2 below. While
monthly average prices reveal some of the variation in power prices that
occurred in 1998, a truer depiction of the actual variability in prices day to
day, and even within a day, are displayed in Figure 2-1. The Figure shows actual
high, low and average prices in the California PX Day-ahead market throughout
1998 and for the first two weeks of January 1999. The average daily price is
highlighted in bold and the high/low range for the day is depicted by the length
of the gray-shaded vertical line.
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Table 2-2
Monthly Average California PX Prices-
April 1998 to January 1999
($/MWh)
<TABLE>
<CAPTION>
Month On-Peak Off-Peak Average
- --------------------------------------------------------------
<S> <C> <C> <C>
April, 1998 26.84 18.55 22.60
- --------------------------------------------------------------
May 17.37 6.92 11.49
- --------------------------------------------------------------
June 16.97 7.43 12.09
- --------------------------------------------------------------
July 40.61 24.39 32.42
- --------------------------------------------------------------
August 54.27 27.38 39.53
- --------------------------------------------------------------
September 42.18 26.19 34.01
- --------------------------------------------------------------
October 30.81 22.91 26.65
- --------------------------------------------------------------
November 29.45 22.50 25.74
- --------------------------------------------------------------
December 33.50 24.87 29.13
- --------------------------------------------------------------
January, 1999 24.78 17.81 20.96
- --------------------------------------------------------------
</TABLE>
Note: On-peak is defined as the weekday hours between the 7:00 A.M. and
11:00 P.M. Off-peak consists of the hours between 11:00 P.M. and 7:00
A.M. on weekdays and all hours during weekends and holidays.
2.4.2 Short Run Avoided Costs
All QFs are compensated on the basis of the SRAC of the IOU purchasing the
power. The Project currently receives payment under the SRAC "Transition
Formula" for Southern California Edison (SCE). This "formulaic" SRAC is a linear
function of the price of natural gas as measured at the "California Border."
Table 2-3 presents a forecast of the annual average SRAC price, as computed
pursuant to the existing SRAC Transition Formula for SCE. The gas prices
(southern California border prices) used to make this calculation are the same
as the long term gas price forecast used in the HESI model to produce the Base
Case MCP forecast.
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Figure 2-1
California PX Daily Prices - High, Low and Average
(GRAPHIC APPEARS HERE)
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Table 2-3
SCE Annual Average
Short-Run Avoided Costs of Energy
<TABLE>
<CAPTION>
Price of Gas SCE SRAC
YEAR ($/MMBtu) ($/MWh)
- ---------------------------------------------------------------
<S> <C> <C>
1999 2.39 29.5
- ---------------------------------------------------------------
2000 2.49 32.4
- ---------------------------------------------------------------
2001 2.59 33.4
- ---------------------------------------------------------------
</TABLE>
Note: The SRAC prices shown are weighted averages with the weights based
on the number of hours in each "time-of use" period as defined by Southern
California Edison. The 1999 estimate consists of actual values to April
and forecast values thereafter.
While HESI has estimated SCE SRAC prices through 2001, we believe, however, that
competitive-based PX pricing will replace the SRAC as early as the beginning of
2000. Appendix D shows monthly time of day SRAC estimates for the same time
period. Also in Appendix D are revised monthly SRAC price estimates using a more
up-to-date short-term monthly gas price forecast.
2.5 PX PRICES AS A MEASURE OF AVOIDED COST
The SRAC Transition Formula is expected to be in effect until several conditions
are met. One condition is the divestiture by California IOUs of their California
fossil-fired generation, a process expected to be completed in the next twelve
months. The other is a determination by the CPUC that the PX market is
"functioning properly." Currently, PX operations are being gradually phased in.
Once complete, the CPUC will likely wait several more months before determining
whether the PX is functioning properly - a determination which could be subject
to several more months of regulatory delay. However, if PX market prices are
substantially below Transition Period SRAC prices, utilities will be motivated
to seek a change in SRAC pricing more quickly. PX prices have been substantially
lower than SRAC prices for the most part. HESI's MCP forecasts support the
notion that annual average PX prices will likely continue to be lower than SRAC
prices throughout the Transition Period. Given the above considerations, the
change from the Transition Formula pricing to PX pricing should occur at the
beginning of 2000.
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ELECTRICITY MARKET AND PRICE FORECAST
1999 - 2009
3 SOUTHERN CALIFORNIA MCP FORECAST: KEY ASSUMPTIONS AND METHODOLOGY
- -------------------------------------------------------------------------------
3.1 MODELING METHODOLOGY AND TECHNIQUES
To develop a forecast of market clearing prices for the Southern California
Transmission Area, simulation of the entire Western Systems Coordinating Council
(WSCC) electrical system was required. Such a simulation requires a vast amount
of data regarding power plants, fuel prices, transmission capability and
constraints, and customer demands.
HESI utilizes its proprietary Electric Market Simulation System (EMSS) and its
MULTISYM(TM) production cost model to simulate the operation of the WSCC. EMSS
is a sophisticated application of relational database technology, which operates
in conjunction with a state-of-the-art, multi-area, chronological, production
simulation model. It is used to manage the tens of thousands of individual data
points necessary to properly characterize the WSCC electric system for the
forecast.
The types of data managed by the EMSS database include the data necessary to
correctly consider the configuration of the regional transmission system. This
includes:
. individual power plant characteristics;
. transmission line interconnections, ratings, losses, and wheeling rates;
. forecasts of resource additions and fuel costs; and
. forecasts of loads for each utility in the region.
MULTISYM(TM) simulates the operation of the individual generators, utilities and
control areas (also referred to as transmission areas) within the region, taking
into consideration various system and operational constraints. Output from the
simulation is generated in hourly, station-level detail and provided in database
format. This data may then be aggregated and sorted for any level of aggregation
required by the user.
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3.2 ASSUMPTIONS REGARDING THE CALIFORNIA MARKET TRANSITION PERIOD
It is assumed during the Transition Period that the market will consist of a
limited number of generators that will be required to operate competitively in
the market. AB 1890-mandated regulatory Must-Take generation and regulatory
Must-Run contracts provide for the continuation of capacity payments through the
Transition Period. Must-Take includes power from QF resources, nuclear units,
and existing purchase power agreements that have minimum-take provisions. Must-
Take units not subject to competition are scheduled with the ISO on a must-take
basis. Must-Take units owned by municipal and public power agencies are assumed
to continue operating as they did in the past.
Units identified on the ISO's Must-Run contract list will end up with one of
three types of Must-Run contracts - A, B, or C. This study assumes that most
Must-Run contracts will be Must-Run "B". This type of contract allows generators
to cover their fixed costs of operation through a payment by the ISO. Those
units that do not sign the "B" contract and remain on an "A" contract will
generally be those that are must-run or follow load, such as hydroelectric.
There will also be few Must-Run "C" contracts. These contracts require that the
units be dedicated to the ISO in exchange for full cost recovery, but do not
allow the unit to bid independently into the market. The ISO has the right to
terminate any Must-Run contract it deems unnecessary on 90-days notice.
Since a majority of the generating units both inside and outside of California
will generally continue to bid to the PX just above their variable cost of
production until the end of the AB 1890 specified Transition Period, we assume
that the PX closely resembles a variable cost pool in the near term. At the end
of the Transition Period, fixed costs will also be recovered through the PX.
Thus, a relatively small number of units will be exposed to full competition
during the Transition Period.
We have forecasted the Must-Run contracts to impact the market through the end
of 2001 by putting downward pressure on PX prices. The Must-Run contract
payments cover much of the generators' costs by allowing fixed costs to be
recovered through the ISO. Thus, these generators will not require higher PX
prices to recover their fixed costs. When the contracts terminate during, or at
the end of, the Transition Period, all generators will be required to recover
their costs through normal,
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competitive trading activities. The model takes into account the phasing out of
the Must-Run contracts in the Transition Period, resulting in an increase in PX
prices.
3.3 KEY ASSUMPTIONS FOR MODELING THE WSCC POWER MARKET
3.3.1 Forecast Horizon
The forecast period covers a twenty-year period beginning January 1, 2000 and
ending December 31, 2009.
3.3.2 Market Structure
It is assumed that all generators in the WSCC, except a few in California that
were not declared Must-Run, receive some payment for capacity through 2001, the
end of the Transition Period specified in AB 1890. From 2002 through 2009 there
are no capacity payments to the California generators. We assume non-California
generators will continue to operate with regulated tariffs and capacity payments
from 2002 through 2004. We believe the market will become fully competitive by
2005 and, from that point forward, all generators will need to recover capacity
costs through the market.
3.3.3 Existing Resource Base
All existing generation units within the WSCC are included in the analysis.
HESI's database contains information regarding all such units and their
performance characteristics. This data has been updated to reflect the most
recent filings made by utilities regarding their resources. Much of this data
was taken from the "OE-411" and is current as of January 1, 1997. Generation
resource data were also supplemented by a review of specific utility resource
plan filings and reports generated by state agencies. Existing resources are
assumed to continue operating through the forecast horizon, except for those
resources that have specific retirement dates or assumed retirements.
3.3.4 Resource Retirements
We have conservatively estimated the retirements to be only those publicly
announced, except in the case of the nuclear units. Recent CPUC decisions on
rate recovery allow California utilities to recover investments in nuclear
plants on an accelerated schedule. Investments in Diablo Canyon and Palo Verde
will therefore be fully recovered by the end of 2001 and San Onofre by the end
of 2003. After this special rate treatment
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1999-2009
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period ends, these plants must compete individually. All costs will have to be
recovered in the competitive energy market. HESI believes that Diablo Canyon and
San Onofre will not be competitive in the new environment and so will be shut
down shortly after their investments are recovered, in 2001 and 2003
respectively. Palo Verde is assumed to operate throughout the forecast period.
3.3.5 Generic Resource Additions
HESI believes that gas-fired combined cycle units (CC) and gas-fired combustion
turbines (CT) will be added as needed to meet the projected increase in customer
demand over the forecast period. HESI's analysis assumes that generation
resources will be added over the forecast period in a 3 CC MWs to 1 CT MW ratio
for all trans-areas.
Table 3-1 lists the cost and performance assumptions for these resources.
Table 3-1
Generic Resource Characteristics (1996 dollars)
<TABLE>
<CAPTION>
Combustion
Unit Characteristic Turbine Combined Cycle
- --------------------------------------------------------------------------
<S> <C> <C>
Capacity (MW) 120 240
- --------------------------------------------------------------------------
Heat Rate (Btu/kWh) 11,000 7,100
- --------------------------------------------------------------------------
Fixed O&M ($/kW- year) 3.00 10.00
- --------------------------------------------------------------------------
Variable O&M (dollars/MWh) 4.00 2.00
- --------------------------------------------------------------------------
Forced Outage Rate (%) 0.00 2.00
- --------------------------------------------------------------------------
Maintenance Outage Rate (%) 4.00 4.00
- --------------------------------------------------------------------------
</TABLE>
3.3.6 Loads
HESI is using the latest available data to project future customer demand and
energy requirements. This data was filed electronically by the utilities with
the Federal Energy Regulatory Commission (FERC) early in 1997, and represents
each utility's most recent recorded historic loads and their most recent load
forecast data. HESI has used data approved by the California Energy Commission
in its 1996 Electricity Report for the California utilities.
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3.3.7 Load Shape
The load shape is based on recent historic load data filed with the FERC by
utilities which reflects their complete hourly loads over calendar years 1993
through 1996. HESI has used these load shapes to create a load shape consistent
with the load forecasts provided by utilities. These "synthetic" load shapes are
used to project the shapes of future utility loads based on the load growth data
described in section below.
3.3.8 Load Growth
Based on the load forecasts filed with the FERC in 1996 under Form 714 and on
more recent information filed to state regulatory agencies, including California
ER96, peak demand and energy requirements for the entire WSCC are expected to
both grow at less than 2 percent per year through the study.
3.3.9 Inflation
General inflation drives a number of cost elements that underlie power market
prices, including operations and maintenance (O&M) costs and the cost of new
resource additions. General inflation is combined with expectations of real
price escalation in order to forecast future fuel prices. For this study
inflation was assumed to be 3.0 percent per year.
3.3.10 Fuel Prices
There are two principal fuels that drive electricity prices in the WSCC region -
- - natural gas and coal.
3.3.11 Natural Gas
Introduction
- ------------
Gas-fired generators are dispatched according to the cost of natural gas at the
burner-tip. HESI models gas burner-tip prices as the sum of the commodity
price - the cost of gas at a particular producing area, and all relevant
transportation charges involved in transporting it from the supply basin to the
generation plant.
Two of the major natural gas producing areas that supply natural gas to power
generators in the WSCC are the Western Canada Sedimentary Basin (WCSB), which is
located mainly in Alberta, Canada and the San Juan Basin, situated mainly in New
Mexico.
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Although generators within the WSCC sometimes use gas from other basins, HESI
assumes that only one gas basin will set the key marginal gas price for each
generator. Generating stations in New Mexico, Southern Nevada, Arizona, and
Southern California are supported by the San Juan Basin. The WSCB basin is
assumed to supply generating stations within Alberta and British Columbia.
Alberta also supplies electric generators located in Washington, Oregon, Idaho,
Montana, Wyoming, Utah, Northern Nevada, and Northern California.
The HESI methodology assumes therefore that the burner-tip gas price for each
gas-fired generation plant will depend mainly on its location relative to the
supply basins that are accessible to it and the cost of shipping gas from those
basins to the plant. The commodity and transportation components of natural gas
burner-tip prices are forecast separately and then added together to derive the
prices paid by generation plants appropriate to their geographic location. A
description of commodity and transportation cost forecast methodology is
presented in more detail below.
Gas Commodity Price Forecast Methodology
- ----------------------------------------
HESI utilizes a "Delphi" approach to forecasting gas commodity prices. That is,
HESI collects various recent expert forecasts of Alberta and San Juan commodity
prices and generally takes the simple average as the Base Case forecast.
The expert sources for the Alberta commodity price forecast are the "Natural Gas
Market Outlook" by the California Energy Commission (CEC), "Annual Energy
Outlook 1998 with Projections to 2020" by the Energy Information Administration
(EIA), and "Natural Gas: Review of 1997 and Outlook to 2005", from Natural
Resources Canada (NRCan)./4/ The NRCan report itself contains a survey of
Alberta commodity gas prices from various sources. The prices in the NRCAN
survey, combined with the CEC forecast, constitute the consensus from which the
HESI Base Case forecast is derived for the years 1998 to 2005.
- --------------------
/4/"Natural Gas Market Outlook," California Energy Commission, June 1998;
"Natural Gas: Review of 1997 and Outlook to 2005," Natural Gas Division, Natural
Resources Canada, May 1998; "Annual Energy Outlook 1998 with Projections to
2020," Energy Information Administration, Department of Energy, December 1997.
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1999-2009
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Figure 3-1 shows the Alberta commodity price forecasts contained in the NRCan
report between 1999 and 2005, the CEC forecast, and the HESI Base Case forecast
derived from these sources./5/ From 2006 onward, the HESI Base Case forecast in
2005 is escalated according to the average of growth rates of the CEC's Alberta
commodity price forecast and the EIA's average Canadian import gas price
forecast. The EIA's forecast is therefore not directly shown in Figure 3-1, but
appears indirectly as a contributor to the projected growth rate of the HESI
forecast.
Figure 3-1
Alberta Gas Commodity Price Forecasts
[GRAPH APPEARS HERE]
The sources for the San Juan commodity price forecast are again the CEC's
"Natural Gas Market Outlook" and the EIA's "Annual Energy Outlook. The HESI Base
Case forecast is derived by averaging the CEC
- -------------------
/5/In Figure 3.1, ARC refers to the ARC Financial Corporation, a Calgary-based
oil and gas investment advisor. PIRA is the PIRA Energy Group, a New York-based
petroleum industry research firm and CERI is the Canadian Energy Research
Institute.
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1999-2009
- --------------------------------------------------------------------------------
and EIA forecasts in all years between 1998 and 2020./6/ These forecasts are
shown in Figure 3-2.
Figure 3-2
San Juan Gas Commodity Price Forecasts
[GRAPH APPEARS HERE]
Factors Affecting Future Gas Commodity Prices
- ---------------------------------------------
Natural Gas consumers in California and other Western states have enjoyed
relatively inexpensive natural gas commodity prices for a number of years. The
main reasons have been intense competition among gas producers to maintain or
expand market share and slower than anticipated demand growth in California.
Although both Alberta and the San Juan areas are major suppliers of natural gas
to the WSCC, both regions currently suffer from a lack of take-away capacity.
Consequently, producer prices, or netbacks, have been relatively weak compared
to prices received by producers in other producing regions, particularly the
Louisiana and Anadarko producing regions, which have access to large markets in
the Midwest and the Eastern U.S. However, most forecasters expect this situation
to change in the near future, particularly in Alberta's case, due to pipeline
capacity expansions that are either in-progress or
- --------------------
/6/ The CEC forecast shown is actually the current actual San Juan price
escalated according to the forecast annual average real growth rate contained in
the CEC forecast.
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planned over the next few years. As a result, expert opinion, such as the CEC,
the EIA and NRCan, expect commodity prices in these regions to increase at rates
that are above price rises projected for most other producer basins.
Accordingly, the HESI Base Case forecast assumes that Alberta and San Juan based
gas commodity prices will increase over the long term at average annual real
rates of 1.8 and 1.6 percent respectively. In comparison, the consensus opinion
is that Gulf Coast prices will increase, on average, in the range of 1 percent
per year over the long term. The following sections discuss developments in the
Alberta and San Juan producing regions that are likely to impact on gas prices
paid by generation plants in the WSCC.
Pipeline capacity in the San Juan basin was developed in the late 1980s to serve
the California market. However, the expected growth in demand never really
materialized. As a result, the region has suffered from excess capacity.
Currently, producers are attempting to expand deliverability eastward. According
to the EIA, the two major intestate pipelines in the area, Transwestern and El
Paso Natural Gas, are expanding facilities which would allow them to direct more
production to the market centers in Southwestern Texas, which would then allow
San Juan producers access to Midwest and Northeast markets./7/
Although TransCanada Pipeline, the major pipeline link between Canadian
producers and eastern U.S. markets, has increased domestic deliverability the
last few years, significant constraints still prevent Alberta producers from
fully accessing these markets. However, a number of projects are planned that
will greatly improve export capability. The most notable of these is the
Alliance project, which would tie Alberta and British Columbia producers
directly to the Chicago market. Also, Great Lakes Gas Transmission and Iroquois
Transmission plan to expand their systems in the Midwest and the Northeast
respectively. Finally, Foothills Pipe Line Ltd. and the Northern Border Pipeline
have obtained approval to expand export capability at the Montana border./8/
- --------------------
/7/"Deliverability on the Inter-state Natural Gas Pipeline System," Department
of Energy, Energy Information Administration, May 1998, page 125.
/8/IBID, page 126-127.
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Implications for the WSCC Region
- --------------------------------
Although the planned pipeline capacity expansions in the San Juan and Alberta
producing regions do not directly affect the volumes flowing to California and
other Western U.S. states, the impact will nonetheless be significant. This is
because generation plants in the WSCC will face greater competition for Alberta
and San Juan produced natural gas from bidders in other market regions.
The Alberta commodity price is therefore expected to rise towards prices in U.S.
markets as Alberta supply becomes more tightly linked to prices in the U.S. For
example, the EIA long term forecast expects Canadian import prices to increase
at about 1.5 percent per year in real terms from 1998 to 2020, while Gulf Coast
prices are projected to increase at only 0.8 percent real over the same period.
Similarly, Southwest prices, which include San Juan, increase at about 1.0
percent per year, somewhat above the U.S. wellhead average price forecast by the
EIA.
Following a similar analysis, the CEC expects both San Juan and Alberta
commodity prices to increase at 2 percent per year in constant dollars. In
comparison, prices in the Gulf Coast and Rocky Mountain regions increase at
about 1 percent per year. Table 3-2 shows projected commodity price growth rates
from the CEC and EIA source documents and the HESI Base Case growth rates,
which, as described, are derived from these projections. The HESI gas commodity
price forecast is shown for selected years in Table 3-3 on the accompanying
page.
Table 3-2
Projected Gas Commodity Price Growth by Producer Basin
(Average Annual Real Percent Change)
<TABLE>
<CAPTION>
CEC EIA HESI Base
Producing Region 1999 - 2019 1998 - 2020 1999 - 2009
- --------------------------------------------------------------------------------------
<S> <C> <C> <C>
Henry Hub (Gulf Coast) 1.3% 0.8% NA
- --------------------------------------------------------------------------------------
Rocky Mountain 1.0% 1.5% NA
- --------------------------------------------------------------------------------------
Permian (SW Texas) 1.9% 1.0% NA
- --------------------------------------------------------------------------------------
Anadarko (mid-continent) 1.9% 0.8% NA
- --------------------------------------------------------------------------------------
San Juan (New Mexico) 2.0% 1.0% 1.6%
- --------------------------------------------------------------------------------------
Alberta (Canadian Imports) 2.0% 1.5% 1.8%
- --------------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
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1999-2009
- --------------------------------------------------------------------------------
Table 3-3
HESI Base Case San Juan and Alberta
Commodity Price Forecast
$98/MMBtu
<TABLE>
<CAPTION>
San Juan Alberta
- -----------------------------------------------
<S> <C> <C>
1999 2.17 1.50
- -----------------------------------------------
2000 2.20 1.57
- -----------------------------------------------
2001 2.22 1.63
- -----------------------------------------------
2002 2.24 1.68
- -----------------------------------------------
2003 2.27 1.70
- -----------------------------------------------
2004 2.30 1.74
- -----------------------------------------------
2005 2.33 1.78
- -----------------------------------------------
2010 2.54 1.94
- -----------------------------------------------
2015 2.74 2.03
- -----------------------------------------------
2009 2.86 2.11
- -----------------------------------------------
</TABLE>
The Estimation of Monthly Natural Gas Prices
- --------------------------------------------
HESI converts the Base Case annual average forecast of gas commodity prices to
monthly prices using a set of estimated monthly (seasonal) factors. These
factors are held constant throughout the forecast. The monthly factors are
derived from historical monthly average 30-day spot prices reported in the
Weekly Gas Price Index and published by Natural Gas Intelligence. In particular,
HESI estimates a set of "normalized" monthly factors that attempt to portray
typical or normal variation in gas prices. The annual San Juan commodity gas
price is converted to monthly prices using estimated monthly variation at
Topock - which represents the market pricing point for most natural gas
purchases in Southern California, Arizona, and Southern Nevada. Alberta-based
annual commodity prices are converted to monthly prices using estimated monthly
variation at Malin - a major pricing point for gas purchases in Northern
California, Oregon, and Northern Nevada.
The details of the estimation procedure are discussed with reference to Figure
3-3 below, which shows actual and estimated monthly variation in gas spot
prices, in ratio form, at Topock. Ratio form is defined here as the average of
actual monthly prices relative to the annual average price for all similar
months, using historical data from January 1991 and October 1998. In other
words, the January actual price shown in Figure 1-3 represents the average of
all January to annual ratios between 1991 and 1998. The ratios
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therefore represent the typical or average variation in monthly prices relative
to the annual average price observed at Topock over the last eight years.
Figure 3-3
Actual and Estimated Monthly Gas Price Variation at Topock
[GRAPH APPEARS HERE]
As a final step, the observed average variation is smoothed according to a
polynomial curve that is fitted by least squares regression. The smoothed
monthly factors are then adjusted slightly so that their average is equal to
unity. As the chart shows, in the case of Topock, most of the adjustment is
added to the January estimate - since the fitted line underestimates actual
variation in this month. An identical procedure is applied to the forecast of
annual average Alberta prices using historical monthly price variation at Malin.
Gas Transportation Price Methodology
- ------------------------------------
Pipeline transportation costs are added to basin prices to determine city-gate
gas prices. The city-gate is defined as the point of delivery from inter-state
transmission pipelines to Local Distribution Company (LDC)
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systems. Transportation costs can potentially consist of both inter-state
transmission charges and LDC costs. However, for most generators, city-gate
prices are the relevant marginal gas costs used to "dispatch" their electric
systems, either because the generation owners receive service directly from
pipelines or pay only nominal additional charges to an LDC. In other areas,
additional charges for intra-state or LDC transportation must be added to yield
the dispatch price of gas.
The forecasts of inter-state transportation costs in the HESI model reflect
historic differences between city-gate prices and commodity prices from the
respective gas supply basins. Additionally, the monthly price profile of the
referenced city-gate is used to approximate the monthly variation in gas
transportation costs arising from fluctuations in shipper volumes.
Local Distribution Company Charges
- ----------------------------------
The key generators receiving LDC gas transportation service are California's
electric generators. Thus, for these generators, LDC charges, based on LDC
tariffs, are added to the California border price./9/ Generators situated in
Northern California are assumed to purchase gas at prices equivalent to the
Northern California border price and generators situated in Southern California
purchase gas at prices that reflect the Southern California border. The Alberta
commodity price plus transportation costs to Malin, Oregon, (located just north
of the California border) constitutes the Northern California border price. The
San Juan commodity price plus transportation to Topock (south of Needles,
California near the California-Arizona border) represents the Southern
California border price.
The LDC charges are based upon estimates of actual 1996 charges and are held
constant in real dollars at these levels through the study horizon.
Historically, with the majority of generation owned by utilities, much of the
fixed cost of gas transportation would be included in fixed cost components of
electric retail customer rates, resulting in only a small portion of such gas
transportation being recognized in daily and hourly generation dispatch
decisions. This practice tended to reduce the assumed marginal generation cost
for an individual generation unit dispatch decision. In a competitive market,
buyers and sellers will determine what costs can be recovered and so generators
will not be able to rely upon
- --------------------
/9/The California border price is similar in some respects to a city-gate price
in that it represents the price of natural gas at a point where an inter-state
transmission line connects to an LDC distribution pipeline.
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regulated rates to automatically recover fixed costs of gas transportation.
Therefore, the full cost of gas transportation will need to be recovered from
energy sales, or generators will face the possibility of under-recovery of gas
transportation costs, which cannot be sustained on a long-term basis. This
change is expected to have some upward pressure on market clearing prices and is
reflected in the HESI market clearing price model.
Total Gas Costs
- ---------------
Table 3-4 summarizes much of this section's discussion. It shows the
relationship between generator location, producer basin and the city-gate. For
example, for generators in the Northwest, excluding the Seattle area, the
referenced basin is Alberta and the city-gate price consists of the Alberta
commodity price plus inter-state transportation costs to the market hub at
Stanfield, Oregon. In the case of generators located in the service territory of
Southern California Edison, the burner-tip price consists of the San Juan
commodity price, inter-state transportation costs from the San Juan producer
region basin to the Southern California border, near Topock, and finally LDC
charges on the SCE transmission system from Topock to the burner-tip.
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Table 3-4
HESI Base Case Natural Gas City-Gate Price Forecast
$1998/MMBtu
<TABLE>
<CAPTION>
Generation PNW- North South
Location Alberta B.C. Coastal PNW NV NV PG&E
- -----------------------------------------------------------------------------------------
Commodity
Basin WCSB WCSB WCSB WCSB WCSB San Juan WCSB
- -----------------------------------------------------------------------------------------
Referenced
Market PGE
Hub/City- City-
gate AECO-C Sumas Sumas Stanfield Malin South NV gate
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1999 1.50 1.71 1.71 1.80 1.97 2.33 2.15
- -----------------------------------------------------------------------------------------
2000 1.57 1.78 1.78 1.87 2.04 2.36 2.22
- -----------------------------------------------------------------------------------------
2001 1.63 1.84 1.84 1.93 2.10 2.38 2.28
- -----------------------------------------------------------------------------------------
2002 1.68 1.89 1.89 1.98 2.15 2.40 2.33
- -----------------------------------------------------------------------------------------
2003 1.70 1.91 1.91 2.00 2.17 2.43 2.35
- -----------------------------------------------------------------------------------------
2004 1.74 1.95 1.95 2.04 2.21 2.46 2.39
- -----------------------------------------------------------------------------------------
2005 1.77 1.98 1.98 2.07 2.24 2.49 2.42
- -----------------------------------------------------------------------------------------
2010 1.94 2.15 2.15 2.24 2.41 2.70 2.59
- -----------------------------------------------------------------------------------------
2015 2.03 2.24 2.24 2.33 2.50 2.90 2.68
- -----------------------------------------------------------------------------------------
2020 2.18 2.39 2.39 2.48 2.65 3.13 2.83
- -----------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Generation Rocky Mt
Location SCE Coolwater SDGE AZ/NM Rocky Mt -Colo.
- -----------------------------------------------------------------------------------------------
Commodity San San San San
Basin Juan Juan Juan Juan WCSB San Juan
- -----------------------------------------------------------------------------------------------
Referenced
Market SCE SCE SCE
Hub/City- City- City- City-
gate gate gate gate AZ/NM Opal Denver
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1999 2.32 2.32 2.32 2.31 1.78 2.17
- -----------------------------------------------------------------------------------------------
2000 2.35 2.35 2.35 2.34 1.85 2.20
- -----------------------------------------------------------------------------------------------
2001 2.37 2.37 2.37 2.36 1.91 2.22
- -----------------------------------------------------------------------------------------------
2002 2.39 2.39 2.39 2.38 1.96 2.24
- -----------------------------------------------------------------------------------------------
2003 2.42 2.42 2.42 2.41 1.98 2.27
- -----------------------------------------------------------------------------------------------
2004 2.45 2.45 2.45 2.44 2.02 2.30
- -----------------------------------------------------------------------------------------------
2005 2.48 2.48 2.48 2.47 2.05 2.33
- -----------------------------------------------------------------------------------------------
2010 2.69 2.69 2.69 2.68 2.22 2.54
- -----------------------------------------------------------------------------------------------
2015 2.89 2.89 2.89 2.88 2.31 2.74
- -----------------------------------------------------------------------------------------------
2020 3.12 3.12 3.12 3.11 2.46 2.97
- -----------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
</TABLE>
3-15
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THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- --------------------------------------------------------------------------------
Coal
- ----
HESI bases its coal prices on historic power plant specific coal price data
extracted from the "Form 423's" utilities regularly file with the FERC. The Form
423 data include historic consumption as well as both spot and average
(transportation and so-called fixed fees included) prices. Given the competitive
nature of fuel supply markets and the current pricing of coal relative to gas,
HESI expects no coal price escalation through the forecast period. HESI used
spot coal prices to simulate the economic operation of coal plants. Spot prices
are historically about 77 percent of average prices.
3.3.12 Operations & Maintenance
Power plant specific non-fuel O&M costs are reported by utilities in annual
reports to the FERC in a number of separate accounts. HESI averages these data
for the 1991 through 1995 time periods (normalized for constant year dollars) to
develop average starting O&M costs. The amounts in these various accounts are
then allocated between fixed and variable O&M. To derive a unit's fixed O&M
cost, the total O&M cost is decreased by the variable O&M cost component. Both
fixed and variable O&M costs are assumed to escalate with inflation.
3.3.13 Property Taxes
Property taxes are set by local jurisdiction and so vary throughout the WSCC. In
California they are 1.09 percent of remaining generation station book value. In
other jurisdictions, the rates range from 0.4 percent to approximately 4
percent. For purposes of establishing the property tax component of going
forward costs, jurisdictional tax rates will be used.
3.3.14 Insurance
Insurance is calculated as 0.2 percent of the remaining, undepreciated book
value of the power plant.
3.3.15 Other Costs
In addition to fuel costs, a power plant operator experiences other costs
associated with the on-going business of producing power. These costs include
O&M, property taxes and insurance. For the most part, these costs can be avoided
if a facility is "mothballed" or retired, and thus are included in power plant
bids when performing competitive market analysis.
- --------------------------------------------------------------------------------
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THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
3.4 WSCC TRANSMISSION SYSTEM CONFIGURATION
In order to perform a study of the Southern California market prices likely to
result from the PX, the operation of the transmission system in the entire WSCC
region must be modeled. The transmission system configuration for this study is
shown in Figure 3-4. This characterization reflects the zones proposed by the
California IOUs in their PX applications to FERC.
Figure 3-4
WSCC Transmission System Configuration
[GRAPHIC APPEARS HERE]
3.5 HYDRO POWER
3.5.1 Median Year Case
HESI utilized average or median hydro conditions depending on the WSCC sub-
region and the data available. The sources for these data follow.
- -------------------------------------------------------------------------------
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<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Pacific Northwest (PNW) Hydro Data
- ----------------------------------
The hydroelectric generation in the PNW accounts for almost half of the hydro
generation in the entire WSCC. HESI used the Bonneville Power Administration's
(BPA) 1996 Pacific Northwest Loads and Resources Study to update hydroelectric
data in the PNW. HESI calculated monthly capacity and energy values for each
hydroelectric station in the PNW based on this data, choosing the median
conditions from a recorded database of 50 years.
Hydro Data for Other Regions
- ----------------------------
Hydro data for the other regions come from a number of sources and are updated
periodically by HESI.
The WSCC Coordinated Bulk Power Supply Program document was used for the
majority of the plant capacity data for plants outside the Northwest. This
document is the WSCC's response to the Department of Energy's Form OE-411. It
includes summer and winter capacity ratings for all of the existing hydro and
thermal resources in the WSCC.
The McGraw Hill Electrical World Directory of Electric Utilities (The
"Bluebook") was the source of hydro plant energy data in a number of the WSCC
regions.
3.5.2 Transactions
HESI incorporates known firm, contracted power transactions into its model, as
reported by the WSCC in the annual FERC Form OE-411 Filing. The transactions are
reflected in the load requirements of the buying and selling utilities, in
transactions between regions, and by adjusting the transmission capacity. Any
remaining transmission capacity is used to facilitate additional power
transactions between regions.
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
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<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
4 SOUTHERN CALIFORNIA MCP FORECAST: RESULTS
- -------------------------------------------------------------------------------
The following sections summarize the model results from the Base Case and the
two Low Gas price sensitivity cases. Gas prices are sensitized due to the fact
that gas-burning generators are the marginal cost producers and therefore a
major influence on the MCP in California. Any additional baseload capacity must
therefore be a low cost producer and a price taker. Additional intermediate
capacity will need to be flexible enough to accommodate hourly load
fluctuations. The gas-fired combined-cycle and combustion turbines are the most
flexible technologies to meet these needs cost-effectively. The role of these
units and the impact of gas prices in setting wholesale power prices will
increase over time, making gas the ideal input to vary for sensitivity. To test
this sensitivity two gas price downside cases are developed as described in the
sections below.
4.1 BASE CASE SOUTHERN CALIFORNIA MCP FORECAST, 2000 - 2009
The Base Case annual average MCP forecast for the Southern California
transmission area is presented in Table 4-1.
The annual average MCP increases at an annual average of 12.6 percent per year
between 2000 to 2002. This is the Transition Period during which most market
players bid selling prices into the market which reflect their short run
marginal costs. During this period, most IOU-owned generators receive payments
for capacity from the ISO Must-Run contracts, if in California, or through
traditional tariffs, if outside of California. The capacity payments cease for
most ISO-contracted Must-Run generators by the end of 2001.
After the AB 1890 Transition Period ends in March 2002, the power pool should
cease to behave as a marginal cost pool. We believe California generators will
begin to recover some, though not all, of their fixed costs through their sales
through the PX. However, they will continue to compete with out-of-state
generators that continue to receive capacity payments through their regulated
rates and may continue to bid as if the PX was a marginal cost pool. This change
is reflected in the average annual MCP increasing from $34.13/MWh in 2002 to
$40.35/MWh by
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PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
2005. From 2002 to 2005, California generators are exposed to the competitive
market, but their out-of-state competitors continue to receive capacity
payments. The average power price increases at an annual average rate of 5.7
percent during this period.
Table 4-1
Base Case Southern California MCP Forecast
2000 - 2009
$/MWh
<TABLE>
<CAPTION>
Average On-Peak Off-Peak
- -------------------------------------------------
<S> <C> <C> <C>
2000 26.93 32.74 21.64
- -------------------------------------------------
2001 28.60 34.62 23.14
- -------------------------------------------------
2002 34.13 41.32 27.60
- -------------------------------------------------
2003 36.17 44.00 29.05
- -------------------------------------------------
2004 37.67 45.53 30.54
- -------------------------------------------------
2005 40.35 49.05 32.45
- -------------------------------------------------
2006 41.63 51.28 32.86
- -------------------------------------------------
2007 42.37 52.20 33.44
- -------------------------------------------------
2008 43.01 52.82 34.09
- -------------------------------------------------
2009 44.27 54.75 34.75
- -------------------------------------------------
</TABLE>
HESI assumes that the entire WSCC will be competitive starting in 2005 and that
the bidding behavior of generators reflects their efforts to recover fixed costs
through sales to the PX. The MCP increases slowly but steadily from $40.35/MWh
in 2005 to $44.27/MWh by 2009 - an average rate of increase of 2.3 percent per
year, which is less than the rate of inflation.
4.2 SENSITIVITY CASES
4.2.1 Low Gas Price Case 1
In the Low Gas Case 1, the gas price decreases each year until it is 10 percent
below the Base Case gas price. It is then held constant at 10 percent below the
Base Case gas price in all remaining years of the analysis. This low gas
scenario, while unlikely, could occur if there was an oversupply of gas, for
which there was no market, followed by a lengthy
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
period of recovery and market demand. The MCP forecast under this assumption is
shown in Table 4-2.
Table 4-2
MCP Forecast under the Low Gas Price Case 1
<TABLE>
<CAPTION>
Base Case Low Gas 1
Sample Annual Average Annual Average Percent Below Base
Year MCP $/MWh MCP $/MWh Case Price
- -------------------------------------------------------------------------
<S> <C> <C> <C>
2000 26.93 25.86 -3.9%
- -------------------------------------------------------------------------
2001 28.60 27.14 -5.1%
- -------------------------------------------------------------------------
2002 34.13 32.15 -5.8%
- -------------------------------------------------------------------------
2003 36.17 33.64 -7.0%
- -------------------------------------------------------------------------
2004 37.67 35.11 -6.8%
- -------------------------------------------------------------------------
2005 40.35 37.75 -6.4%
- -------------------------------------------------------------------------
2009 44.27 40.91 -7.6%
- -------------------------------------------------------------------------
</TABLE>
4.2.2 Low Gas Price Case 2
In the Low Gas Case 2, the Base Case gas price forecast is reduced each year
until it is 15 percent below the Base Case forecast gas price. The Low Gas 2
gas price is then held at a constant 15 percent below the Base Case gas price
for the remaining years of the forecast. This scenario also requires an
oversupply of gas or a dramatic decline in demand followed by a lengthy period
of recovery. The results of this scenario are shown in Table 4-3.
- -------------------------------------------------------------------------------
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Table 4-3
MCP Forecast Under the Low Gas Price Case 2
<TABLE>
<CAPTION>
Base Case Low Gas 2 Percent
Sample Annual Ave Annual Ave Below Base
Year MCP $/MWh MCP $/MWh Case Prices
------------------------------------------------------
<S> <C> <C> <C>
2000 26.93 25.65 -4.7%
- ------------------------------------------------------
2001 28.60 26.85 -6.1%
- ------------------------------------------------------
2002 34.13 31.59 -7.4%
- ------------------------------------------------------
2003 36.17 32.99 -8.8%
- ------------------------------------------------------
2004 37.67 34.22 -9.2%
- ------------------------------------------------------
2005 40.35 36.53 -9.5%
- ------------------------------------------------------
2009 44.51 39.44 -10.9%
- ------------------------------------------------------
</TABLE>
- -------------------------------------------------------------------------------
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PROPRIETARY AND CONFIDENTIAL
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
5 THE PROJECT AND THE CALIFORNIA MARKET
- -------------------------------------------------------------------------------
5.1 Market Analysis Results
This section presents an analysis of the Project and its position in the
competitive California market. It consists of two sets of comparisons: 1) a
comparison of unit operating cost estimates provided by the Project and
operating costs of other types of generation; 2) a comparison of the Project's
operating costs and forecasted Southern California power prices. The latter set
of comparisons were performed using the Base Case and Low Gas Price cases.
The Project is expected to be a very low cost producer in all years of the
study. Table 5-1 lists the average operating costs projected in 2005 for several
categories of generators in the WSCC region, including the Project. We selected
the year 2005 for this analysis as it is the first year in which a fully
competitive market is assumed. According to data provided by the Project
Operator, the average operating cost of the Project in 2005 is $10.8/MWh.
Therefore, we estimate that about 70 percent of the electricity produced in the
WSCC in 2005 will be generated from units with higher costs, a strong indication
that the Project would be dispatched as baseload if the Project was operating
without a PPA. Of all the generation in the region, only hydroelectric and wind
generators have lower operating costs.
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Table 5-1
Average Operating Costs by Plant Type in the
WSCC from PROSYM Model Simulation in 2005/10/
<TABLE>
<CAPTION>
Electricity Generation Average Operating Cost
Plant Type (GWh) ($/MWh)/1/
- ---------------------------------------------------------------------------------
<S> <C> <C>
Internal Combustion Engines 62 62.22
- ---------------------------------------------------------------------------------
Gas Turbine 26,177 39.94
- ---------------------------------------------------------------------------------
Geothermal/2/ 18,890 37.49
- ---------------------------------------------------------------------------------
Gas/Cogeneration 21,917 26.85
- ---------------------------------------------------------------------------------
Gas/Combined Cycle 151,804 25.41
- ---------------------------------------------------------------------------------
Other Renewable/3/ 6,737 23.29
- ---------------------------------------------------------------------------------
Steam Plants 335,527 18.21
- ---------------------------------------------------------------------------------
Nuclear 35,885 13.33
- ---------------------------------------------------------------------------------
The Project/4/ 2,310 10.83
- ---------------------------------------------------------------------------------
Wind 3,435 10.45
- ---------------------------------------------------------------------------------
Hydroelectric 246,434 4.91/5/
- ---------------------------------------------------------------------------------
Total 846,867
- ---------------------------------------------------------------------------------
</TABLE>
[1] Cost based on fuel and variable O&M in nominal dollars.
[2] The operating costs of the Geothermal category reflect the fact that many of
the utility-owned geothermal facilities have long term steam contracts with
steam suppliers.
[3] Includes solar, biomass, and other renewable.
[4] Based on cost and production estimates provided by the Project Operator.
[5] Cost based on average aggregated operating expenses of hydroelectric
facilities in the WSCC as reported to FERC on FERC Form 1.
Project operating costs are compared to the Base Case annual average MCP in the
Figure 5-1 below. Inflation of 3 percent per year is embedded in both the price
and cost projections.
- ---------------------
/10/ The table displays operating cost by plant-type for various plant
categories in the Prosym simulation results. The values shown are for the
simulation year 2005 and are stated in nominal dollars. These values
reflect expenses for fuel and variable operation and maintenance only. They
do not include costs associated with fixed operation and maintenance, the
inclusion of which would increase overall costs for some plants
substantially. For example, inclusion of fixed operation and maintenance in
the nuclear category would increase the cost reported in the Table from
$13.33/MWh to $34.00/MWh. In as much as it is presently unclear what
portion of fixed costs will be recovered in the competitive market and
under what conditions, the Table should be viewed as a conservative
representation of the operational costs of these plants.
- -------------------------------------------------------------------------------
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Figure 5-1
Base Case Annual Average MCP and Project Operating Costs
[GRAPHIC APPEARS HERE]
As Figure 5-1 shows, Project operating costs are expected to be well below
HESI's Base Case average annual MCP forecast. In fact, over the 2000 to 2009
period, Project costs are, on average, 69 percent below Southern California
power prices.
Figure 5-2 below compares Project operating costs to the Base Case off-peak
power price forecast. Although off-peak prices are about 25 percent below
average annual power prices, the Project is still very competitive. Project
costs are, on average, 62 percent below Southern California off-peak annual
power prices.
- -------------------------------------------------------------------------------
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Figure 5-2
Base Case Annual Off-Peak MCP and Project Operating Costs
[GRAPHIC APPEARS HERE]
The last analysis compares Project operating costs to off-peak prices in the Low
Gas Price 2 Case, which is the worst-case scenario. Off-peak power prices are
about 27 percent below Base Case average annual power prices. The comparison is
shown in Figure 5-3 below. In this case, Project costs are, on average, 58
percent below off-peak prices.
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Figure 5-3
Low Gas Price Case 2 Annual Off-Peak MCP
and Project Operating Costs
[GRAPHIC APPEARS HERE]
5.2 SOUTHERN CALIFORNIA MCP FORECAST AND THE MARKET POSITION OF THE PROJECT
For an additional perspective of the relative position of the Project in the
market, a table summarizing the frequency of the Southern California power price
forecast is developed. This approach captures more of the hour by hour price
variability than the preceding results. First, the hourly price results from the
Base Case year 2005 are ranked from highest to lowest. From this, the frequency
of price levels (i.e. the percentage of hours in which the price is at, or
above, a given level) is developed. The analysis for 2005 indicates that in 96
percent of the hours the power price is greater than, or equal to, $19.7/MWh.
This means that the Project, with an average operating cost of $10.8/MWh will
be below the average annual MCP more than 96 percent of the time.
- -------------------------------------------------------------------------------
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5-5
<PAGE>
PROPRIETARY AND CONFIDENTIAL
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
Table 5-2
MCP Frequency Analysis in
Southern California Transmission Area, 2005
<TABLE>
<CAPTION>
Minimum MCP
% of Time $/MWh
---------------------------
<S> <C>
70 31.45
---------------------------
75 28.24
---------------------------
80 26.27
---------------------------
85 24.50
---------------------------
90 22.98
---------------------------
95 21.22
---------------------------
96 19.69
---------------------------
</TABLE>
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
5-6
<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
6 THE RENEWABLE RESOURCE FUNDING PROGRAM
- -------------------------------------------------------------------------------
AB 1890 established a $540 million fund to promote and develop renewable energy
projects and directed the CEC to administer and distribute the funds. In
response, the CEC established four separate accounts to deliver these funds over
the period January 1, 1998 to January 1, 2002. Each account has been allocated a
fixed percentage of the total fund and a different distribution mechanism is
used for each account. The four accounts and the amount of funds allocated to
each are shown in Table 6-1.
Table 6-1
AB 1890 Accounts - Total Funding
Allocations by Technology
$Millions
<TABLE>
<CAPTION>
Technology $Millions
----------------------------------------------------------
<S> <C>
Existing Technologies 243
----------------------------------------------------------
New Technologies 162
----------------------------------------------------------
Emerging Technologies 54
----------------------------------------------------------
Consumer-Side 81
----------------------------------------------------------
Total 540
----------------------------------------------------------
</TABLE>
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998.
The "existing" and "new" categories are the most important, accounting for 75%
of the total fund disbursement. Further, these accounts are applicable to the
majority of active or economically feasible renewable energy projects in
California. The distinction between an existing and a new technology is a matter
of vintage. An existing technology refers to a facility that started operation
prior to September 23, 1996 and a new technology means a facility that started
generation on or after September 26, 1996 but before January 1, 2002. The
Project is eligible for funding under the Existing Renewable Resource category.
Existing facilities that are substantially refurbished on or after September 23,
1996 can apply for funding from the new technology category.
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ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
However, the non-refurbished portion of the facility cannot exceed 20% of the
refurbished facility's total value.
The "emerging" category is restricted to projects using small wind turbines of
10 kW or less, fuel cell technology and solar power - both photovoltaic and
solar thermal. A total of $54 million has been allocated to the emerging
technology account - $10.5 million of which became available on March 20 on a
first-come, first-served basis.
The consumer-side account is designed to promote customer participation in the
renewable energy market. This fund has been allocated $81 million in total,
which in turn is divided between two sub-accounts: a customer credit account -
which has been allotted most of the consumer-side funds, and secondly a consumer
information account.
Existing Renewable
- ------------------
The Existing Renewable Resource Account was designed to help maintain existing
renewable technologies during the first four years of the electric industry
restructuring. The total amount of funds allocated to the existing renewable
account is $243 million, which is divided among three tiers.
Existing technologies are assigned to a tier according to their cost
characteristics and potential for further cost efficiencies. Tier 1 contains
biomass and solar thermal technologies and is allocated 25% of the total
existing renewable account. Wind generation is placed in Tier 2 and is allocated
13% of the total. Tier 3 is allocated 7% of the existing renewable fund total
and consists of geothermal, small hydro, digester gas, and municipal solid waste
and landfill gas technologies.
Table 6-2
Existing Renewable Resource Account - Allocations by Tier
$Millions
<TABLE>
<CAPTION>
Tier 1 Tier 3
Biomass, Solar, Tier 2 Geothermal, Small
Thermal Wind Hydro, Other Total
- ---------------------------------------------------------------------
<S> <C> <C> <C>
$135 $70.2 $37.8 $243
- ---------------------------------------------------------------------
</TABLE>
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998, page ES-8.
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1999-2009
- -------------------------------------------------------------------------------
The amount of funds available annually to each tier declines over the four year
period. The CEC structured the funding in this manner because they expect
renewable generation facilities to become more cost efficient over time.
Therefore, less financial help is required in order to compete in an unregulated
market.
The subsidy is distributed monthly to renewable suppliers through a simple cents
per kWh payment. However, the calculation of the subsidy is more complicated -it
is based on the lowest of three possible calculations: 1) the difference between
a Target Price and the market clearing price (the SRAC specific to each IOU is
used as a proxy for the market clearing price at present), 2) a pre-determined
cents per kWh price cap and 3) a funds adjusted price - which ensures that the
amount disbursed does not exceed the amount of funds available. The CEC
designated Target Price and Price Cap for Existing Renewable Resource Tier 3
facilities are 3.0 cents and 1.0 cents per kWh respectively. Between January and
December of 1998, the SRAC price applicable to Southern California Edison varied
from 2.7 to 3.1 cents per kWh. The average subsidy paid to eligible generators
was about 0.21 cents per kWh.
Of the $37.80 million targeted for eligible existing Tier 3 generation, $12.15
million was scheduled for disbursement in 1998, $10.80 million is planned for
1999, $8.10 million in 2000 and $6.75 in 2001. However, only $8.32 million was
actually paid out in 1998, leaving a $3.83 million surplus that can be used to
supplement funds allocated to future years. It appears therefore that additional
geothermal generation could financially benefit from the program without
adversely affecting the subsidy paid to current Tier 3 generators. However, as
shown in Appendix D, SRAC prices are forecast to be above the Target Price of
3.0 cents per kWh in all, or almost all, months in 2000 and 2001, depending upon
gas price levels. This situation is not exceptional. During 1998, a Tier 3
subsidy was not paid in six of the twelve months because the calculated SRAC
exceeded the target price.
In the event that future SRAC prices are lower than forecast here, HESI believes
that the AB 1890 program has ample funds to ensure that Tier 3 producers receive
the minimum of 3.0 cents per kWh until the end of 2001. It is important to note
that if PX-based pricing replaces the Transition Formula before March 2002, as
we expect, then the likelihood of positive Tier 3 subsidy payments is much
higher because PX prices are more likely to be below the Target Price than
formula-based SRAC prices.
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1999-2009
- -------------------------------------------------------------------------------
New Renewable Resource Account
- ------------------------------
The New Renewable Resources Account contains $162 million to support new
renewable power generation projects. According to the legislation, "new" in this
context means a renewable energy facility located in California that became
operational on or after September 23, 1996, but prior to January 1, 2002. As
Table 6-3 shows, the proportion of total funds devoted to new technologies
increases from $32.4 million in 1998 to $48.6 million by 2001. However, eligible
facilities receive subsidy payments over a 5 year period commencing when the
facility comes on-line - though funding will terminate at the end of 2006, or
five years after the last winning project begins operation.
Table 6-3
New Renewable Resource Account - Allocations by Year,
$Millions
<TABLE>
<S> <C> <C> <C> <C>
1998 1999 2000 2001 Total
- ----------------------------------------------------------
$32.4 $37.8 $43.2 $48.6 $162
- ----------------------------------------------------------
</TABLE>
Source: Policy Report on AB 1890 Renewables Funding, Report to the Legislature,
California Energy Commission, March 1998, page 33.
The full $162 million allocated to new renewable energy technologies was
disbursed in a single auction held in July of this year. Auction participants
were required to submit "bids" - a cents per kWh subsidy, and an estimate of
project generation over a 5 year period (however, acceptable bids were capped at
1.5 cents per kWh). The fund was then allocated from lowest to highest bidder
until it was exhausted. Winners will receive a payment for renewable electric
generation produced and sold in the first five years of project operation.
According to California Energy Commission records, 55 out of 56 bids,
representing 600 MW, divided up the $162 million allotment. The average bid was
1.2 cents per kilowatt hour. The winning bids consisted of approximately 300 MW
of wind; 157 MW of geothermal; 70 MW of landfill gas; 12 MW of biomass; 1
megawatt of digester gas; and 1 megawatt of small hydro.
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1999-2009
- -------------------------------------------------------------------------------
Emerging Renewables Account
- ---------------------------
The purpose of the emerging renewable subsidy program is to reduce the cost to
consumers of certain renewable energy generation equipment. Four types of
renewable power generation are eligible for these funds: small wind turbines of
10 kW or less, fuel cells that convert renewable fuels such as methane gas into
electric power, and solar power - both photovoltaic (PV) and solar thermal. The
first $10.5 million of the total $54 million allocated to this fund became
available March 20, 1998 from the CEC on a first-come, first-served basis.
The delivery mechanism for this Account is a cash rebate equal to 50 percent of
the purchase price or $3,000 per kW, whichever is less, of the cost of an
eligible power generating system. In order to receive the rebate, the system
must offset some or all of the electric power used by the consumer; have a full,
five-year guarantee; and be installed by an appropriately licensed contractor.
Most importantly, the system must be connected to local power lines. Remote,
self-contained systems that are not grid-connected do not qualify. The offer is
good only for systems installed in the service territories of the State's
largest three investor-owned utilities -- PG&E, SCE and SDG&E.
Consumer-Side Incentives
- ------------------------
The consumer-side account is designed to promote customer participation in the
renewable energy market. This account was allocated $81 million, or 15% of the
total fund. These funds in turn have been allocated to two sub-accounts - a
customer credit account, which has most of the allotted funds, and secondly to a
consumer information account.
The customer credit account provides "credits" to consumers who purchase CEC-
registered renewable power that satisfy certain eligibility criteria. Through
this program, residential and small commercial customers' electric power bill
who purchase renewable energy will automatically be credited up to 1.5 cents for
every kilowatt-hour of renewable electric power they consume up to the total
fund amount of $75.6 million. Funds for customer credits were distributed in
early 1998. For at least the first two years, payments to some customers have a
ceiling of $1,000 per year per customer.
As of early September, the CEC has not disbursed any monies under this program,
even though a number of power providers have obtained CEC registered status and
therefore are in a position to grant subsidies to
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
6-5
<PAGE>
PROPRIETARY AND CONFIDENTIAL
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND PRICE FORECAST
1999-2009
- -------------------------------------------------------------------------------
consumers. The reason is largely due to the delay in getting deregulation
underway. The CEC expects that the first set of customer power bills eligible
for a rebate will begin coming in within a few weeks.
- -------------------------------------------------------------------------------
(C)1999 Henwood Energy Services, Inc. May 20, 1999
6-6
<PAGE>
Appendix A - Southern California Base Case MCP Forecast
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
Base Case Forecast TRANSAREA MARKET CLEARING PRICES BY MONTH AND PERIOD
------------------------------------------------------------------------------------------------------------
TransArea Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ANN
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SoCal On-Peak 33.98 30.20 31.34 27.80 28.50 27.54 33.86 38.70 37.04 34.87 34.39 34.26 32.74
2000 Off-Peak 26.49 21.35 20.95 18.39 15.20 13.77 19.14 21.44 23.77 25.43 26.94 26.72 21.64
Average 30.06 25.57 25.89 22.87 21.53 20.33 26.14 29.65 30.09 29.92 30.49 30.31 26.93
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 35.00 33.47 29.82 28.51 35.25 31.96 34.96 40.14 39.25 34.42 35.95 36.45 34.62
2001 Off-Peak 27.50 25.42 22.83 18.99 16.26 14.12 19.63 25.56 24.98 25.79 28.95 27.64 23.14
Average 31.07 29.25 26.16 23.52 25.30 22.62 26.93 32.50 31.78 29.90 32.28 31.84 28.60
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 43.58 39.64 33.81 33.54 34.02 32.63 42.49 49.05 49.17 45.78 45.96 45.83 41.32
2002 Off-Peak 32.12 29.60 26.68 22.42 20.01 17.67 24.03 31.47 30.41 30.44 33.37 32.90 27.60
Average 37.57 34.38 30.07 27.72 26.67 24.79 32.82 39.84 39.35 37.74 39.37 39.06 34.13
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 45.90 41.15 35.38 36.08 35.18 33.82 46.01 53.05 51.85 52.12 48.17 48.87 44.00
2003 Off-Peak 34.82 31.82 26.65 23.50 20.70 18.82 25.26 32.09 31.76 32.50 35.68 35.11 29.05
Average 40.09 36.27 30.80 29.49 27.59 25.96 35.13 42.07 41.33 41.84 41.63 41.66 36.17
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 48.56 41.34 37.70 35.34 37.80 35.88 47.22 57.83 54.94 48.39 51.30 49.48 45.53
2004 Off-Peak 35.11 29.80 27.80 25.93 22.83 21.39 28.26 32.45 32.95 34.84 37.52 37.36 30.54
Average 41.51 35.29 32.51 30.41 29.95 28.29 37.28 44.52 43.43 41.29 44.09 43.12 37.67
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 52.99 49.47 39.39 38.89 42.36 38.48 51.34 61.54 57.64 52.36 51.11 52.72 49.05
2005 Off-Peak 37.11 32.63 29.19 26.77 24.25 22.26 29.39 37.33 34.56 35.55 42.09 38.12 32.45
Average 44.67 40.65 34.04 32.55 32.86 29.99 39.83 48.85 45.55 43.55 46.39 45.06 40.35
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 55.79 49.21 47.35 39.05 41.66 40.94 51.36 63.51 58.02 55.14 56.52 56.28 51.28
2006 Off-Peak 36.88 33.89 29.20 27.52 25.24 23.01 31.41 37.72 35.15 36.72 38.36 39.05 32.86
Average 45.88 41.18 37.84 33.01 33.06 31.55 40.90 49.99 46.05 45.48 47.01 47.25 41.63
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 55.63 55.93 41.53 40.41 47.11 41.60 53.91 59.56 57.56 56.55 59.33 57.31 52.20
2007 Off-Peak 38.13 33.73 30.64 29.19 25.72 23.64 30.28 37.34 36.57 35.61 39.97 40.28 33.44
Average 46.45 44.30 35.82 34.53 35.90 32.20 41.53 47.91 46.57 45.58 49.19 48.38 42.37
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 59.34 46.42 46.56 43.88 48.11 42.04 57.14 60.81 58.34 56.33 56.12 57.80 52.82
2008 Off-Peak 38.37 31.45 31.13 30.04 28.01 24.18 32.70 38.28 36.68 36.10 41.04 40.72 34.09
Average 48.34 38.58 38.47 36.63 37.57 32.69 44.33 49.00 47.00 45.72 48.23 48.85 43.01
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 58.73 60.97 43.20 44.66 48.33 46.51 55.87 62.62 60.61 56.56 60.22 59.13 54.75
2009 Off-Peak 38.25 34.49 32.31 30.00 28.45 25.59 34.91 38.63 35.84 38.30 38.81 41.08 34.75
Average 48.00 47.10 37.49 36.98 37.91 35.55 44.89 50.05 47.64 46.99 49.01 49.67 44.27
------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Appendix B - Southern California Low Gas Case 1 MCP Forecast
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Low Gas Price Case 1 MARKET CLEARING PRICES FOR SOUTHERN CALIFORNIA TRANSMISSION AREA
- ---------------------------------------------------------------------------------------------------
Year Period Jan Feb Mar Apr May Jun
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000 On-Peak 32.79 28.76 29.36 26.06 27.03 30.19
Off-Peak 25.53 17.93 20.22 17.72 14.66 13.39
Average 28.98 23.08 24.57 21.69 20.55 21.39
- ---------------------------------------------------------------------------------------------------
2001 On-Peak 34.44 31.05 30.96 26.93 29.35 31.86
Off-Peak 25.96 24.26 21.29 18.29 15.71 13.78
Average 30.00 27.49 25.89 22.41 22.20 22.39
- ---------------------------------------------------------------------------------------------------
2002 On-Peak 41.22 37.13 31.80 31.32 30.68 30.51
Off-Peak 31.00 28.21 24.89 21.23 18.92 17.12
Average 35.87 32.45 28.17 26.03 24.51 23.50
- ---------------------------------------------------------------------------------------------------
2003 On-Peak 43.32 39.85 32.59 32.43 32.40 32.20
Off-Peak 31.49 29.80 25.10 22.46 19.72 17.91
Average 37.12 34.59 28.66 27.21 25.75 24.71
- ---------------------------------------------------------------------------------------------------
2004 On-Peak 46.80 35.80 34.24 33.63 36.27 34.63
Off-Peak 32.91 28.11 25.87 24.32 21.57 20.22
Average 39.52 31.77 29.85 28.75 28.57 27.08
- ---------------------------------------------------------------------------------------------------
2005 On-Peak 50.18 46.56 36.48 35.16 41.80 36.62
Off-Peak 34.50 30.16 26.87 25.07 22.94 21.06
Average 41.96 37.97 31.44 29.88 31.91 28.47
- ---------------------------------------------------------------------------------------------------
2006 On-Peak 52.43 45.50 44.44 36.06 39.63 37.72
Off-Peak 34.11 31.81 27.10 25.71 23.88 21.74
Average 42.83 38.33 35.35 30.64 31.37 29.36
- ---------------------------------------------------------------------------------------------------
2007 On-Peak 52.10 46.96 39.47 39.35 42.57 38.14
Off-Peak 35.59 30.82 28.64 26.75 24.17 22.26
Average 43.45 38.50 33.79 32.75 32.93 29.83
- ---------------------------------------------------------------------------------------------------
2008 On-Peak 54.84 43.43 41.56 38.71 42.43 40.66
Off-Peak 35.61 29.59 28.93 28.01 26.36 22.84
Average 44.76 36.18 34.94 33.11 34.00 31.33
- ---------------------------------------------------------------------------------------------------
2009 On-Peak 55.12 50.26 41.09 40.07 44.24 41.73
Off-Peak 35.12 31.93 29.96 28.05 26.56 24.16
Average 44.63 40.66 35.26 33.78 34.97 32.53
- ---------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Low Gas Price Case 1 MARKET CLEARING PRICES FOR SOUTHERN CALIFORNIA TRANSMISSION AREA
- ---------------------------------------------------------------------------------------------------
Year Jul Aug Sep Oct Nov Dec ANN
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
2000 33.94 37.40 35.85 32.58 32.72 33.60 31.72
18.39 20.76 23.02 23.57 25.62 25.38 20.55
25.79 28.68 29.13 27.86 29.01 29.29 25.86
- ---------------------------------------------------------------------------------------------------
2001 33.19 38.21 37.98 34.09 33.04 34.54 32.99
18.78 23.65 23.32 22.59 27.75 26.62 21.83
25.64 30.58 30.30 28.06 30.27 30.39 27.14
- ---------------------------------------------------------------------------------------------------
2002 41.16 46.69 45.94 42.95 43.56 42.92 38.85
23.16 28.91 28.41 29.13 30.96 30.88 26.07
31.73 37.37 36.76 35.71 36.96 36.61 32.15
- ---------------------------------------------------------------------------------------------------
2003 43.29 49.50 48.66 44.27 46.83 43.62 40.76
23.86 30.00 29.38 30.35 33.32 32.70 27.17
33.10 39.28 38.56 36.98 39.75 37.90 33.64
- ---------------------------------------------------------------------------------------------------
2004 45.16 51.54 49.49 45.52 47.63 46.66 42.34
26.46 30.59 30.65 32.55 34.79 34.15 28.53
35.36 40.56 39.62 38.72 40.91 40.10 35.11
- ---------------------------------------------------------------------------------------------------
2005 45.74 58.59 55.87 47.53 46.84 50.47 46.01
27.67 34.99 32.40 32.83 39.37 35.07 30.25
36.27 46.22 43.58 39.82 42.93 42.40 37.75
- ---------------------------------------------------------------------------------------------------
2006 47.76 60.79 55.73 49.50 50.53 52.63 47.77
29.23 35.41 32.38 34.50 35.66 36.67 30.69
38.04 47.48 43.51 41.64 42.75 44.26 38.83
- ---------------------------------------------------------------------------------------------------
2007 50.06 58.50 55.47 56.13 63.31 52.51 49.57
28.52 35.25 33.89 33.30 36.88 37.28 31.13
38.77 46.32 44.17 44.16 49.47 44.53 39.91
- ---------------------------------------------------------------------------------------------------
2008 52.55 58.89 57.12 53.57 51.78 53.95 49.19
30.40 35.37 34.42 33.50 38.39 37.81 31.80
40.94 46.56 45.23 43.05 44.77 45.49 40.08
- ---------------------------------------------------------------------------------------------------
2009 53.26 60.50 55.93 52.86 55.89 54.05 50.44
32.27 35.82 33.29 35.34 36.35 37.94 32.25
42.25 47.56 44.07 43.68 45.66 45.60 40.91
- ---------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Appendix C - Southern California Low Gas Case 2 MCP Forecast
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
Low Gas Price Case 2 TRANSAREA MARKET CLEARING PRICES BY MONTH AND PERIOD
------------------------------------------------------------------------------------------------------------
TransArea Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ANN
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
SoCal On-Peak 32.67 29.48 27.70 25.86 27.06 27.53 33.46 37.00 35.61 32.55 34.17 32.34 31.30
2000 Off-Peak 25.46 17.81 20.09 17.68 14.76 13.40 18.36 20.64 22.75 23.49 25.63 25.70 20.51
Average 28.89 23.37 23.71 21.57 20.61 20.13 25.55 28.42 28.88 27.80 29.70 28.86 25.65
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 33.14 31.55 30.57 26.63 30.85 30.77 32.77 38.42 36.86 32.44 33.21 33.25 32.55
2001 Off-Peak 25.63 24.06 21.26 18.08 15.59 13.70 18.89 24.03 23.11 22.24 27.39 26.12 21.67
Average 29.20 27.62 25.69 22.15 22.85 21.83 25.49 30.88 29.66 27.10 30.16 29.51 26.85
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 40.05 35.96 31.54 30.42 30.10 29.53 40.58 45.77 46.59 42.14 42.20 42.88 38.17
2002 Off-Peak 30.25 27.53 24.54 20.81 18.87 16.84 22.70 28.63 28.10 28.05 30.67 30.24 25.60
Average 34.92 31.54 27.87 25.39 24.21 22.89 31.21 36.79 36.90 34.75 36.16 36.26 31.59
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 42.65 38.98 32.44 32.10 31.86 31.27 42.31 49.99 47.28 42.77 43.68 43.89 39.96
2003 Off-Peak 31.14 28.93 24.83 21.61 19.46 17.62 23.56 29.48 28.74 29.80 32.98 31.81 26.66
Average 36.62 33.71 28.45 26.61 25.36 24.12 32.48 39.24 37.57 35.97 38.08 37.56 32.99
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 45.46 35.25 33.26 32.30 34.35 32.15 43.73 54.52 48.62 45.01 45.29 44.64 41.28
2004 Off-Peak 31.70 27.26 25.20 23.48 20.95 19.75 25.90 29.74 29.74 31.64 34.18 33.83 27.80
Average 38.25 31.06 29.04 27.68 27.32 25.66 34.38 41.53 38.74 38.00 39.47 38.97 34.22
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 48.84 43.85 34.98 35.39 39.33 33.70 45.04 55.26 55.19 46.99 45.64 48.85 44.45
2005 Off-Peak 32.85 28.76 25.93 24.30 22.25 20.54 26.72 33.89 30.99 31.88 39.67 34.14 29.34
Average 40.46 35.95 30.24 29.59 30.38 26.81 35.44 44.06 42.52 39.07 42.51 41.14 36.53
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 49.39 43.93 39.68 34.87 38.23 36.11 45.88 58.22 53.08 47.57 48.01 50.64 45.51
2006 Off-Peak 32.56 30.62 26.20 24.52 22.98 21.18 28.30 34.40 31.42 33.00 33.90 35.23 29.54
Average 40.57 36.96 32.61 29.45 30.24 28.29 36.66 45.73 41.74 39.93 40.62 42.56 37.14
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 50.03 44.97 39.80 35.84 43.80 35.74 47.27 57.40 51.45 49.66 52.25 50.08 46.56
2007 Off-Peak 34.14 29.91 27.17 25.73 23.39 21.51 27.47 33.76 32.39 32.33 35.42 34.96 29.86
Average 41.70 37.08 33.18 30.54 33.10 28.29 36.89 45.00 41.47 40.57 43.44 42.15 37.81
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 53.37 40.60 41.82 42.26 40.41 38.21 49.36 56.11 55.55 55.12 49.50 51.66 47.91
2008 Off-Peak 33.79 28.24 27.56 26.74 25.33 21.93 29.59 34.08 33.23 32.20 36.69 36.23 30.50
Average 43.11 34.13 34.35 34.13 32.51 29.69 39.00 44.57 43.86 43.11 42.79 43.58 38.78
------------------------------------------------------------------------------------------------------------
SoCal On-Peak 51.85 46.58 41.60 37.87 43.43 41.47 49.32 57.57 55.22 50.18 54.84 53.74 48.67
2009 Off-Peak 34.32 30.64 28.76 26.67 25.26 23.08 31.11 34.51 32.73 34.21 34.34 36.77 31.06
Average 42.66 38.23 34.87 32.00 33.90 31.84 39.77 45.48 43.44 41.81 44.11 44.84 39.44
------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Appendix Table D.1
Southern California Edison SRAC Prices by Month and Time-of-Day, 1999-2001
Cents per kWh
<TABLE>
<CAPTION>
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1999
On Peak 4.212 4.254 4.334 4.451
Mid Peak 3.342 3.090 2.953 3.026 3.596 2.989 2.987 3.197 3.225 3.938 4.100 4.171
Off Peak 2.604 2.375 2.202 2.264 2.802 2.520 2.545 2.593 2.663 2.987 3.208 3.161
Super-Off 2.129 1.968 1.881 1.927 2.290 2.508 2.611 2.656
Average 2.743 2.536 2.424 2.483 2.952 2.956 2.985 3.041 3.123 3.231 3.365 3.423
Tier 3 Subsidy 0.257 0.464 0.576 0.517 0.048 0.044 0.015 0.000 0.000 0.000 0.000 0.000
2000
On Peak 4.358 4.401 4.485 4.607
Mid Peak 4.161 3.903 3.809 3.748 3.721 3.093 3.091 3.308 3.338 4.076 4.247 4.320
Off Peak 3.241 2.999 2.841 2.804 2.899 2.607 2.633 2.683 2.756 3.092 3.323 3.273
Super-Off 2.650 2.486 2.426 2.387 2.370 2.596 2.704 2.751
Average 3.415 3.203 3.126 3.076 3.054 3.058 3.088 3.147 3.232 3.345 3.485 3.545
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
2001
On Peak 4.494 4.541 4.626 4.754
Mid Peak 4.294 4.026 3.929 3.866 3.838 3.190 3.188 3.412 3.444 4.207 4.384 4.461
Off Peak 3.345 3.094 2.929 2.893 2.989 2.689 2.717 2.768 2.844 3.191 3.430 3.380
Super-Off 2.735 2.564 2.502 2.462 2.444 2.679 2.792 2.841
Average 3.524 3.304 3.224 3.173 3.149 3.153 3.186 3.246 3.336 3.452 3.598 3.661 3.334
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
Note: Forecast based on HESI Base Case long term gas price forecast at Topock with 3% inflation per year.
See Table 2.3 for annual average SRAC values.
SRAC prices from January to April 1999 are actual.
</TABLE>
<PAGE>
Appendix Table D.2
Southern California Edison SRAC Prices by Month and Time-of-Day, 1999 - 2001
Cents per kWh
<TABLE>
<CAPTION>
Jan Feb Mar Apr May Jun Jul
<S> <C> <C> <C> <C> <C> <C> <C>
1999
On Peak 3.657 3.693
Mid Peak 3.342 3.090 2.953 3.026 3.123 2.596 2.594
Off Peak 2.604 2.375 2.202 2.264 2.433 2.188 2.210
Super-Off 2.129 1.968 1.881 1.927 1.989
Average 2.743 2.536 2.424 2.483 2.563 2.566 2.592
Tier 3 Subsidy 0.257 0.464 0.576 0.517 0.437 0.434 0.408
2000
On Peak 4.253 4.296
Mid Peak 4.027 3.808 3.717 3.658 3.631 3.018 3.017
Off Peak 3.137 2.926 2.772 2.737 2.829 2.544 2.570
Super-Off 2.565 2.425 2.367 2.330 2.312
Average 3.305 3.125 3.050 3.002 2.980 2.984 3.015
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.020 0.016 0.000
2001
On Peak 4.354 4.399
Mid Peak 4.126 3.900 3.807 3.746 3.718 3.090 3.089
Off Peak 3.214 2.997 2.838 2.803 2.896 2.605 2.632
Super-Off 2.628 2.484 2.424 2.385 2.368
Average 3.386 3.201 3.124 3.074 3.051 3.055 3.087
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000 0.000 0.000
</TABLE>
<TABLE>
<CAPTION>
Aug Sep Oct Nov Dec
<S> <C> <C> <C> <C> <C>
1999
On Peak 3.759 3.857
Mid Peak 2.773 2.794 3.408 3.544 3.616
Off Peak 2.249 2.307 2.585 2.773 2.740
Super-Off 2.170 2.257 2.303
Average 2.638 2.706 2.797 2.908 2.967
Tier 3 Subsidy 0.362 0.294 0.203 0.092 0.033
2000
On Peak 4.377 4.496
Mid Peak 3.229 3.257 3.977 4.142 4.229
Off Peak 2.619 2.690 3.016 3.240 3.205
Super-Off 2.532 2.638 2.693
Average 3.072 3.155 3.263 3.399 3.470
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000
2001
On Peak 4.482 4.604
Mid Peak 3.306 3.336 4.073 4.243 4.333
Off Peak 2.682 2.754 3.090 3.320 3.284
Super-Off 2.594 2.702 2.760
Average 3.145 3.231 3.343 3.482 3.556
Tier 3 Subsidy 0.000 0.000 0.000 0.000 0.000
Note: Forecast based on HESI short-term gas price forecast at Topock.
SRAC prices from January to April 1999 are actual.
</TABLE>
<PAGE>
EXHIBIT C
[GeothermEx, Inc. Letterhead]
INDEPENDENT REVIEW OF STEAM SUPPLY
AND RESOURCE-RELATED CAPITAL AND OPERATING COSTS
COSO GEOTHERMAL FIELD
for
CAITHNESS COSO FUNDING CORPORATION
New York, New York
by
GeothermEx, Inc.
Richmond, California
MAY 1999
<PAGE>
[GeothermEx, Inc. Letterhead]
CONTENTS
<TABLE>
<CAPTION>
<S> <C>
EXECUTIVE SUMMARY...................................................iv
1. INTRODUCTION....................................................1-1
2. STEAM SUPPLY....................................................2-1
2.1 Introduction..............................................2-1
2.2 Production................................................2-2
2.3 Injection.................................................2-7
2.4 Gases in Steam............................................2-8
3. CAPITAL AND OPERATING COSTS.....................................3-1
</TABLE>
Tables
Figures
Appendices
Appendix A: Production Histories for Navy I Production Wells
Appendix B: Production Histories for Navy II Production Wells
Appendix C: Production Histories for BLM Production Wells
Appendix D: Injection Histories for Navy I Injection Wells
Appendix E: Injection Histories for Navy II Injection Wells
Appendix F: Injection Histories for BLM Injection Wells
ii
<PAGE>
[GeothermEx, Inc. Letterhead]
ILLUSTRATIONS
Table
- -----
2.1 H2S in Steam at Coso Wells
3.1 Summary of Drilling, Gathering Systems and Workover Costs for the Coso
Geothermal Project in Caithness financial projections
Figure
- ------
1.1 Location of the Coso geothermal field, California
1.2 Well location map, Coso geothermal field
2.1 Coso MW forecast from Caithness financial projections
2.2 Megawatts per well vs. time, Navy I
2.3 Megawatts per well vs. time, Navy II
2.4 Megawatts per well vs. time, BLM
2.5 Total NCG/steam vs. time, Navy II well 15-17RD
2.6 H2S/steam vs. time, Navy II well 15-17RD
2.7 Comparison of Caithness and GeothermEx MW forecasts
3.1 Planned drilling costs at Coso from Caithness financial projections
3.2 Planned gathering system costs at Coso from Caithness financial
projections
3.3 Planned workover costs at Coso from Caithness financial projections
iii
<PAGE>
[GeothermEx, Inc. Letterhead]
EXECUTIVE SUMMARY
GeothermEx has been requested by Caithness Coso Funding Corporation
("Caithness") to conduct a due diligence review of the geothermal resource at
the Coso Geothermal Field. This review has been conducted in connection with
the re-financing of Caithness' recent acquisition of the Coso assets from
CalEnergy Company, Inc. (CECI). The work by GeothermEx has consisted of:
. a review of the status of the steam supply from the geothermal field;
. a review of resource-related capital and operating costs; and
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs as contained in Caithness' financial
projections.
GeothermEx has acted as the independent geothermal engineer for the Coso
projects (Navy I, Navy II, and BLM) since their initial financing in the late
1980s. Since 1993, GeothermEx has provided an annual independent assessment of
the resource supply as a requirement of CECI's bond issue; the last such
evaluation was prepared in June 1998.
Based upon this review, we have reached the following main conclusions:
. The resource data supplied to us by Caithness appear reasonable based
on our long familiarity with the Coso projects.
iv
<PAGE>
[GeothermEx, Inc. Letterhead]
. The Coso geothermal reservoir has supplied steam to the installed
plants for more than 10 years and has proven to be one of the most
reliable geothermal reservoirs in the United States.
. Geothermal energy reserves at Coso are more than sufficient to
support the existing plants for 30 years. However, as in all geothermal
fields, make-up well drilling will be necessary to maintain power
output.
. Development of leaseholds adjacent to the Caithness acreage is
unlikely, and the possibility of any impact of offsetting development
on the performance of the Caithness resource is remote.
. The financial projections by Caithness show a combined generation
capacity of about 264 net megawatts until year 2006 and declining
thereafter. The forecasts of the generation decline trend after year
2006 made by Caithness are reasonable and very similar to the
GeothermEx forecasts.
. The well drilling and workover programs assumed in Caithness's
financial projections are reasonable and should result in steam supply
sufficient to maintain the generation capacity forecast in Caithness's
financial projections.
. Resource-related capital and operating costs assumed in Caithness's
financial projections are reasonable and consistent with the historical
trend and industry practice.
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In conducting the current review, GeothermEx has relied on resource and cost
data supplied by Caithness; these data appear reasonable based on our long
familiarity with the Coso projects. We have had numerous phone conversations
with members of Caithness' technical and managerial staff to clarify questions
relating to the data and to ensure that no significant resource issues have been
overlooked.
The Coso reservoir has been operated profitably for more than 10 years, and has
proven to be one of the most reliable geothermal reservoirs in the United
States. In our previous assessments of the resource, we have repeatedly
confirmed that the geothermal energy reserves at Coso are more than sufficient
to support the three existing power plants for 30 years. However, in all
geothermal fields, well productivity declines with time due to declines in
reservoir pressure; generation capacity is maintained by drilling "make-up"
wells to compensate for declining well productivity. Any decline in generation
capacity at Coso will not be caused by a shortage of reserves, but by the
economics of make-up well drilling in relation to the power price.
The financial projections presented by Caithness show the combined power
generation at the Coso projects to be approximately 264 net megawatts (NMW)
until 2006, declining thereafter at a rate of about 3.7% per year. The nearly
constant generation level during 1999-2006 is to be maintained by make-up well
drilling to compensate for declines in well productivity. After 2006, no make-
up wells will be drilled, and therefore, generation will decline. We have
forecast declines in steam supply based on decline curve analysis, a method that
extrapolates the past trends in well productivity decline into the future.
Caithness has conducted a similar decline curve analysis, which we have reviewed
herein.
Caithness has assumed a harmonic decline trend in its analysis. This is a
reasonable assumption. Geothermal wells in "two-phase" reservoirs (that is,
reservoirs containing both hot water and
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steam) such as Coso often exhibit exponential declines in capacity during their
first few years of operation, but later make a transition to a harmonic decline.
Unlike exponential decline, where the decline rate remains constant with time,
harmonic decline implies that the decline rate itself declines with time.
GeothermEx's review of historical well capacities indicates that the wells at
Coso are currently exhibiting harmonic declines. Also, there is still some spare
capacity above the electromechanical limit of the plants. This spare capacity
should allow a plateau of constant output for a year or so without drilling
additional geothermal production wells, provided existing wells are maintained
in good mechanical condition, which has generally been the case historically.
After 2006, the annual decline rate used in the financial projections is about
3.7% (harmonic). This is close to the decline rate of 4.1% (harmonic) starting
in 2006 estimated by GeothermEx. The forecasts of generation decline trend
after 2006 made by Caithness and GeothermEx differ by less than 5% throughout
the 13-year period of declining generation.
Resource-related costs reviewed herein include those related to drilling new
wells, connecting them to the gathering system (for wells drilled on pads with
existing production wells) or extending the gathering system (for wells drilled
on new pads) and working over existing wells. All projected costs are based on
1999 dollars and are escalated at 3% per year.
The historical drilling expenditures from 1995 to 1998 were in the range of $12
million to $15 million per year, with the exception of 1996, when drilling
expenditures were about $2 million. Going forward, the financial projections
include $6.5 million in drilling funds for 1999, about $4 million in 2000, $7
million in 2001, $10.5 million in 2002, and $7.5 to $8.5 million in 2003 - 2006.
No drilling is planned after 2006.
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The cost assumed in the financial projections for drilling a new well is $2.75
million in 1999, except for a BLM well to be drilled this year (see discussion
below). Based on documents provided by Caithness, a total of six new wells were
drilled in 1997 and 1998, with an average cost of $2.73 million and an average
depth of approximately 9,000 feet. Considering that the average depths of
future wells will be similar, the estimate of $2.75 million per well is
reasonable. The average productivity of these wells was approximately 8 MW
(gross); this includes the highly productive East Flank well 38B-9. Without
38B-9, the average productivity was approximately 5 MW (gross). Caithness has
reasonably assumed an average 1999 productivity of 5.6 MW for new wells. The
financial projections do not include any decline in the expected capacity of
make-up wells; it remains at 5.6 MW throughout the project life. Realistically,
this amount should be expected to decline according to the decline rate assigned
to each area of the field; as few make-up wells are planned and the decline rate
in well productivity is very small, the difference between the projections with
and without declining the capacity of make-up wells is not significant.
Several production wells were redrilled in 1997 and 1998, at an average cost of
$1.3 million, an average depth of 6,000 feet, and an average productivity of 3.2
MW (gross). No funds are allocated in the financial projections for production
well redrills, as Caithness does not plan to redrill any existing production
wells. However, Caithness reports that there is about $1.5 million per year in
the O&M section of the budget, which will be used for well clean-outs and other
well maintenance. Production well workovers are discussed below. Two
injection well redrills are planned for 1999, and one injection well redrill per
year is planned for years 2000 to 2006. The cost of injection well redrills in
1999 dollars is $1.2 million per well, which is reasonable.
In 1999, the drilling costs include injection well redrills in the BLM and Navy
II areas ($1.2 million each), a purchase of new drill pipe ($150,000, allocated
unequally between Navy II and BLM), drilling a slim exploration well in BLM
North ($400,000), deepening the existing BLM
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North well 43-7 ($726,000) and drilling BLM North well 43A-7 ($2.9 million). The
last is planned to a total depth of 10,000 feet, which is deeper than other
planned wells at Coso, and accounts for its slightly greater cost.
One injection well redrill and one BLM production well (43B-7) are planned for
2000. A total of 15 new wells are planned from 1999 through 2006, which
equates to nearly 11 MW per year, using Caithness' assumption of no decline in
the capacity of make-up wells. As indicated by drilling data provided by
Caithness, six new wells were drilled in the last two years. Therefore, we
would expect that two to three make-up wells would be needed each year to
maintain production, unless the make-up wells have a higher-than-average
capacity which is expected under Caithness' plans to drill in the East Flank
area, a relatively undrilled portion of the resource that should prove more
productive.
In addition to the cost of drilling a well, there are costs associated with
connecting the well to the gathering system. In the case where a new well is
drilled from a pad with existing production wells, the connection cost is
assumed by Caithness to be $500,000; these are "pad pipelines," which are
charged to the appropriate project. For wells drilled on new pads in the BLM
North and East Flank areas, additional expenses will be incurred to extend the
steam gathering pipelines; these are "trunk lines," which are shared equally
between the projects. There are also expenses associated with low-pressure (LP)
steam separation equipment included in this category in 1999. We have not
independently estimated the costs of pipelines or LP separation equipment. The
well connection costs are on the conservative side.
The assumptions page of the financial projections indicates a 1999 workover cost
of $700,000 per well; however, discussion with Caithness revealed that $700,000
is budgeted for each unit, which is adequate for two to three workovers each
year. This is escalated at 3% per year. Workovers
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are assumed to be needed throughout the life of the project. The workover costs
and frequencies are reasonable.
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1. INTRODUCTION
GeothermEx has been requested by Caithness Coso Funding Corporation
("Caithness") to conduct a due diligence review of the geothermal resource at
the Coso Geothermal Field. This review has been conducted in connection with
the re-financing of Caithness' recent acquisition of the Coso assets from
CalEnergy Company, Inc. (CECI). The work by GeothermEx has consisted of:
. a review of the status of the steam supply from the geothermal field;
. a review of resource-related capital and operating costs; and
. an assessment of the reasonableness of the forecasts of power production
and resource-related costs contained in the financial projections
prepared by Caithness.
The Coso Geothermal Field is located about 150 miles northeast of Los Angeles in
Inyo County, California (figure 1.1). Caithness recently took over operation of
the field from CECI, and is the operator of three geothermal projects in the
field: Navy I, Navy II, and BLM. Because Caithness has been a partner of CECI
in the development and operation of the Coso field, Caithness's staff has long
familiarity with this field. In addition, Caithness has retained most of the
CECI employees who ran the Coso project.
Each of the three projects consist of three turbine-generator units and
associated wells, pipelines and other surface facilities. For the purposes of
assessing the available steam supply from the wells, the Navy I, Navy II, and
BLM projects each have megawatt (MW) capacities of 80 MW. However, each project
has plant facilities physically capable of generating about 90 net megawatts
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(NMW) if sufficient steam is available from the wells, representing a total
installed plant capacity of about 270 NMW. The capacity expressed in NMW is net
of the power used by the plant facilities themselves ("parasitic power"). The
Navy I and Navy II projects have single plant sites containing three turbine-
generator units each. The BLM project has two plant sites: BLM East, with two
turbine-generator units; and BLM West, with one turbine-generator unit. Figure
1.2 shows the three project areas with their respective plant sites and well
locations.
The first turbine-generator unit at Navy I came on line in July 1987, and the
second and third units at Navy I came on line in December 1988. All three
units of the Navy II power plant came on line in December 1989. The BLM East
plant came on line in December 1988, and the BLM West plant came on line in
August 1989. Since the plants came on line, make-up wells have been drilled to
maintain or increase production, and the power plants have been modified to
improve the efficiency of steam use. This has allowed the output of the plants
to rise each year through 1996. The average fieldwide output over the past
three years has been 260 NMW, including down time for plant maintenance. This
represents a plant capacity factor of 96%, based on the electromechanical limit
of 270 NMW, and 108% based on 240 MW.
GeothermEx has acted as the independent geothermal engineer for the Coso
projects (Navy I, Navy II, and BLM) since their initial financing in the late
1980s. Since 1993, GeothermEx has provided independent annual evaluations of
the resource supply for CalEnergy; the last such evaluation was prepared in June
1998.
In conducting the current review, GeothermEx has relied on resource and cost
data supplied by Caithness. This data appear reasonable based on our long
familiarity with the Coso projects. We have had numerous phone conversations
with members of Caithness' technical and managerial staff to clarify questions
relating to the data and to ensure that no significant resource issues have
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been overlooked. Our review has focused on the geothermal resource and the
operation of the wellfield; considerations pertaining to the plants have not
been covered in this review.
Our review of the present and projected steam supply is described in detail in
Chapter 2. Our review of present and projected capital costs for drilling and
pipeline construction, as well as operating costs for workovers is presented in
Chapter 3.
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2. STEAM SUPPLY
2.1 Introduction
------------
The geothermal reservoir at Coso consists of a fractured body of granitic rock
with temperatures in the reservoir ranging from about 400(degrees) to
650(degrees)F. Since the early 1980s, approximately 150 wells have been drilled
in the field, ranging in depth from 1,300 feet to 13,000 feet. About 57% of
these wells have been commercially productive, another 18% have been used for
injection, and the remaining 25% have been non-commercial. Of these 150 wells,
56 were drilled from 1991 through 1998, during which time the drilling success
rate has been considerably higher. Of the 56 wells drilled in this period, only
five have been non-productive, and the others have been used for production (33
wells) or injection (18 wells), indicating a drilling success rate of 91%.
The Coso reservoir has been operated at capacity and profitability for more than
10 years, and has proven to be one of the most reliable geothermal reservoirs in
the United States. In our previous assessments of the resource, we have
repeatedly confirmed that the geothermal energy reserves at Coso are more than
sufficient to support the three existing power plants for 30 years. However, in
all geothermal fields, well productivity declines with time due to declines in
reservoir pressure; generation capacity is maintained by drilling "make-up"
wells to compensate for declining well productivity. Any decline in generation
capacity at Coso will not be caused by a shortage of reserves, but by the
economics of make-up well drilling in relation to the power price.
There are two productive areas: the main reservoir, consisting of the western
portions of the Navy I and Navy II areas and the northern portion of the BLM
area; and the "East Flank," located in the eastern portion of the Navy I and
Navy II areas. The main reservoir was the first part of the field to be
developed and has the greatest concentration of wells, as can be seen in figure
1.2. The
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East Flank was developed later and was tied into the plants in 1994. There are
pipelines allowing transfer of steam between projects, which allows flexibility
in making use of available steam anywhere in the field. To date, each project
has relied primarily on steam from wells within its own boundaries and has
consistently maintained a steam supply in excess of that required for nominal
generation. Leases offsetting the Caithness acreage do not appear to have
significant resource potential. It is unlikely that development of these
offsetting leases will occur, so the risk of any impact from offsetting
development on the performance of the Caithness leases is negligible.
Within the main reservoir, the hottest temperatures are located at BLM West.
However, the flow capacity of the reservoir rock (that is, the ability of the
rock to transmit fluids) generally increases from BLM West northward (toward
Navy II and Navy I) and eastward (toward BLM East). The resource is generally
deeper at BLM and becomes progressively shallower to the north; on the East
Flank, the reservoir is hotter and deeper, similar to the reservoir at BLM West.
2.2 Production
----------
Most of the wells at Coso produce a mixture of steam and boiling water. The
steam is separated from the water and used to generate electricity at the
plants. The separated water is returned to the reservoir by injection wells.
The steam at the power plants is condensed to water (or "condensate") downstream
of the turbines, and a portion of this condensate is also injected. Because
some of the condensate is lost to evaporation in the cooling towers, not all of
the mass from the production wells is returned to the reservoir. To some
extent, this loss of mass is replaced by a natural inflow of groundwater (or
"recharge"). However, as is commonly the case in geothermal projects using this
type of plant technology, the rate of recharge at Coso has been less than the
rate of mass lost to evaporation.
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As a result, reservoir pressures have decreased, and the flow rates of most of
the wells have declined. In addition, lower pressures have induced boiling in
the reservoir, resulting in the formation of a vapor zone (or "steam cap") in
the upper portions of the reservoir. As a consequence, many of the wells have
produced higher proportions of steam over time, and some wells have "dried out"
completely (that is, they have begun producing dry steam). These changes in the
geothermal reservoir are not unusual or unique to Coso, and additional drilling
and optimizing the location of injection has successfully compensated for them
in the past. Still, some decline in steam production is to be expected and is
considered normal for a development of this type.
The Caithness financial projections shows combined power generation at the Coso
projects maintaining a level of about 264 MW through 2006 and declining about
3.7% per year thereafter (figure 2.1). Production is to be maintained by
drilling make-up wells until 2006. The decline occurring thereafter reflects
the anticipated gradual decrease in the amount of steam available from the
wells.
Decline rates are determined by analyzing the historical behavior of the project
wells. The field operator has evaluated the capacity of each of the wells on a
quarterly basis since the projects started up; the capacities represent each
well's best consistent performance during the evaluation period. Because the
performance of individual wells is affected by the flow from other wells in the
gathering system, flow rates from each well have varied in the course of routine
operations. For instance, taking one well off line for maintenance work can
cause higher flow rates from other wells that share the same pipeline. The
variation in the flow rates of individual wells is illustrated in plots of
actual performance at Navy I, Navy II, and BLM (Appendices A, B, and C,
respectively).
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In its annual reports on the Coso project, GeothermEx has used essentially the
same methodology in estimating well capacities based on recent performance.
Although estimates for individual wells have differed, GeothermEx's annual
assessments of resource supply for each project (based on the sum of individual
well capacities) have consistently matched the field operator's estimates within
a few megawatts. For this reason, GeothermEx feels that operator's historical
well capacity estimates are a reasonable basis for decline curve analysis, and
have used them for that purpose in this study. The estimates for each well were
summed for each of the three projects. These sums were then divided by the by
the number of wells to achieve an estimate of average megawatt capacity per well
for each project. This averaged megawatt capacity was then plotted versus time.
The plots for Navy I, Navy II, and BLM are shown in figures 2.2 through 2.4.
Geothermal wells in "two-phase" reservoirs (that is, reservoirs containing both
hot water and steam) often exhibit exponential declines in capacity during their
first few years of operation, but later make a transition to a harmonic decline.
Unlike exponential decline, where the decline rate remains constant with time,
harmonic decline implies that the decline rate itself declines with time. In
each case, the projects showed initial exponential declines in the range of 20
to 30% per year, followed by a transition to harmonic decline rates starting in
early 1992.
Figure 2.2 shows the historical average megawatt capacity for wells in the Navy
I area. In mid-1995, the average capacity of Navy I wells actually rose,
apparently reflecting the effects of drying out of several wells in the
shallower portion of the reservoir. Another increase in average capacity
occurred in 1998, when new East Flank wells were tied into the gathering system.
As shown in figure 2.2, the decline rate in productivity of the Navy I wells
since January 1992 can be approximately fitted to a 3.4% initial harmonic trend.
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At Navy II (figure 2.3), the data since 1992 can be approximately matched by a
harmonic decline rate starting at 6.4%. At BLM (figure 2.4), well productivity
decline since 1995 can be matched approximately to a 16% initial harmonic
decline rate. It should be noted that between 1992 and mid-1995, the decline
rate at BLM was gentler. The cause of the steepened decline since mid-1995 is
not certain, but appears to be related to breakthrough of water from certain
injection wells to offsetting production wells in the BLM West area. The
configuration of injection wells in BLM West has been changed since 1992, and
the decline rate appears to be moderating.
The fieldwide transition from high exponential rates to moderate harmonic
decline rates in 1992 may represent an increase in the amount of recharge in
response to the decline in reservoir pressure. This hypothesis is consistent
with changes in the chemistry of produced steam over time. As part of the
current review, GeothermEx has investigated trends in the concentrations of
hydrogen sulfide (H2S) and total non-condensible gas (NCG) in Coso steam. These
trends are discussed in section 2.4, but in the context of productivity decline
curves, it is interesting to note that a large proportion of the Coso wells
showed an initial steep decline in the concentrations of H2S and total NCG,
followed by a transition to much more gradual declines or steady concentrations.
Figures 2.5 and 2.6 show the typical pattern in H2S and NCG concentrations from
a representative well at Navy II. The timing of this fieldwide transition in
gas concentrations coincides with the start of harmonic declines in well
capacities in 1992. This suggests that the transition reflects the same
underlying reservoir process, that is, the depletion of the fluids initially
present in the reservoir and the onset of production of a greater proportion of
recharge fluid with relatively low gas concentrations from surrounding areas.
For the purposes of this review, GeothermEx has used the estimated well
capacities based on its assessment of June 1998 as the starting point for its
forecast of power generation. To convert the gross capacities to net megawatts,
GeothermEx has assumed parasitic loads to be 10% of the
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gross megawatt output, which is consistent with the historic performance of the
Coso plants. GeothermEx has also assumed a plant capacity factor of 96% to allow
for plant down time, based on the ratio of the field's average net megawatt
output for the past three years (260 NMW) to the electromechanical limit of the
plants after parasitic loads (270 NMW). The plant capacity factor is
approximately 108% if the average net megawatts produced is compared to the
rated capacity of the plants (240 MW). With these adjustments, the combined net
megawatt capacity of the Coso projects as of mid-1996 was 273.5 NMW. This
represents a spare capacity of 11 NMW over the field's actual output of 262.5
NMW in 1996.
This amount of spare capacity should allow a plateau of constant output for a
year or so, provided existing wells are maintained in good mechanical condition
which has generally been the case historically. New wells planned for the
future will be drilled in relatively undeveloped portions of the reservoir, such
as the BLM North area (located west of Navy I and Navy II on acreage formerly
leased to the Los Angeles Department of Water and Power) and the northern
portion of the East Flank. As discussed further in Chapter 3, the projected
drilling costs in the financial projections are sufficient to drill two wells
per year from 1999 to 2006.
Figure 2.7 shows a comparison of GeothermEx's power generation forecast based on
decline curve analysis with the power generation forecast in the financial
projections. GeothermEx's forecast of power generation assumes a 4.1% harmonic
decline starting in 2006. The choice of this decline rate is explained below.
As discussed earlier, the current decline trends of Navy I and Navy II wells
could be approximately fitted to harmonic decline trends of 3.4% and 6.4%,
respectively, starting in January 1992. Similarly, the decline trend of the BLM
wells could be fitted to a harmonic decline trend of 16% starting in mid-1995.
However, since the decline rate itself declines with time in the case of
harmonic decline, these rates would be considerably lower by 2006.
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We estimate harmonic decline rates (as of January, 2006) of 2.4%, 3.5% and 6.4%
for Navy I, Navy II and BLM, respectively. Since these plants all have
approximately the same net generation, it is reasonable to estimate an
arithmetic average decline rate, which is 4.1%. In figure 2.7, the trend
according to GeothermEx's forecast is compared to that of Caithness, which lies
essentially parallel to and within 1 to 5% of GeothermEx's forecast. This
similarity between the two forecasts is remarkable considering that Caithness's
forecast was based on separate estimates of decline rates from six sub-areas
within the Coso field (Navy I West, Navy I East, Navy II West, Navy II East, BLM
East and West, and BLM North) compared to decline trend estimates for three sub-
areas into which the field was divided (Navy I, Navy II and BLM) in preparing
GeothermEx's forecast. We believe that Caithness's forecast is reasonable
because it is very similar to our independent forecast.
2.3 Injection
---------
The Coso projects currently have spare injection capacity to dispose of produced
water and steam condensate. Several injection wells are idle or under-utilized,
particularly at Navy I where many of the production wells have dried out. Plots
of individual injection well histories for the Navy I, Navy II, and BLM projects
are included in Appendices D, E, and F, respectively. Wellhead pressures on
active injectors are generally less than 150 pounds per square inch gauge
(psig). Some of the wellhead pressures in the plots show higher values when
injection rates are low or zero. This is because some injection wells fill with
a column of vapor (steam and NCG) when the rate of injection gets too low. In
this vapor-filled condition, these wells show pressures at the wellhead which
reflect the high pressures of the reservoir. However, once injection is started
again with a high-pressure pump, wellhead pressures typically fall, and the
wells again become capable of taking injection water.
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Some injection wells (particularly on Navy II and BLM) have been affected by the
formation of silica scale. Produced water is treated with sulfuric acid at
several locations in the field to control this scale in surface pipelines and in
injection wells. There has also been some success in using hydrofluoric acid
stimulations to restore the injectivity of wells that have been damaged by
silica scale. In the event of a sudden mechanical problem in an injection well,
it is possible to divert injection water through temporary lines to idle
injection wells until the problem well can be repaired or replaced.
The new low-pressure steam separation systems present some possibility of
silica-scaling in the separators, injection lines and injection wells, because
the low-pressure steam separation results in considerable over-saturation of
silica. To mitigate this scaling, the operator has been testing acidification
of the liquid phase and plans to use this method to control silica scale.
Acidification for scale control has been successfully used at other geothermal
projects, and it is reasonable to expect that it will be successful at Coso.
Properly controlled addition of acid should not result in undue corrosion, and
should provide a significant level of protection to the injection wells.
However, we cannot predict just what the remaining scaling effect on the
injection wells will turn out to be, or the frequency of re-drills or workovers
that could be needed to relieve the effects of downhole scale deposition.
2.4 Gases in Steam
--------------
Historical trends of the hydrogen sulfide (H2S) and the total non-condensible
gases (NCG) in steam have been examined by comparing measurements done since
June 1996 with graphs and detailed tabulations that were compiled in 1997. Gas
concentration trends bear a relationship to reservoir processes, and the H2S
component is of particular interest because releases of H2S to the
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atmosphere are regulated by the government and so H2S must be removed from the
other gases that are released.
Table 2.1 is a summary of the H2S concentration at mid-year at each well, from
1990 through 1998. The status of the H2S trend (stable, decreasing, increasing)
as of mid-1998 is indicated, along with an abbreviated description of the
overall trend during the production history of the well. Total NCG content in
steam is not separately tabulated, but trends of total NCG tend to correlate
closely with trends of H2S.
As of June 1998, nearly all wells had stable or nearly stable gas
concentrations. H2S was decreasing or possibly decreasing at 16 wells, and
possibly increasing at only three wells. Gases at BLM East and BLM West wells
remained particularly stable with one well decreasing and three possibly
decreasing. Most Navy I wells were stable, with three decreasing and three
possibly increasing, but none changing rapidly. At Navy II wells, the gases
were stable in about 2/3 of the cases, and decreasing in about 1/3 of the cases.
The highest concentrations of H2S occur in BLM West, and in the wells on the
East Flank.
The currently stable and decreasing gas concentrations follow earlier
instabilities and transient conditions. By 1996, it was established that most
wells with high initial NCG concentrations had shown rapid decreases in these
concentrations; then, commonly in 1991 or 1992 (1992-3 in the BLM areas), there
was a distinct break in slope to stable conditions or a more gentle and linear
decline trend.
In summary, current trends of gases in Coso steam are either stable of gently
decreasing, and it is unlikely that there will be any significant increase in
the concentrations of H2S or total NCG in Coso steam in the future.
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3. CAPITAL AND OPERATING COSTS
Resource-related costs reviewed herein include those related to drilling new
wells, connecting them to the gathering system (for wells drilled on pads with
existing production wells) or extending the gathering system (for wells drilled
on new pads) and working over existing wells. Figures 3.1, 3.2 and 3.3 show the
costs in these three categories as provided by Caithness, including both
historical data from 1995 through 1998 and projections for 1999 through 2009.
Also included in either the drilling or gathering system costs are the costs of
building low-pressure separators to enable the use of low-pressure steam.
Projected costs for the three projects are summarized in table 3.1. All
projected costs are based on 1999 dollars and are escalated at 3% per year.
As illustrated in figure 3.1, historical drilling expenditures from 1995 to 1998
were in the range of $12 million to $15 million per year, with the exception of
1996, when drilling expenditures were about $2 million. Going forward, the
financial projections include $6.5 million in drilling funds for 1999, about $4
million in 2000, $7 million in 2001, $10.5 million in 2002, and $7.5 to $8.5
million in 2003 - 2006. No drilling is planned after 2006. The number of new
wells to be drilled each year and injection well redrills, which together make
up the drilling costs, are included in table 3.1.
The cost assumed in the financial projections for drilling a new well is $2.75
million in 1999, except for a BLM well to be drilled this year (see discussion
below). Based on documents provided by Caithness, a total of six new wells were
drilled in 1997 and 1998, with an average cost of $2.73 million and an average
depth of approximately 9,000 feet. Considering that the average depths of
future wells will be similar, the estimate of $2.75 million per well is
reasonable. The average productivity of these wells was approximately 8 MW
(gross); this includes the highly
3-1
<PAGE>
[GeothermEx, Inc. Letterhead]
productive East Flank well 38B-9. Without 38B-9, the average productivity was
approximately 5 MW (gross). Caithness has reasonably assumed an average 1999
productivity of 5.6 MW for new wells. The financial projections do not include
any decline in the expected capacity of make-up wells; it remains at 5.6 MW
throughout the project life. While this amount should be expected to decline
according to the decline rate assigned to each area of the field (see Chapter
2), as few make-up wells are planned and the decline rate in well productivity
is very small, the difference between the projections with and without declining
the make-up wells is not significant.
Several production wells were redrilled in 1997 and 1998, at an average cost of
$1.3 million, an average depth of 6,000 feet, and an average productivity of 3.2
MW (gross). No funds are allocated in the financial projections for production
well redrills, as Caithness does not plan to redrill any existing production
wells. However, Caithness reports that there is about $1.5 million per year in
the O&M section of the budget, which will be used for well clean-outs and other
well maintenance. Production well workovers are discussed below. One
injection well redrill per year is planned, with a 1999 cost of $1.2 million per
well, which is reasonable.
In 1999, the drilling costs include an injection well redrill in the BLM and
Navy II areas ($1.2 million each), a purchase of new drill pipe ($150,000,
allocated unequally between Navy II and BLM), drilling a slim exploration well
in BLM North ($400,000), deepening of the existing BLM North well 43-7
($726,000) and drilling BLM North well 43A-7 ($2.9 million). The last is
planned to a total depth of 10,000 feet, which is deeper than other planned
wells at Coso, and accounts for its slightly greater cost.
One injection well redrill and one BLM production well (43B-7) are planned for
2000 (table 3.1). A total of 15 new wells are planned from 1999 through 2006,
which equates to nearly 11 MW per year, using Caithness' assumption of no
decline in the capacity of make-up wells. As indicated by
3-2
<PAGE>
[GeothermEx, Inc. Letterhead]
drilling data provided by Caithness, which are reflected in the costs in figure
3.1, six new wells were drilled in the last two years. Therefore, we would
expect that two to three make-up wells would be needed each year to maintain
production, unless the make-up wells have a higher-than-average capacity which
is expected under Caithness' plan to drill in the East Flank area.
In addition to the cost of drilling a well, there are costs associated with
connecting the well to the gathering system. In the case where a new well is
drilled from a pad with existing production wells, the connection cost is
assumed by Caithness to be $500,000; these are "pad pipelines," which are
charged to the appropriate project. For wells drilled on new pads in the BLM
North and East Flank areas, additional expenses will be incurred to extend the
steam gathering pipelines as indicated in table 3.1; these are "trunk lines,"
which are shared equally between the projects. There are also expenses
associated with additions or modifications to the steam separation equipment
included in this category in 1999 and 2006. The projected gathering system
costs are included in table 3.1 and figure 3.2. We have not independently
estimated the costs of pipelines or LP separation equipment. The well
connection costs are on the conservative side.
The assumptions page of the financial projections indicates a 1999 workover cost
of $700,000 per well; however, discussion with Caithness revealed that $700,000
is budgeted for each unit, which is adequate for approximately two workovers
each year. This is escalated at 3% per year. The workover costs and
frequencies are reasonable. Workovers are assumed to be needed throughout the
life of the project; the escalation of workover costs is shown in table 3.1 and
figure 3.3.
3-3
<PAGE>
Table 2.1: H2S in Steam at Coso Wells
<TABLE>
<CAPTION>
H2S in Steam (parts per million by weight - ppmw) /a/
---------------------------------------------------------- Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Navy 1
- ------------------------------------------------------------------------
66-6 30 insuff insuff
68-6 200 200 135 130 S-D insuff
78-6 130 110 110 110 110 110 110 105 100 S s
78A-6 50 40 40 100 170 170 150 160 S d-i(6/92)
78B-6 110 90 90 100 90 105 S s
43-7 340 insuff
52-7 90 60 45 80 150 170 180 185 185 S d-i(6/93)
52A-7 110 140 130 150 190 195 220 225 I? i-s
52B-7 160 140 140 140 140 175 180 S-I d-s
61-7 40 30 25 80 130 140 150 160 180 I d-i(6/92)
61A-7 45 55 80 110 150 170 170 180 180 I? i
63-7 70 70 70 60 65 75 85 90 95 S s
63A-7 40 40 25 25 50 50 50 60 90 I? d-i(6/92)
63B-7 40 30 55 60 65 100 I s
66-7 250 200 175 175 150 140 115 D d
66A-7 50 80 100 120 120 55 S? i
71-7 70 110 125 150 160 180 175 175 180 S i
71A-7 100 120 130 150 190 200 200 215 215 S i-s
71B-7 80 80 100 100 95 130 S? d-i(6/93)
73-7 20 20 20 120 90 90 90 90 90 S s-(jump 6/92)
73A-7 50 65 75 75 80 90 100 90 100 S i
75-7 225 150 125 120 120 120 120 105 95 D? d-s(6/92)
75A-7 200 140 125 115 115 110 110 95 85 D? d-s(6/92)
75B-7 100 100 100 100 100 100 85 75 D s
76-7 170 120 110 110 100 100 110 90 40 D d-s(6/91)
76A-7 75 75 75 100 100 S? s (irreg.)
76B-7 140 110 100 110 110 100 100 95 110 S d-s
77-7 150 100 100 100 100 100 90 80 85 S-D d-s(6/91)
78-7 300 200 175 150 125 125 125 125 165 S? d-s(6/91)
87-7 100 75 75 75 50 45 50 S d-s(6/92)
87A-7 100 100 100 100 125 S s
15A-8 225 125 100 100 90 90 90 80 80 S d-s(3/92)
16A-8RD 125 140 130 120 110 115 120 100 90 S-D d-s(6/93)
24-8 100 120 125 125 125 120 95 100 S s
47-8 130 100 80 80 80 90 S d-s
47A-8RD 150 150 100 95 95 105 115 S d-s
34A-9 1050 1050 insuff
38-9 500 1000 1000 500 S? insuff
38A-9 630 insuff insuff
Navy 2
- ------------------------------------------------------------------------
78-7 300 200 175 150 125 125 125 insuff d-s(6/91)
22-16 1400 1000 900 850 800 800 S d
51-16 600 600 600 570 530 D? irregular
51A-16 900 850 600 720 630 S insuff. data
64-16 600 450 400 240 D? insuff. data
83A-16 700 500 400 350 450 325 S? d
83B-16 325 250 225 320 140 D d
</TABLE>
Page 1 of 3
<PAGE>
Table 2.1: H2S in Steam at Coso Wells
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------
H2S in Steam (parts per million by weight - ppmw) /a/
---------------------------------------------------------- Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15-17RD 430 300 260 230 210 200 180 140 175 S d-s(12/91)
15A-17RD 350 290 250 210 170 190 210 170 160 S-D d-s(3/94)
37-17 150 120 150 140 120 115 120 S s-d
37A-17 200 110 110 90 80 70 80 70 80 S d-s(6/91)
37B-17 175 125 140 150 140 100 S? s
58A-18 210 insuff
58B-18 290 insuff
63-18RD 375 240 170 150 130 100 100 95 120 S d-s(12/91)
63A-18 500 300 180 180 180 130 140 105 S d-s(6/92)
63B-18 200 150 110 100 100 100 insuff d-s(6/92)
65-18 650 430 400 375 320 330 350 325 235 D? d-s(12/91)
65A-18 900 500 450 500 375 375 375 360 270 D? d-s(6/92)
72-18 175 80 50 45 45 insuff d-s(6/92)
72A-18 175 100 70 50 60 80 95 25 D? d-s(6/92)
72B-18 200 100 75 60 60 60 60 85 45 D? d-s(6/92)
72C-18 200 100 80 70 75 65 65 120 75 S d-s(6/92)
73-18RD 400 150 100 100 80 80 80 65 60 S d-s(6/92)
73A-18 400 200 180 175 160 150 150 130 S d-s(12/91)
76-18 900 600 400 350 350 300 250 400 200 S-D d-s(6/92)
76A-18 650 400 350 300 270 240 200 320 140 D d-s(6/91)
81-18 170 125 100 100 100 100 100 90 110 S d-s(6/92)
81A-18RD 70 insuff
- ------------------------------------------------------------------------
BLM East
- ------------------------------------------------------------------------
16-20 60 55 50 50 40 35 S d-s(6/93)
16A-20 600 650 500 520 510 510 500 S d-s(6/94)
16B-20 175 200 225 250 210 235 S s
24-20 150 150 150 150 150 125 125 125 S s
24A-20 150 100 100 90 80 70 insuff d-s(6/93)
24B-20 80 60 45 50 65 85 60 S? s
32-20 220 140 125 110 100 100 100 100 125 S d-s(6/93)
32A-20 150 80 25 25 25 25 20 20 S d-s(12/92)
34-20 150 110 110 75 60 60 60 insuff d-s(6/93)
34A-20 110 80 60 40 60 50 60 insuff d-s(6/92)
35-20 150 160 150 50 50 40 40 40 S d-s(6/93)
35A-20 100 60 20 20 d-s(12/91)
35A-20RD 40 25 25 10 D? insuff
35B-20 35 25 25 25 25 20 20 5 D? s
- ------------------------------------------------------------------------
</TABLE>
Page 2 of 3
<PAGE>
Table 2.1: H2S in Steam at Coso Wells
<TABLE>
<CAPTION>
H2S in Steam (parts per million by weight - ppmw) /a/
------------------------------------------------------------------ Status
June June June June June June June June June June Historical
Well No. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1998 /b/ Trend to mid-96 /c/
- --------- ------ ---- ---- ---- ---- ---- ---- ---- ---- ---- -------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BLM West
- --------------------------------------------------------------------------------
23-19RD 1050 850 750 700 700 930 830 S d-s(5/94)
33-19 1400 1000 900 800 600 600 600 620 500 S-D d-s?(6/94)
72A-19RD 400 500 500 S
72B-19 500 430 340 D insuff
73-19 1200 900 300 400 700 500 400 410 370 D d(irreg.)
74-19 900 700 600 350 350 400 450 600 580 S? d-s(6/93)
74A-19 500 325 300 275 260 250 250 230 250 S d-s(6/91)
74B-19RD 400 300 270 250 250 250 250 230 270 S d-s(6/91)
81-19 800 700 600 500 425 425 475 580 570 S? d-s(6/93)
81A-19RD 100 30 40 40 40 160 I? d-s(6/93)
81B-19 150 150 S?
33A-19 1300 1200 S?
33B-19 410 310 D?
- --------------------------------------------------------------------------------
</TABLE>
Notes:(a) H2S concentration in bold italics is the highest level.
H2S concentration in bold is the lowest level.
(b) Status June 1998 D = decreasing
S = stable
I = increasing
? = no data or very uncertain
Combined symbols indicate uncertain
condition; e.g.,
S-D = stable or decreasing
(c) Historical Trend d = decreasing
(shown only if there s = stable
is a distinct pattern) i = increasing
d-s = decreasing then stable
d-s (date) = strong decrease followed by
gentle decrease or stable; date
indicates approximate break in slope
d-i (date) = decreasing, followed by
increase; date indicates start of increase
<PAGE>
Table 3.1: Summary of Drilling, Gathering System and Workover Costs for the
Coso Geothermal Project in Caithness pro forma
<TABLE>
<CAPTION>
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1999 Navy I 1/3 of each: East Flank LP
system; 43-7 trunk line; safety
None 0 platforms 1,248 700
-----------------------------------------------------------------------------------------------------------------
Navy II 1/3 of each: East Flank LP
Injection well redrill; system; 43-7 trunk line; safety
1/5 of drill pipe costs 1,225 platforms 1,248 700
-----------------------------------------------------------------------------------------------------------------
BLM deepen 43-7; drill 1/3 of each: East Flank LP
43A-7; injection well system; 43-7 trunk line; safety
redrill; slim platforms, plus BLM LP
exploration hole; 4/5 system; tie-in 43-7, 43A-7 and
of drill pipe costs 5,351 46-19RD 3,248 700
- ------------------------------------------------------------------------------------------------------------------------
2000 Navy I None 0 None 0 721
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,224 None 0 721
-----------------------------------------------------------------------------------------------------------------
BLM Drill well 43B-7 2,918 Tie-in well 43B-7 531 721
- ------------------------------------------------------------------------------------------------------------------------
2001 Navy I Injection well redrill 1,249 None 0 743
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 743
-----------------------------------------------------------------------------------------------------------------
BLM Tie-in 43C-7 and 45-7; 45-7
Drill 43C-7 and 45-7 6,010 pad pipeline 1,639 743
- ------------------------------------------------------------------------------------------------------------------------
2002 Navy I None 0 1/3 Navy II/BLM trunk line 563 765
-----------------------------------------------------------------------------------------------------------------
Navy II Drill 22A-16 and 1/3 Navy II/BLM trunk line plus
22B-16 6,190 tie-in 22A-16 and 22B-16 1,688 765
-----------------------------------------------------------------------------------------------------------------
BLM Injection well redrill; 1/3 Navy II/BLM trunk line plus
drill well 46A-7 4,369 tie-in 46A-7 1,126 765
- ------------------------------------------------------------------------------------------------------------------------
Page 1 of 4
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
2003 Navy I None 0 1/3 Navy I/Navy II trunk line 386 788
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,299 1/3 Navy I/Navy II trunk line 386 788
-----------------------------------------------------------------------------------------------------------------
BLM 1/3 Navy I/Navy II trunk line
Drill 66A-6 and plus tie-in 66A-6 and 66B-6;
66B-6 6,376 66-6 pad pipeline 2,415 788
- ------------------------------------------------------------------------------------------------------------------------
2004 Navy I Drill 38C-9; injection
well redrill 4,635 Tie-in 38C-9 597 812
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 812
-----------------------------------------------------------------------------------------------------------------
BLM Drill 66B-6 3,284 Tie-in 66B-6 597 812
- ------------------------------------------------------------------------------------------------------------------------
2005 Navy I None 0 None 0 836
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 836
-----------------------------------------------------------------------------------------------------------------
BLM Injection well redrill; Tie-in 48-7 and 48B-7; 48-7
drill 48-7 and 48B-7 8,143 pad pipeline 1,845 836
- ------------------------------------------------------------------------------------------------------------------------
2006 Navy I None 0 Separator modifications 950 861
-----------------------------------------------------------------------------------------------------------------
Navy II Injection well redrill 1,406 None 0 861
-----------------------------------------------------------------------------------------------------------------
BLM Drill 48B-7 and Tie-in 48B-7 and 88A-1; 88-1
88A-1 6,967 pad pipeline 2,438 861
- ------------------------------------------------------------------------------------------------------------------------
2007 Navy I None 0 None 0 887
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 887
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 887
- ------------------------------------------------------------------------------------------------------------------------
2008 Navy I None 0 None 0 913
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 913
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 913
- ------------------------------------------------------------------------------------------------------------------------
Page 2 of 4
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
2009 Navy I None 0 None 0 941
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 941
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 941
- ------------------------------------------------------------------------------------------------------------------------
2010 Navy I None 0 None 0 969
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 969
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 969
- ------------------------------------------------------------------------------------------------------------------------
2011 Navy I None 0 None 0 998
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 998
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 998
- ------------------------------------------------------------------------------------------------------------------------
2012 Navy I None 0 None 0 1,028
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,028
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,028
- ------------------------------------------------------------------------------------------------------------------------
2013 Navy I None 0 None 0 1,059
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,059
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,059
- ------------------------------------------------------------------------------------------------------------------------
2014 Navy I None 0 None 0 1,091
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,091
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,091
- ------------------------------------------------------------------------------------------------------------------------
2015 Navy I None 0 None 0 1,123
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,123
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,123
- ------------------------------------------------------------------------------------------------------------------------
Page 3 of 4
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Drilling Gathering System Workover
--------------------------------------------------------------------------
Cost Cost Budget
Year Project Summary ($1,000s) Summary ($1,000s) ($1,000s)
========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
2016 Navy I None 0 None 0 1,157
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,157
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,157
- ------------------------------------------------------------------------------------------------------------------------
2017 Navy I None 0 None 0 1,192
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,192
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,192
- ------------------------------------------------------------------------------------------------------------------------
2018 Navy I None 0 None 0 1,228
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,228
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,228
- ------------------------------------------------------------------------------------------------------------------------
2019 Navy I None 0 None 0 1,264
-----------------------------------------------------------------------------------------------------------------
Navy II None 0 None 0 1,264
-----------------------------------------------------------------------------------------------------------------
BLM None 0 None 0 1,264
- -----------------=======================================================================================================
</TABLE>
Page 4 of 4
<PAGE>
Figure 1.1: Location of Coso geothermal field
[MAP APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 1.2: Well location map, Coso geothermal field
[MAP APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 2.1: Coso MW forecast from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 2.2: Megawatts per well vs. time, Navy I
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 2.3: Megawatts per well vs. time, Navy II
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 2.4: Megawatts per well vs. time, BLM
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 2.5:
Total NCG/Steam Vs. Time - Navy II Well 15-17RD
[GRAPH APPEARS HERE]
Date
<PAGE>
Figure 2.6:
H2S/Steam Vs. Time - Navy II Well 15-17RD
[GRAPH APPEARS HERE]
<PAGE>
Figure 2.7: Comparison of Caithness and GeothermEx MW forecasts
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 3.1: Planned drilling costs at Coso from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 3.2: Planned gathering system costs at Coso from Caithness financial
projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
Figure 3.3: Planned workover costs at Coso from Caithness financial projections
[GRAPH APPEARS HERE]
1999, GeothermEx, Inc.
<PAGE>
APPENDICES A THROUGH F
OF
GEOTHERMAL
CONSULTANT'S REPORT
APPENDICES A THROUGH F OF THE GEOTHERMAL CONSULTANT'S REPORT HAVE BEEN OMITTED
FROM THIS PROSPECTUS. YOU CAN OBTAIN COPIES OF THESE APPENDICES FROM US UPON
REQUEST.
<PAGE>
APPENDICES A THROUGH F
OF
GEOTHERMAL
CONSULTANT'S REPORT
APPENDICES A THROUGH F OF THE GEOTHERMAL CONSULTANT'S REPORT HAVE BEEN
OMITTED FROM THIS PROSPECTUS. YOU CAN OBTAIN COPIES OF THESE APPENDICES
FROM US UPON REQUEST (SUBJECT TO POSSIBLE CONFIDENTIALITY RESTRICTIONS).
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
October 7, 1999
All tendered Series A notes, executed letters of transmittal and other
related documents should be directed to the exchange agent. Questions and
requests for assistance and requests for additional copies of this prospectus,
letters of transmittal and other related documents should also be addressed to
the exchange agent.
Caithness Coso Funding Corp.
Offer to Exchange
6.80% Series B Senior Secured Notes Due 2001
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
6.80% Series A Senior Secured Notes Due 2001
and
9.05% Series B Senior Secured Notes due 2009
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
9.05% Series A Senior Secured Notes due 2009
-----------------------
PROSPECTUS
-----------------------
Exchange Agent:
U.S. Bank Trust National Association
180 East Fifth Street
St. Paul, Minnesota 55101
- --------------------------------------------------------------------------------
We have not authorized any dealer, salesperson or other person to give you
written information other than this prospectus or to make representations as to
matters not stated in this prospectus. You must not rely on unauthorized
information. This prospectus is not an offer to sell the securities or our
solicitation of your offer to buy the securities in any jurisdiction where that
would not be permitted or legal. Neither the delivery of this prospectus nor
any sales made hereunder after the date of this prospectus shall create an
implication that the information contained herein or the affairs of Caithness
Energy, L.L.C., Caithness Coso Funding Corp., Coso Finance Partners, Coso
Energy Developers or Coso Power Developers have not changed since the date of
this prospectus.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 20. Indemnification of Directors and Officers
Pursuant to Section 102(b)(7) of the Delaware General Corporations Law,
Article IX of the Certificate of Incorporation for Funding Corp. (the
"Certificate of Incorporation") provides that no director of Funding Corp.
shall be liable to Funding Corp. or its stockholders for monetary damages for a
breach of fiduciary duty as a director, except to the extent that exculpation
from liability is not permitted under the Delaware General Corporation Law as
in effect at the time such liability is determined.
Article X of the Certificate of Incorporation further provides that Funding
Corp. shall, to the fullest extent permitted under the laws of the State of
Delaware, indemnify, and upon request, advance expenses to its directors and
officers against liabilities that may arise by reason of their status or
service as directors, officers, trustees, partners, employees, or agents of the
Corporation. Officers and directors shall be indemnified against expenses
(including attorney's fees and expenses), judgments, fines, penalties, and
amounts paid in settlement incurred in connection with the investigation,
preparation, and defense of such actions, suits, proceedings, or claims.
However, Funding Corp. will not be required to indemnify or advance expenses to
any person in connection with such actions, suits, proceedings or claims when
the action, suit, proceeding or claim was initiated by or on behalf of the
officer or director seeking indemnity.
Article XIV of the general partnership agreement of each of Coso Power
Developers, Coso Finance Partners and Coso Energy Developers (collectively, the
"General Partnership Agreements") empower each such partnership to indemnify
and hold harmless its managing partner, and the officers, directors,
shareholders, and agents of its managing partner ("Indemnitees") from and
against any and all losses, claims, demands, costs, damages, judgments, fines,
settlements and expenses (including attorney's fees and disbursements) arising
out of or incidental to the business of each partnership provided that
Indemnitee's conduct did not constitute fraud, willful misconduct, or gross
negligence. Article XIV of each of the General Partnership Agreements also
provides that the managing partner, in its capacity as such, or its officers,
directors, shareholders, employees, or agents will not be held liable to their
respective partnership or other partners of such partnership for any expense,
loss, or liability suffered by such partnership or other partners of such
partnership in connection with that partnership's activities, provided that the
managing partner or its affiliates acted in good faith and without gross
negligence and had previously determined that such a course of conduct was in
the best interests of the partnership.
The foregoing discussion of the Certificate of Incorporation, Bylaws, the
General Partnership Agreements, and Delaware law is not intended to be
exhaustive and is qualified in its entirety by the Certificate of
Incorporation, Bylaws, the General Partnership Agreements and the relevant
provisions of Delaware Corporation Law.
II-1
<PAGE>
Item 21. Exhibits and Financial Statement Schedules.
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
3.1* Certificate of Incorporation of Caithness Coso Funding Corp.
3.2* Bylaws of Caithness Coso Funding Corp.
3.3 Third Amended and Restated Partnership Agreement of Coso Finance
Partners, dated as of May 28, 1999.
3.4 Third Amended and Restated Partnership Agreement of Coso Energy
Developers, dated as of May 28, 1999.
3.5 Third Amended and Restated Partnership Agreement of Coso Power
Developers, dated as of May 28, 1999.
3.6 Amendment Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Caithness Acquisition Company, LLC, New CLOC
Company, LLC, ESCA, LLC and Coso Operating Company LLC.
3.7 Amendment Agreement, dated as of May 28, 1999, by and among Coso
Energy Developers, Caithness Acquisition Company, LLC, New CHIP
Company, LLC, Caithness Coso Holdings, LLC and Coso Operating Company
LLC.
3.8 Amendment Agreement, dated as of May 28, 1999, by and among Coso Power
Developers, Caithness Acquisition Company, LLC, New CTC Company, LLC,
Caithness Navy II Group, LLC and Coso Operating Company LLC.
4.1* Indenture, dated as of May 28, 1999, among Caithness Coso Funding
Corp., Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and U.S. Bank Trust National Association as trustee and as
collateral agent.
4.2* Specimen Series B notes (included in Exhibit 4.1).
4.3* Notation of Guarantee, dated as of May 28, 1999, of Coso Finance
Partners.
4.4* Notation of Guarantee, dated as of May 28, 1999, of Coso Energy
Developers.
4.5* Notation of Guarantee, dated as of May 28, 1999, of Coso Power
Developers.
4.6* Registration Rights Agreement, dated as of May 28, 1999, by and among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and Donaldson, Lufkin & Jenrette
Securities Corporation.
5.1 Opinion of Riordan & McKinzie, A Professional Law Corporation.
5.2 Opinion of Reed Smith Shaw & McClay LLP.
10.1* Deposit and Disbursement Agreement, dated as of May 28, 1999, among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and U.S. Bank Trust National
Association, as collateral agent, as trustee, and as depositary.
10.2* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Finance Partners.
10.3* Promissory Note due 2001 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.4* Promissory Note due 2009 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.5* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Energy Developers.
10.6* Promissory Note due 2001 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.7* Promissory Note due 2009 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.8* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Power Developers.
10.9* Promissory Note due 2001 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
</TABLE>
II-2
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.10* Promissory Note due 2009 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.11* Purchase Agreement, dated as of May 21, 1999, by and among Caithness
Coso Funding Corp., as issuer, Coso Finance Partners, Coso Energy
Developers and Coso Power Developers, as guarantors, and Donaldson,
Lufkin & Jenrette Securities Corporation, as initial purchaser.
10.12* Security Agreement, dated as of May 28, 1999, executed by and among
Caithness Coso Funding Corp. in favor of U.S. Bank Trust National
Association, as collateral agent.
10.13* Security Agreement, dated as of May 28, 1999, executed by and among
Coso Finance Partners in favor of U.S. Bank Trust National
Association, as collateral agent.
10.14* Security Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.15* Security Agreement, dated as of May 28, 1999, executed by Coso Power
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.16 Sale Agreement dated October 6, 1999, between Caithness Acquisitions
Company, LLC and ESI Geothermal, Inc.
10.17* Reserved.
10.18 Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.19* Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.20* Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by Coso Operating Company LLC in favor of U.S. Bank
Trust National Association, as collateral agent.
10.21* Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.22* Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.23* Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by FPL Energy Operating Services, Inc., in favor of
U.S. Bank Trust National Association, as collateral agent.
10.24* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Finance Partners
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.25* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.26* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Power Developers
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.27* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Transmission
Line Partners in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.28* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by China Lake Joint
Venture in favor of U.S. Bank Trust National Association, as trustee,
and as beneficiary.
10.29* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Land Company in
favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
</TABLE>
II-3
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.30* Stock Pledge Agreement, dated as of May 28, 1999, by Coso Finance
Partners, Coso Energy Developers and Coso Power Developers in favor of
U.S. Bank Trust National Association, as collateral agent.
10.31* Partnership Interest Pledge Agreement (Navy I), dated as of May 28,
1999, by ESCA, LLC and New CLOC Company, LLC, in favor of U.S. Bank
Trust National Association, as collateral agent.
10.32* Partnership Interest Pledge Agreement (BLM), dated as of May 28, 1999,
by Caithness Coso Holdings, LLC and New CHIP Company, LLC, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.33* Partnership Interest Pledge Agreement (Navy II), dated as of May 28,
1999, by Caithness Navy II Group, LLC and New CTC Company, LLC, in
favor of U.S. Bank Trust National Association, as collateral agent.
10.34* Partnership Interest Pledge Agreement (CTLP), dated as of May 28,
1999, by Coso Energy Developers and Coso Power Developers, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.35* Partnership Interest Pledge Agreement (CLJV), dated as of May 28,
1999, by Caithness Acquisition Company, LLC and Caithness Geothermal
1980 Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.36* Partnership Interest Pledge Agreement (CLC), dated as of May 28, 1999,
by Caithness Acquisition Company, LLC and Caithness Geothermal 1980
Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.37* Promissory Notes Security Agreement, dated as of May 28, 1999, by
Caithness Coso Funding Corp., in favor of U.S. Bank Trust National
Association, as collateral agent.
10.38* Original Service Contract N62474-79-C-5382, dated December 6, 1979,
between U.S. Naval Weapons Center and California Energy Company, Inc.,
Contractor (the "Navy Contract"), including all amendments thereto.
10.39* Escrow Agreement, dated December 16, 1992, as amended, by and among
Coso Finance Partners, Bank of America and the Navy.
10.40* Offer to Lease and Lease for Geothermal Resources, Serial No. 11402,
dated April 29, 1985 but effective May 1, 1985, from the United States
of America, acting through the Bureau of Land Management, to
California Energy Company, Inc.; as assigned by Assignment Affecting
Record Title to Geothermal Resources Lease, dated June 24, 1985, but
effective July 1, 1985 from California Energy Company, Inc. to Coso
Land Company; as assigned by Assignment of Record Title Interest in a
Lease for Oil and Gas or Geothermal Resources, dated April 20, 1988,
but effective May 1, 1988 from Coso Land Company to Coso Geothermal
Company; as assigned by Assignment of Record Title Interest in a Lease
for Oil and Gas or Geothermal Resources dated April 20, 1988 but
effective
May 1, 1988 from Coso Geothermal Company to Coso Energy Developers.
10.41* Geothermal Resources Lease, Serial No. CA-11383, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of January 1, 1988; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company , dated September 10, 1997; as assigned by Assignment of
Record Title Interest in Lease for Oil and Gas or Geothermal
Resources, by and between the United States of America, acting through
the Bureau of Land Management, and Coso Land Company, effective
January 1, 1998; and as extended by extension of primary term of CACA-
11383 to September 23, 2004.
</TABLE>
II-4
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.42* Geothermal Resources Lease, Serial No. CA-11384, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11384), by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.43* Geothermal Resources Lease, Serial No. CA-11385, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11385) by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.44* License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, Licensor, through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No. CACA
22512, dated March 8, 1989 (expires 3/8/19).
10.45* License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, acting through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No.
25690, dated 12/29/1989 (expires 12/28/19).
10.46* Right of Way CA-18885 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated May 7, 1986 (telephone cable) (expires 5/7/16).
10.47* Right of Way CA-13510 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated April 12, 1984 (Coso office site) (expires
4/12/14).
10.48* Agreement of Transfer and Assignment (Navy I Transmission Line), dated
July 14, 1987, among China Lake Joint Venture and Coso Finance
Partners.
10.49* Agreement of Transfer and Assignment (Navy II Transmission Line),
dated July 31, 1989, among Coso Power Developers and Coso Transmission
Line Partners.
10.50* Agreement of Transfer and Assignment (BLM Transmission Line), dated
July 31, 1989, among Coso Energy Developers and Coso Transmission Line
Partners.
10.51* Agreement Regarding Overriding Royalty (CLC Royalty), dated May 5,
1988, between Coso Energy Developers and Coso Land Company.
10.52* Coso Geothermal Exchange Agreement, dated January 11, 1994, by and
among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.53* Amendment to Coso Geothermal Exchange Agreement, dated April 12, 1995,
by and among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.54* Reserved.
10.55* Operation and Maintenance Agreement (Navy I Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CLOC Company, LLC.
</TABLE>
II-5
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.56* Operation and Maintenance Agreement (BLM Project), dated May 28, 1999,
by and among FPL Energy Operating Services, Inc. and Coso Operating
Company, LLC and New CHIP Company, LLC.
10.57* Operation and Maintenance Agreement (Navy II Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CTC Company, LLC.
10.58* Field Operation and Maintenance Agreement (Navy I), dated February 25,
1999, between Coso Operating Company, LLC and New CLOC Company, LLC.
10.59* Field Operations and Maintenance Agreement (Navy II), dated February
25, 1999, between Coso Operating Company, LLC and New CTC Company,
LLC.
10.60* Field Operations and Maintenance Agreement (BLM), dated February 25,
1999, between Coso Operating Company, LLC and New CHIP Company, LLC.
10.61* Purchase Agreement, dated as of January 16, 1999, by and among
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, and
California Energy Company, Inc.
10.62* Agreement Concerning Consideration, dated as of February 25, 1999, by
and among Caithness Energy, L.L.C., Caithness Acquisition Company,
L.L.C., New CLOC Company, LLC, New CHIP Company, LLC, New CTC Company,
LLC, and CalEnergy Company, Inc.
10.63* Future Revenue Agreement, dated February 25, 1999, by and between
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, New CTC
Company, LLC, New CLOC Company, LLC, New CHIP Company, LLC, Coso
Finance Partners, Coso Energy Developers, Coso Power Developers, and
California Energy Company, Inc.
10.64* Acknowledgment and Agreement--Release, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., James Bishop Sr.,and Caithness CEA
Geothermal, L.P. (appended to Exhibit 10.61).
10.65* Acknowledgment and Agreement--Indemnity, dated May 28, 1999, executed
by Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso
Energy Developers, New CHIP Company, LLC, Caithness Coso Holdings,
LLC, Coso Power Developers, New CTC Company, LLC, and Caithness Navy
II Group, LLC.
10.66* Acknowledgment and Agreement--Release, dated May 28, 1999, executed by
Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso Energy
Developers, New CHIP Company, LLC, Caithness Coso Holdings, LLC, Coso
Power Developers, New CTC Company, LLC, and Caithness Navy II Group,
LLC.
10.67* Acknowledgment and Agreement--Indemnity, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., China Lake Operating Company, Coso Technology
Corporation and Coso Hotsprings Intermountain Power (appended to
Exhibit 10.61).
10.68* Power Purchase Agreement (modified Standard Offer No.4) (Navy I),
dated as of June 4, 1984, as amended, by and between Southern
California Edison Company and Coso Finance Partners (as assignee of
China Lake Joint Venture).
10.69* Power Purchase Agreement (modified Standard Offer No.4) (BLM), dated
as of February 1, 1985, by and between Southern California Edison
Company and Coso Energy Developers (as assignee of China Lake Joint
Venture).
10.70* Power Purchase Agreement (modified Standard Offer No.4) (Navy II),
dated as of February 1, 1985, by and between Southern California
Edison Company and Coso Power Developers (as assignee of China Lake
Joint Venture).
10.71* Reserved.
</TABLE>
II-6
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.72* Interconnection and Integration Facilities Agreement (BLM project),
dated December 15, 1988, between Southern California Edison Company
and Coso Energy Developers (as assignee of China Lake Joint Venture).
10.73* Interconnection and Integration Facilities Agreement (Navy II
project), dated December 15, 1988, between Southern California Edison
Company and Coso Power Developers (as assignee of China Lake Joint
Venture).
10.74* Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.75* Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among FPL Energy Operating Services, Inc., and U.S. Bank Trust
National Association, as collateral agent.
10.76* Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.77* Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.78* Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among Coso Operating Company, LLC, and U.S. Bank Trust National
Association, as collateral agent.
10.79* Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.80* Management Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among ESCA, LLC, New CLOC Company, LLC, Coso Finance
Partners, and U.S. Bank Trust National Association, as collateral
agent.
10.81* Management Fee Subordination Agreement (BLM), dated as of May 28,
1999, by and among Caithness Coso Holdings, LLC, New CHIP Company,
LLC, Coso Energy Developers, and U.S. Bank Trust National Association,
as collateral agent.
10.82* Management Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Caithness Navy II Group, LLC, New CTC Company, LLC,
Coso Power Developers, and U.S. Bank Trust National Association, as
collateral agent.
10.83* Cotenancy Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Coso Energy Developers, and Coso Power Developers.
10.84* Acquisition Agreement, dated as of May 28, 1999, among Coso Land
Company, Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and Coso Operating Company, LLC.
10.85* Assignment and Assumption Agreement, dated as of May 28, 1999, by and
among MidAmerican Energy Holdings Company as successor-in-interest to
Cal Energy Company, Inc., Coso Energy Developers, Coso Power
Developers and Coso Finance Partners.
12.1* Statement regarding computation of Coso Finance Partners ratio of
earnings to fixed charges.
12.2* Statement regarding computation of Coso Energy Developers ratio of
earnings to fixed charges.
12.3* Statement regarding computation of Coso Power Developers ratio of
earnings to fixed charges.
21.1* Subsidiaries of Caithness Coso Funding Corp., Coso Finance Partners,
Coso Energy Developers, and Coso Power Developers.
23.1 Consent of KPMG LLP, Independent Accountants.
23.2 Consent of PricewaterhouseCoopers LLP, Independent Accountants.
23.3 Consent of Sandwell Engineering Inc.
23.4 Consent of Henwood Energy Services, Inc.
</TABLE>
II-7
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
23.5 Consent of GeothermEx, Inc.
23.6 Consent of Riordan & McKinzie, A Professional Law Corporation
(included in Exhibit 5.1).
23.7 Consent of Reed Smith Shaw & McClay LLP (included in Exhibit 5.2).
24.1* Powers of Attorney (included on pages II-9, II-11, II-13 and II-15).
25.1* Form T-1 Statement of Eligibility and Qualification of U.S. Bank Trust
National Association as Trustee.
27.1 Financial Data Schedule--Caithness Coso Funding Corp.
27.2 Financial Data Schedule--Coso Finance Partners.
27.3 Financial Data Schedule--Coso Energy Developers.
27.4 Financial Data Schedule--Coso Power Developers.
99.1 Form of Letter of Transmittal.
99.2 Form of Notice of Guaranteed Delivery.
99.3 Letter to Registered Holders and The Depositary Trust Company
Participants.
99.4 Letter to Clients.
99.5 Letter to Registered Holder and/or Book-Entry Transfer Facility
Participant.
</TABLE>
- ---------------------
* Previously filed.
Item 22. Undertakings
The undersigned Registrant hereby undertakes as follows:
1. That, insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the registrant pursuant to the foregoing provisions,
or otherwise, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public
policy as expressed in the Act, and is, therefore, unenforceable. In the
event that a claim for indemnification against such liabilities (other than
the payment by the registrant of expenses incurred by the payment of a
director, officer, or controlling person of the registrant in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer, or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the
matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
2. To respond to requests for information that is incorporated by reference
into the prospectus pursuant to Item 4, 10(b), 11, or 13 of this form,
within one business day of receipt of such requests, and to send the
incorporated documents by first class mail or other equally prompt means.
This includes information contained in documents filed subsequent to the
effective date of the registration statement through the date of responding
to the request.
3. To supply by means of a post-effective amendment all information concerning
a transaction, and the company being acquired involved therein, that was not
the subject of and included in the registration statement when it became
effective.
II-8
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Amendment No. 1 to Registration
Statement on Form S-4 to be signed on behalf of the undersigned thereunto duly
authorized, in the City of New York, on October 6, 1999.
Caithness Coso Funding Corp.,
a Delaware corporation
/s/ Christopher T. McCallion
By: _________________________________
Christopher T. McCallion
Executive Vice President and Chief
Financial Officer
Pursuant to the requirements of the Securities Act of 1933, this Registration
Statement has been signed by the following persons in the capacities and on the
dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ James D. Bishop, Sr. Director, Chairman and Chief October 6, 1999
____________________________________ Executive Officer
James D. Bishop, Sr. (Principal Executive
Officer)
/s/ Christopher T. McCallion Director, Executive Vice October 6, 1999
____________________________________ President and Chief
Christopher T. McCallion Financial Officer
(Principal Accounting
Officer)
/s/ Leslie J. Gelber Director, President and October 6, 1999
____________________________________ Chief Operating Officer
Leslie J. Gelber
/s/ James D. Bishop, Jr. Director October 6, 1999
____________________________________
James D. Bishop, Jr.
/s/ Larry K. Carpenter Director October 6, 1999
____________________________________
Larry K. Carpenter
/s/ James C. Sullivan Director October 6, 1999
____________________________________
James C. Sullivan
/s/ Mark A. Ferrucci Director October 6, 1999
____________________________________
Mark A. Ferrucci
</TABLE>
II-9
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Amendment No. 1 to Registration
Statement on Form S-4 to be signed on behalf of the undersigned thereunto duly
authorized, in the City of New York, October 6, 1999.
Coso Finance Partners,
a California general partnership
By: New CLOC Company, LLC,
its Managing General Partner
/s/ Christopher T. McCallion
By: _________________________________
Christopher T. McCallion
Executive Vice President
Pursuant to the requirements of the Securities Act of 1933, this Registration
Statement has been signed by the following persons in the capacities and on the
dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ James D. Bishop, Sr. Chief Executive Officer of October 6, 1999
____________________________________ New CLOC Company, LLC, as
James D. Bishop, Sr. Managing General Partner of
Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Christopher T. McCallion Executive Vice President and October 6, 1999
____________________________________ Chief Financial Officer of
Christopher T. McCallion New CLOC Company, LLC, as
Managing General Partner of
Registrant (Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager of
New CLOC Company, LLC, as
Managing General Partner of
Registrant
</TABLE>
II-10
<PAGE>
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Leslie Gelber President and Chief October 6, 1999
____________________________________ Operating Officer of New
Leslie Gelber CLOC Company, LLC, as
Managing General Partner of
Registrant; Director of
Caithness Acquisition
Company, LLC, as Manager of
New CLOC Company, LLC, as
Managing General Partner of
Registrant
/s/ James D. Bishop, Jr. Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CLOC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New October 6, 1999
____________________________________ CLOC Company, LLC, as
Mark A. Ferrucci Managing General Partner of
Registrant
</TABLE>
II-11
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Amendment No. 1 to Registration
Statement on Form S-4 to be signed on behalf of the undersigned thereunto duly
authorized, in the City of New York, on October 6, 1999.
Coso Energy Developers,
a California general partnership
By: New CHIP Company, LLC,
its Managing General Partner
/s/ Christopher T. McCallion
By: _________________________________
Christopher T. McCallion
Executive Vice President
Pursuant to the requirements of the Securities Act of 1933, this Registration
Statement has been signed by the following persons in the capacities and on the
dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ James D. Bishop, Sr. Chief Executive Officer of October 6, 1999
_________________________________ New CHIP Company, LLC, as
James D. Bishop, Sr. Managing General Partner
of Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ Christopher T. McCallion Executive Vice President October 6, 1999
_________________________________ and Chief Financial
Christopher T. McCallion Officer of New CHIP
Company, LLC, as Managing
General Partner of
Registrant (Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager
of New CHIP Company, LLC,
as Managing General
Partner of Registrant
</TABLE>
II-12
<PAGE>
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Leslie Gelber President and Chief October 6, 1999
_________________________________ Operating Officer of New
Leslie Gelber CHIP Company, LLC, as
Managing General Partner
of Registrant; Director
of Caithness Acquisition
Company, LLC, as Manager
of New CHIP Company, LLC,
as Managing General
Partner of Registrant
/s/ James D. Bishop, Jr. Director of Caithness October 6, 1999
_________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness October 6, 1999
_________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness October 6, 1999
_________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CHIP
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New October 6, 1999
_________________________________ CHIP Company, LLC, as
Mark A. Ferrucci Managing General Partner
of Registrant
</TABLE>
II-13
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
undersigned Registrant has duly caused this Amendment No. 1 to Registration
Statement on Form S-4 to be signed on behalf of the undersigned thereunto duly
authorized, in the City of New York, on October 6, 1999.
Coso Power Developers,
a California general partnership
By: New CTC Company, LLC,
its Managing General Partner
/s/ Christopher T.
McCallion
By: ______________________________
Christopher T. McCallion
Executive Vice President
POWER OF ATTORNEY
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed by the following persons in the capacities and on the
dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ James D. Bishop, Sr. Chief Executive Officer of October 6, 1999
____________________________________ New CTC Company, LLC, as
James D. Bishop, Sr. Managing General Partner of
Registrant (Principal
Executive Officer);
Director of Caithness
Acquisition Company, LLC,
as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Christopher T. McCallion Executive Vice President and October 6, 1999
____________________________________ Chief Financial Officer of
Christopher T. McCallion New CTC Company, LLC, as
Managing General Partner of
Registrant ( Principal
Financial Officer and
Principal Accounting
Officer); Director of
Caithness Acquisition
Company, LLC, as Manager of
New CTC Company, LLC, as
Managing General Partner of
Registrant
</TABLE>
II-14
<PAGE>
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Leslie Gelber President and Chief October 6, 1999
____________________________________ Operating Officer of New
Leslie Gelber CTC Company, LLC, as
Managing General Partner;
Director of Caithness
Acquisition Company, LLC,
as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James D. Bishop, Jr. Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
James D. Bishop, Jr. as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Larry K. Carpenter Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
Larry K. Carpenter as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ James C. Sullivan Director of Caithness October 6, 1999
____________________________________ Acquisition Company, LLC,
James C. Sullivan as Manager of New CTC
Company, LLC, as Managing
General Partner of
Registrant
/s/ Mark A. Ferrucci Independent Manager of New October 6, 1999
____________________________________ CTC Company, LLC, as
Mark A. Ferrucci Managing General Partner of
Registrant
</TABLE>
II-15
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
3.1* Certificate of Incorporation of Caithness Coso Funding Corp.
3.2* Bylaws of Caithness Coso Funding Corp.
3.3 Third Amended and Restated Partnership Agreement of Coso Finance
Partners, dated as of May 28, 1999.
3.4 Third Amended and Restated Partnership Agreement of Coso Energy
Developers, dated as of May 28, 1999.
3.5 Third Amended and Restated Partnership Agreement of Coso Power
Developers, dated as of May 28, 1999.
3.6 Amendment Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Caithness Acquisition Company, LLC, New CLOC
Company, LLC, ESCA, LLC and Coso Operating Company LLC.
3.7 Amendment Agreement, dated as of May 28, 1999, by and among Coso
Energy Developers, Caithness Acquisition Company, LLC, New CHIP
Company, LLC, Caithness Coso Holdings, LLC and Coso Operating Company
LLC.
3.8 Amendment Agreement, dated as of May 28, 1999, by and among Coso Power
Developers, Caithness Acquisition Company, LLC, New CTC Company, LLC,
Caithness Navy II Group, LLC and Coso Operating Company LLC.
4.1* Indenture, dated as of May 28, 1999, among Caithness Coso Funding
Corp., Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and U.S. Bank Trust National Association as trustee and as
collateral agent.
4.2* Specimen Series B notes (included in Exhibit 4.1).
4.3* Notation of Guarantee, dated as of May 28, 1999, of Coso Finance
Partners.
4.4* Notation of Guarantee, dated as of May 28, 1999, of Coso Energy
Developers.
4.5* Notation of Guarantee, dated as of May 28, 1999, of Coso Power
Developers.
4.6* Registration Rights Agreement, dated as of May 28, 1999, by and among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and Donaldson, Lufkin & Jenrette
Securities Corporation.
5.1 Opinion of Riordan & McKinzie, A Professional Law Corporation.
5.2 Opinion of Reed Smith Shaw & McClay LLP.
10.1* Deposit and Disbursement Agreement, dated as of May 28, 1999, among
Caithness Coso Funding Corp., Coso Finance Partners, Coso Energy
Developers, Coso Power Developers, and U.S. Bank Trust National
Association, as collateral agent, as trustee, and as depositary.
10.2* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Finance Partners.
10.3* Promissory Note due 2001 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.4* Promissory Note due 2009 of Coso Finance Partners in favor of
Caithness Coso Funding Corp.
10.5* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Energy Developers.
10.6* Promissory Note due 2001 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.7* Promissory Note due 2009 of Coso Energy Developers in favor of
Caithness Coso Funding Corp.
10.8* Credit Agreement, dated as of May 28, 1999, between Caithness Coso
Funding Corp. and Coso Power Developers.
10.9* Promissory Note due 2001 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.10* Promissory Note due 2009 of Coso Power Developers in favor of
Caithness Coso Funding Corp.
10.11* Purchase Agreement, dated as of May 21, 1999, by and among Caithness
Coso Funding Corp., as issuer, Coso Finance Partners, Coso Energy
Developers and Coso Power Developers, as guarantors, and Donaldson,
Lufkin & Jenrette Securities Corporation, as initial purchaser.
10.12* Security Agreement, dated as of May 28, 1999, executed by and among
Caithness Coso Funding Corp. in favor of U.S. Bank Trust National
Association, as collateral agent.
10.13* Security Agreement, dated as of May 28, 1999, executed by and among
Coso Finance Partners in favor of U.S. Bank Trust National
Association, as collateral agent.
10.14* Security Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.15* Security Agreement, dated as of May 28, 1999, executed by Coso Power
Developers in favor of U.S. Bank Trust National Association, as
collateral agent.
10.16 Sale Agreement dated October 6, 1999, between Caithness Acquisitions
Company, LLC and ESI Geothermal, Inc.
10.17* Reserved.
10.18 Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.19* Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by Coso Operating Company LLC in favor of U.S. Bank Trust
National Association, as collateral agent.
10.20* Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by Coso Operating Company LLC in favor of U.S. Bank
Trust National Association, as collateral agent.
10.21* Security Agreement (Navy I project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.22* Security Agreement (BLM project permits), dated as of May 28, 1999,
executed by FPL Energy Operating Services, Inc., in favor of U.S. Bank
Trust National Association, as collateral agent.
10.23* Security Agreement (Navy II project permits), dated as of May 28,
1999, executed by FPL Energy Operating Services, Inc., in favor of
U.S. Bank Trust National Association, as collateral agent.
10.24* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Finance Partners
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.25* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Energy
Developers in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.26* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Power Developers
in favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
10.27* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Transmission
Line Partners in favor of U.S. Bank Trust National Association, as
trustee, and as beneficiary.
10.28* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by China Lake Joint
Venture in favor of U.S. Bank Trust National Association, as trustee,
and as beneficiary.
10.29* Deed of Trust, Assignment of Rents, Fixture Filing and Security
Agreement, dated as of May 28, 1999, executed by Coso Land Company in
favor of U.S. Bank Trust National Association, as trustee, and as
beneficiary.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.30* Stock Pledge Agreement, dated as of May 28, 1999, by Coso Finance
Partners, Coso Energy Developers and Coso Power Developers in favor of
U.S. Bank Trust National Association, as collateral agent.
10.31* Partnership Interest Pledge Agreement (Navy I), dated as of May 28,
1999, by ESCA, LLC and New CLOC Company, LLC, in favor of U.S. Bank
Trust National Association, as collateral agent.
10.32* Partnership Interest Pledge Agreement (BLM), dated as of May 28, 1999,
by Caithness Coso Holdings, LLC and New CHIP Company, LLC, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.33* Partnership Interest Pledge Agreement (Navy II), dated as of May 28,
1999, by Caithness Navy II Group, LLC and New CTC Company, LLC, in
favor of U.S. Bank Trust National Association, as collateral agent.
10.34* Partnership Interest Pledge Agreement (CTLP), dated as of May 28,
1999, by Coso Energy Developers and Coso Power Developers, in favor of
U.S. Bank Trust National Association, as collateral agent.
10.35* Partnership Interest Pledge Agreement (CLJV), dated as of May 28,
1999, by Caithness Acquisition Company, LLC and Caithness Geothermal
1980 Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.36* Partnership Interest Pledge Agreement (CLC), dated as of May 28, 1999,
by Caithness Acquisition Company, LLC and Caithness Geothermal 1980
Ltd., L.P., in favor of U.S. Bank Trust National Association, as
collateral agent.
10.37* Promissory Notes Security Agreement, dated as of May 28, 1999, by
Caithness Coso Funding Corp., in favor of U.S. Bank Trust National
Association, as collateral agent.
10.38* Original Service Contract N62474-79-C-5382, dated December 6, 1979,
between U.S. Naval Weapons Center and California Energy Company, Inc.,
Contractor (the "Navy Contract"), including all amendments thereto.
10.39* Escrow Agreement, dated December 16, 1992, as amended, by and among
Coso Finance Partners, Bank of America and the Navy.
10.40* Offer to Lease and Lease for Geothermal Resources, Serial No. 11402,
dated April 29, 1985 but effective May 1, 1985, from the United States
of America, acting through the Bureau of Land Management, to
California Energy Company, Inc.; as assigned by Assignment Affecting
Record Title to Geothermal Resources Lease, dated June 24, 1985, but
effective July 1, 1985 from California Energy Company, Inc. to Coso
Land Company; as assigned by Assignment of Record Title Interest in a
Lease for Oil and Gas or Geothermal Resources, dated April 20, 1988,
but effective May 1, 1988 from Coso Land Company to Coso Geothermal
Company; as assigned by Assignment of Record Title Interest in a Lease
for Oil and Gas or Geothermal Resources dated April 20, 1988 but
effective
May 1, 1988 from Coso Geothermal Company to Coso Energy Developers.
10.41* Geothermal Resources Lease, Serial No. CA-11383, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of January 1, 1988; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company , dated September 10, 1997; as assigned by Assignment of
Record Title Interest in Lease for Oil and Gas or Geothermal
Resources, by and between the United States of America, acting through
the Bureau of Land Management, and Coso Land Company, effective
January 1, 1998; and as extended by extension of primary term of CACA-
11383 to September 23, 2004.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.42* Geothermal Resources Lease, Serial No. CA-11384, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11384), by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.43* Geothermal Resources Lease, Serial No. CA-11385, by and between the
United States of America, acting through the Bureau of Land
Management, and the LADWP, effective as of February 1, 1982; as
assigned by Lease Assignment Agreement by and between LADWP and Coso
Land Company, dated September 10, 1997; as assigned by Assignment of
Record Title Interest in a Lease for Oil and Gas or Geothermal
Resources (CACA-11385) by and between the United States of America,
acting through the Bureau of Land Management, and Coso Land Company,
effective as of January 1, 1998; and as extended by extension of
primary term of CACA-11385 to December 24, 2002.
10.44* License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, Licensor, through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No. CACA
22512, dated March 8, 1989 (expires 3/8/19).
10.45* License for Electric Power Plant Site Utilizing Geothermal Resources
between the United States of America, acting through the Bureau of
Land Management, and Coso Energy Developers, Licensee, Serial No.
25690, dated 12/29/1989 (expires 12/28/19).
10.46* Right of Way CA-18885 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated May 7, 1986 (telephone cable) (expires 5/7/16).
10.47* Right of Way CA-13510 by and between the United States of America,
acting through the Bureau of Land Management, and California Energy
Company, Inc., dated April 12, 1984 (Coso office site) (expires
4/12/14).
10.48* Agreement of Transfer and Assignment (Navy I Transmission Line), dated
July 14, 1987, among China Lake Joint Venture and Coso Finance
Partners.
10.49* Agreement of Transfer and Assignment (Navy II Transmission Line),
dated July 31, 1989, among Coso Power Developers and Coso Transmission
Line Partners.
10.50* Agreement of Transfer and Assignment (BLM Transmission Line), dated
July 31, 1989, among Coso Energy Developers and Coso Transmission Line
Partners.
10.51* Agreement Regarding Overriding Royalty (CLC Royalty), dated May 5,
1988, between Coso Energy Developers and Coso Land Company.
10.52* Coso Geothermal Exchange Agreement, dated January 11, 1994, by and
among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.53* Amendment to Coso Geothermal Exchange Agreement, dated April 12, 1995,
by and among Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and California Energy Company, Inc.
10.54* Reserved.
10.55* Operation and Maintenance Agreement (Navy I Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CLOC Company, LLC.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.56* Operation and Maintenance Agreement (BLM Project), dated May 28, 1999,
by and among FPL Energy Operating Services, Inc. and Coso Operating
Company, LLC and New CHIP Company, LLC.
10.57* Operation and Maintenance Agreement (Navy II Project), dated May 28,
1999, by and among FPL Energy Operating Services, Inc. and Coso
Operating Company, LLC and New CTC Company, LLC.
10.58* Field Operation and Maintenance Agreement (Navy I), dated February 25,
1999, between Coso Operating Company, LLC and New CLOC Company, LLC.
10.59* Field Operations and Maintenance Agreement (Navy II), dated February
25, 1999, between Coso Operating Company, LLC and New CTC Company,
LLC.
10.60* Field Operations and Maintenance Agreement (BLM), dated February 25,
1999, between Coso Operating Company, LLC and New CHIP Company, LLC.
10.61* Purchase Agreement, dated as of January 16, 1999, by and among
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, and
California Energy Company, Inc.
10.62* Agreement Concerning Consideration, dated as of February 25, 1999, by
and among Caithness Energy, L.L.C., Caithness Acquisition Company,
L.L.C., New CLOC Company, LLC, New CHIP Company, LLC, New CTC Company,
LLC, and CalEnergy Company, Inc.
10.63* Future Revenue Agreement, dated February 25, 1999, by and between
Caithness Energy, L.L.C., Caithness Acquisition Company, LLC, New CTC
Company, LLC, New CLOC Company, LLC, New CHIP Company, LLC, Coso
Finance Partners, Coso Energy Developers, Coso Power Developers, and
California Energy Company, Inc.
10.64* Acknowledgment and Agreement--Release, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., James Bishop Sr., and Caithness CEA
Geothermal, L.P. (appended to Exhibit 10.61).
10.65* Acknowledgment and Agreement--Indemnity, dated May 28, 1999, executed
by Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso
Energy Developers, New CHIP Company, LLC, Caithness Coso Holdings,
LLC, Coso Power Developers, New CTC Company, LLC, and Caithness Navy
II Group, LLC.
10.66* Acknowledgment and Agreement--Release, dated May 28, 1999, executed by
Coso Finance Partners, New CLOC Company, LLC, ESCA, LLC, Coso Energy
Developers, New CHIP Company, LLC, Caithness Coso Holdings, LLC, Coso
Power Developers, New CTC Company, LLC, and Caithness Navy II Group,
LLC.
10.67* Acknowledgment and Agreement--Indemnity, dated January 16, 1999,
executed by Caithness Resources, Inc., Caithness Corporation,
Caithness Power, L.L.C., China Lake Operating Company, Coso Technology
Corporation and Coso Hotsprings Intermountain Power (appended to
Exhibit 10.61).
10.68* Power Purchase Agreement (modified Standard Offer No.4) (Navy I),
dated as of June 4, 1984, as amended, by and between Southern
California Edison Company and Coso Finance Partners (as assignee of
China Lake Joint Venture).
10.69* Power Purchase Agreement (modified Standard Offer No.4) (BLM), dated
as of February 1, 1985, by and between Southern California Edison
Company and Coso Energy Developers (as assignee of China Lake Joint
Venture).
10.70* Power Purchase Agreement (modified Standard Offer No.4) (Navy II),
dated as of February 1, 1985, by and between Southern California
Edison Company and Coso Power Developers (as assignee of China Lake
Joint Venture).
10.71* Reserved.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.72* Interconnection and Integration Facilities Agreement (BLM project),
dated December 15, 1988, between Southern California Edison Company
and Coso Energy Developers (as assignee of China Lake Joint Venture).
10.73* Interconnection and Integration Facilities Agreement (Navy II
project), dated December 15, 1988, between Southern California Edison
Company and Coso Power Developers (as assignee of China Lake Joint
Venture).
10.74* Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.75* Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among FPL Energy Operating Services, Inc., and U.S. Bank Trust
National Association, as collateral agent.
10.76* Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among FPL Energy Operating Services, Inc., and U.S. Bank
Trust National Association, as collateral agent.
10.77* Operating Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.78* Operating Fee Subordination Agreement (BLM), dated as of May 28, 1999,
by and among Coso Operating Company, LLC, and U.S. Bank Trust National
Association, as collateral agent.
10.79* Operating Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Coso Operating Company, LLC, and U.S. Bank Trust
National Association, as collateral agent.
10.80* Management Fee Subordination Agreement (Navy I), dated as of May 28,
1999, by and among ESCA, LLC, New CLOC Company, LLC, Coso Finance
Partners, and U.S. Bank Trust National Association, as collateral
agent.
10.81* Management Fee Subordination Agreement (BLM), dated as of May 28,
1999, by and among Caithness Coso Holdings, LLC, New CHIP Company,
LLC, Coso Energy Developers, and U.S. Bank Trust National Association,
as collateral agent.
10.82* Management Fee Subordination Agreement (Navy II), dated as of May 28,
1999, by and among Caithness Navy II Group, LLC, New CTC Company, LLC,
Coso Power Developers, and U.S. Bank Trust National Association, as
collateral agent.
10.83* Cotenancy Agreement, dated as of May 28, 1999, by and among Coso
Finance Partners, Coso Energy Developers, and Coso Power Developers.
10.84* Acquisition Agreement, dated as of May 28, 1999, among Coso Land
Company, Coso Finance Partners, Coso Energy Developers, Coso Power
Developers, and Coso Operating Company, LLC.
10.85* Assignment and Assumption Agreement, dated as of May 28, 1999, by and
among MidAmerican Energy Holdings Company as successor-in-interest to
Cal Energy Company, Inc., Coso Energy Developers, Coso Power
Developers and Coso Finance Partners.
12.1* Statement regarding computation of Coso Finance Partners ratio of
earnings to fixed charges.
12.2* Statement regarding computation of Coso Energy Developers ratio of
earnings to fixed charges.
12.3* Statement regarding computation of Coso Power Developers ratio of
earnings to fixed charges.
21.1* Subsidiaries of Caithness Coso Funding Corp., Coso Finance Partners,
Coso Energy Developers, and Coso Power Developers.
23.1 Consent of KPMG LLP, Independent Accountants.
23.2 Consent of PricewaterhouseCoopers LLP, Independent Accountants.
23.3 Consent of Sandwell Engineering Inc.
23.4 Consent of Henwood Energy Services, Inc.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
23.5 Consent of GeothermEx, Inc.
23.6 Consent of Riordan & McKinzie, A Professional Law Corporation
(included in Exhibit 5.1).
23.7 Consent of Reed Smith Shaw & McClay LLP (included in Exhibit 5.2).
24.1* Powers of Attorney (included on pages II-9, II-11, II-13 and II-15).
25.1* Form T-1 Statement of Eligibility and Qualification of U.S. Bank Trust
National Association as Trustee.
27.1 Financial Data Schedule--Caithness Coso Funding Corp.
27.2 Financial Data Schedule--Coso Finance Partners.
27.3 Financial Data Schedule--Coso Energy Developers.
27.4 Financial Data Schedule--Coso Power Developers.
99.1 Form of Letter of Transmittal.
99.2 Form of Notice of Guaranteed Delivery.
99.3 Letter to Registered Holders and The Depositary Trust Company
Participants.
99.4 Letter to Clients.
99.5 Letter to Registered Holder and/or Book-Entry Transfer Facility
Participant.
</TABLE>
- ---------------------
* Previously filed.
<PAGE>
EXHIBIT 3.3
THIRD AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT
OF
COSO FINANCE PARTNERS
This Third Amended and Restated General Partnership Agreement (the
"Agreement"), of Coso Finance Partners (the "Partnership") dated as of May 28,
1999, is between (a) ESCA, LLC, a Delaware limited liability company (successor
by merger with ESCA Limited Partnership, a California limited partnership)
("ESCA") and (b) New CLOC Company, LLC, a Delaware limited liability company
("New CLOC").
R E C I T A L S
- - - - - - - -
On December 6, 1979, CalEnergy Company, Inc., a Delaware corporation
(formerly known as California Energy Company, Inc.) ("CECI") entered into a
contract (the "Navy Contract") with the United States Navy (the "Navy") to
develop geothermal energy at the Naval Weapons Center, China Lake, California,
and to sell the resultant electricity to the Navy.
CECI and Caithness Geothermal 1980 Ltd., a Delaware limited partnership
(successor by merger with Caithness Geothermal 1980 Ltd., a New Jersey limited
partnership) ("CG-80") entered into a Joint Venture Agreement to form the China
Lake Joint Venture ("CLJV") on December 17, 1980 (as amended and restated from
time to time, the "CLJV Agreement"). The CLJV Agreement set forth the
relationship between CECI and CG-80 regarding the development and operation of a
geothermal power generating system at the Naval Weapons Center; established a
Management Committee; designated CECI the "Operator"; set forth the Operator's
rights and duties; and provided guidelines for conduct of the geothermal power
project.
CECI assigned its rights and obligations under the Navy Contract to CLJV on
December 17, 1980. The assignment was approved by the Navy on December 24,
1980.
On July 7, 1987, CLOC and ESCA entered into the General Partnership
Agreement of Coso Finance Partners (the "1987 Agreement"), creating the
Partnership. The Partnership entered into certain agreements in connection with
the acquisition of Turbine 1 (as hereinafter defined) and the Turbine 1 Project
Area Rights (as hereinafter defined).
At the time of entering into the 1987 Agreement, the partners and their
affiliates contemplated that Turbine 1 would be financed, owned and operated by
the Partnership, and that Turbines 2 and 3 (as hereinafter defined) would be
owned and operated by CFP II (as hereinafter defined). Subsequent to that time,
the Partners determined that it was the best interests of the Partnership to
have all of the Turbines owned and operated by a single entity to provide for
operation of the Turbine 1 Project and the Turbines 2 and 3 Project as a
combined project and to provide for allocation of profits and losses and
distributions in a manner as if separate ownership of Turbine 1 and Turbines 2
and 3 had been maintained.
<PAGE>
ESCA, CLOC and partners of CFP II transferred and assigned to the
Partnership the Division II Assigned Rights (as hereinafter defined).
Pursuant to that certain Agreement and Plan of Merger dated as of February
25, 1999, CLOC was merged with and into New CLOC, and New CLOC became the
successor-in-interest to CLOC.
Concurrently with this Agreement, the Partnership is acquiring, subject to
the approval of the United States Department of the Interior, Bureau of Land
Management ("BLM"), an undivided interest as a tenant-in-common in and to the
BLM Leases (as hereinafter defined) and has entered into the Co-Tenancy
Agreement (as hereinafter defined) in order to utilize the resources from said
land for the Combined Project (as hereinafter defined).
Concurrently with this Agreement, (1) China Lake Geothermal Management
Company, Inc. ("CLGMC"), a general partner of Coso Finance Partners II, a
California general partnership ("CFP II"), has dissolved and distributed its
general partnership interest in CFP II to its sole shareholder, Caithness
Acquisition Company, LLC, a Delaware limited liability company ("CAC"), which
contributed the interest to New CLOC; (2) ESCA Limited Partnership, a California
limited partnership, has converted into ESCA; (3) ESCA II Limited Partnership II
("ESCA II") has merged with and into ESCA; and (4) CFP II has merged with and
into CFP.
The parties hereto desire to provide for the continued existence and
governance of the Partnership and to set forth in detail their respective rights
and duties relating to the Partnership.
NOW, THEREFORE, in consideration of the mutual covenants, conditions and
agreements herein contained, the parties agree that the Original Agreement shall
be amended and restated so that the operative provisions shall read in their
entirety as follows:
ARTICLE I
DEFINITIONS
The capitalized words and phrases used in this Agreement shall, unless the
context otherwise requires, have the meanings specified in this Article I.
1.1 "Act" means the California Uniform Partnership Act, as amended from
time to time.
1.2 "Agreement" or "Partnership Agreement" means this Third Amended and
Restated General Partnership Agreement, as amended from time to time. Words
such as "herein", "hereof", "hereto" and "hereunder" refer to this Agreement as
a whole, unless the context otherwise requires.
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1.3 "AMJV" means Atkinson-Mitsubishi Joint Venture, a joint venture
between Guy F. Atkinson Company, a Nevada corporation, and Mitsubishi Heavy
Industries America, Inc., a Delaware corporation.
1.4 "AMJV Project Agreement" means the Coso Geothermal Project Agreement
between CLJV and AMJV, dated February 12, 1986, as amended.
1.5 "AMJV Royalties" means the Plant Royalty and the Well Residual more
fully described in the AMJV Project Agreement and that certain Project Royalty
and Warranty Agreement, dated as of July 14, 1987, by and among AMJV, CFP and
CLJV, as amended, which assigned to CFP pursuant to the Assignment of Royalty
and Residual Interests and Mutual Release of Claims by and among AMJV, CFP and
CLJV dated July 14, 1998, and as may be further amended.
1.6 "BLM Leases" means that certain (i) Geothermal Resources Lease, Serial
No. CA-11384, by and between the United States of America, acting through the
BLM, and the LADWP, effective as of February 1, 1982, as amended; (ii)
Geothermal Resources Lease, Serial No. CA-11385, by and between the United
States of America, acting through the BLM, and the LADWP, effective as of
February 1, 1982, as amended; and, (iii) Geothermal Resources Lease, Serial No.
CA-11383, by and between the United States of America, acting through the BLM,
and the LADWP, effective as of February 1, 1982, as amended.
1.7 "Book" when used to modify an item of income, gain, loss or deduction,
or any word in reference thereto, means the amount thereof taken into account
for capital accounting purposes under the principles of Section 1.10 and
Regulation Section 1.704-1(b)(2)(iv).
1.8 "Budget" means each of the budgets to be prepared by the Managing
Partner and approved by the Management Committee pursuant to Section 7.4.
1.9 "Business Day" means any day that is not a Saturday, Sunday or a day
on which banking institutions in the City of San Francisco, State of California,
are authorized or required to close by law, executive order or Regulation.
1.10 "Capital Account" with respect to each Partner means the capital
account of that Partner determined and maintained throughout the full term of
the Partnership in accordance with the capital accounting rules set forth in
Regulation Section 1.704-1(b)(2)(iv). The initial balance of each Partner's
Capital Account is set forth at Section 4.1. As a result of the reorganizations
described in the Recitals, the capital contributions by ESCA, New CLOC, ESCA II
and CLGMC are in the amounts reflected on the Partnership's books. In the event
the Managing Partner determines that it is prudent to modify the manner in which
the Capital Accounts, or any debits or credits thereto (including, without
limitation, debits or credits relating to liabilities which are secured by
contributed or distributed property, or assumed by the Partnership with regard
to such asset with the approval of the Partnership), are computed in order to
comply with such
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Regulations, the Managing Partner may make such modification, provided that it
is not likely to have a material effect on the amounts distributable to any
Partner. The Managing Partner also shall make any modification, provided that it
is not likely to have a material effect on the amounts distributable to any
Partner, in the event unanticipated events cause this Agreement not to comply
with Regulation Section 1.704.1(b). Subject to the four previous sentences:
(a) Each Partner's Capital Account shall be increased by (i) the
amount of money contributed by such Partner to the Partnership; (ii) the Fair
Market Value of property contributed by such Partner to the Partnership (net of
liabilities secured by such contributed property that the Partnership is
considered to assume or take subject to under Code Section 752); and (iii)
Partnership income and gain (or items thereof) allocated to such Partner. Each
Partner's Capital Account shall be decreased by (iv) the amount of money
distributed to such Partner by the Partnership; (v) the Fair Market Value of
property distributed to such Partner by the Partnership (net of liabilities
secured by such distributed property that such Partner is considered to assume
or take subject to under Code Section 752); (vi) Partnership loss (or item
thereof) allocated to such Partner; (vii) the Partner's share of expenditures of
the Partnership described in Code Section 705(a)(2)(B), including for this
purpose losses which are nondeductible under Code Section 267(a)(1) or Code
Section 707(b); and (viii) the Partner's share of amounts paid or incurred by
the Partnership to organize the Partnership or to promote the sale of (or to
sell) an interest in the Partnership (except to the extent properly amortizable
for tax purposes).
(b) For this purpose, "income" refers to all items of income
(including all items of gain and including income exempt from tax) as properly
determined for Book purposes, and "loss" refers to all items of loss (including
all items of deduction) as properly determined for Book purposes.
(c) An assumption of a Partner's unsecured liability by the
Partnership shall be treated as a distribution of money to the Partner. An
assumption of the Partnership's unsecured liability by a Partner shall be
treated as a cash contribution to the Partnership.
(d) Capital Accounts shall be adjusted appropriately on account of
investment tax credit and investment tax credit recapture in accordance with the
principles of Code Section 48 (q).
(e) In the event that assets of the Partnership other than cash are
distributed to a Partner in kind, Capital Accounts shall be adjusted for the
hypothetical Book gain or Book loss that would have been realized by the
Partnership if the distributed assets had been sold for their Fair Market Value
in a cash sale (in order to reflect unrealized Book gain or Book loss).
(f) At the option of the Management Committee, in the event of a
contribution of money or other property (other than a de minimus amount) to the
Partnership by a new or existing Partner as consideration for an interest in the
Partnership, or in connection with a distribution of money or other property
(other than a de minimus amount) by the Partnership to a
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retiring or continuing Partner as consideration for an interest in the
Partnership, Capital Accounts shall be adjusted for the hypothetical Book gain
or Book loss that would have been realized by the Partnership if all Partnership
assets had been sold for their Fair Market Value in a cash sale (in order to
reflect unrealized Book gain or Book loss).
1.11 "Capital Contribution" means the amount of money plus the Fair Market
Value of property contributed by a Partner to the Partnership.
1.12 "Capital Events" shall mean a Division I Capital Event and/or a
Division II Capital Event.
1.13 "Cash Flow from Capital Events" shall mean the net proceeds from each
Capital Event which the Management Committee makes available for distribution
after the Management Committee has set aside the amounts deemed prudent by the
Management Committee to: (a) replace tangible property disposed of or destroyed
and (b) provide working capital for the Partnership.
1.14 "CED" means Coso Energy Developers, a California general partnership.
1.15 "CFP" or the "Partnership" means Coso Finance Partners, a California
general partnership of which the Managing Partner is New CLOC, and the other
general partner is ESCA, being the partnership organized under the Act by the
Original Agreement and as such partnership may be constituted from time to time.
1.16 "CFP II" means Coso Finance Partners II, a California general
partnership of which the Managing Partner immediately prior to the merger of CFP
II into CFP was China Lake Geothermal Management Company, a Delaware
corporation, and the other partner was ESCA Limited Partnership II, a California
limited partnership.
1.17 "CFP II Royalty" means the royalty rights originally retained by CFP
II pursuant to that certain Assignment and Royalty Agreement between CFP and CFP
II dated July 14, 1988 which shall be held by the Partnership after the date
hereof.
1.18 "COC" means Coso Operating Company LLC, a Delaware limited liability
company.
1.19 "Code" means the Internal Revenue Code of 1986, as amended from time
to time, and any succeeding law.
1.20 "Combined Project" means the Turbine 1 Project together with the
Turbine 2 and 3 Project.
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1.21 "Co-Tenancy Agreement" means that certain Co-Tenancy Agreement, dated
as of even date herewith, by and between, the Coso Power Developers, a
California general partnership, Coso Energy Developers, a California general
partnership, and the Partnership
1.22 "CPD" means Coso Power Developers, a California general partnership.
1.23 "Distribution Condition" shall have the meaning set forth on Exhibit
D hereto.
1.24 "Distribution Date" means the 45th day following the end of each
calendar quarter, commencing with the third quarter of 1987, or the next
succeeding Business Day if such day is not a Business Day.
1.25 "Division I Assigned Rights" means the following rights assigned by
CLJV to CFP in partial consideration of the issuance of Interests to CLOC and
ESCA, which assignment was made in connection with the 1987 Agreement:
(a) the Turbine 1 Project Area Rights;
(b) the Power Sales Contract;
(c) an assignment of all assignable Turbine 1 Project Authorizations;
and
(d) CLJV's rights to acquire Turbine 1 and all other assets and
rights pursuant to "Buy-out", as described in the AMJV Project Agreement.
The Division I Assigned Rights are subject to all related monetary
obligations and liabilities assumed by the Partnership.
1.26 "Division I Capital Event" means any of the following: (a) a sale,
exchange, transfer, assignment or other disposition of all or a portion of any
Turbine 1 Project asset (but not including occasional sales in the ordinary
course of business of inventory, furniture, fixtures and equipment); (b) any
financing or refinancing of, or with respect to, a Turbine 1 Project asset; (c)
any condemnation or deeding in lieu of condemnation of a Turbine 1 Project
asset; (d) any collection with respect to property, hazard or casualty insurance
(but not business interruption insurance) or any damage award; or (e) any other
Turbine 1 Project transaction the proceeds of which, in accordance with
generally accepted accounting principles, are considered to be capital in
nature.
1.27 "Division I Cash Flow from Capital Events" means Cash Flow from
Capital Events pertaining to ownership and operation of the Turbine 1 Project.
1.28 "Division I Cash Flow from Operations" means, with respect to any
fiscal period and determined on the basis of a closing or interim closing of the
books as of the end of such
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period: (a) all cash receipts received during such fiscal period by the
Partnership attributable to the Turbine 1 Project (other than Division I Cash
Flow from Capital Events and Division I Capital Contributions); plus (b) any
amounts that were originally reserved from amounts that would otherwise have
been Division I Cash Flow from Operations that are no longer deemed by the
Management Committee to be required as reserves; less (c) all cash outlays
during such fiscal period to pay expenses of the Partnership attributable to the
Turbine 1 Project; less (d) amounts paid by the Partnership with respect to AMJV
Royalties, Tudesco Royalties and Navy Sinking Fund Payments; less (e) any
amounts set aside as reserves attributable to the Turbine 1 Project, including
reserves for capital improvements, expenses or contingent liabilities; less (f)
payments (and reserves for payments) of debt service (and premiums or penalties
thereon, if any) on indebtedness of the Partnership attributable to the Turbine
1 Project.
1.29 "Division I Payout" shall mean the point at which all Partners have
received distributions from Division I Cash Flow from Capital Events or Division
I Cash Flow from Operations in an aggregate amount equal to: (i) $14,509,815 for
CLOC, or (ii) $20,375,658 for ESCA, respectively, plus (iii) any cash
contributions to the Turbine 1 Project and the cash value, as determined by the
Management Committee, of any property contributed to the Turbine 1 Project after
December 31, 1988, plus (iv) a simple return of ten percent (10%) per annum on
the sum of (i), (ii), and (iii), as applicable, accrued from and after December
31, 1988, provided, however, that the 10% distribution of Division I Cash Flow
from Operations to the Managing Partner under Section 5.1(a) shall not be
considered a distribution in computing whether Division I Payout has been
achieved."
1.30 "Division II Assigned Rights" means the following rights assigned to
the Partnership by CFP II (subject to Section 4.1), which at the time was in
partial consideration of the CFP II Royalty:
(a) the Turbines 2 and 3 Project Area Rights;
(b) the Turnkey Contract together with all work in progress,
guarantees, security interests and subject to all liens thereunder; and
(c) an assignment of all assignable Turbines 2 and 3 Project
Authorizations.
The Division II Assigned Rights are subject to all related monetary
obligations and liabilities assumed by the Partnership.
1.31 "Division II Capital Event" means any of the following: (a) a sale,
exchange, transfer, assignment or other disposition of all or a portion of any
Turbines 2 and 3 Project asset (but not including occasional sales in the
ordinary course of business of inventory, furniture, fixtures and equipment);
(b) any financing or refinancing of, or with respect to, a Turbines 2 and 3
Project asset; (c) any condemnation or deeding in lieu of condemnation of a
Turbines 2 and 3 Project asset; (d) any collection with respect to property,
hazard or casualty insurance (but not
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business interruption insurance) or any damage award; or (e) any other Turbines
2 and 3 Project transaction the proceeds of which, in accordance with generally
accepted accounting principles, are considered to be capital in nature.
1.32 "Division II Cash Flow from Capital Events" means the Cash Flow from
Capital Events pertaining to the ownership and operation of the Turbines 2 and 3
Project.
1.33 "Division II Cash Flow from Operations" means, with respect to any
fiscal period and determined on the basis of a closing or interim closing of the
books as of the end of such period: (a) all cash receipts received during such
fiscal period by the Partnership attributable to the Turbines 2 and 3 Project
(other than Division II Cash Flow from Capital Events and Division II Capital
Contributions); plus (b) any amounts that were originally reserved from amounts
that would otherwise have been Division II Cash Flow from Operations that are no
longer deemed by the Management Committee to be required as reserves; plus (c)
the AMJV Royalties less (d) all cash outlays during such fiscal period to pay
expenses of the Partnership attributable to the Turbines 2 and 3 Project; less
(e) any amounts set aside as reserves attributable to the Turbines 2 and 3
Project, including reserves for capital improvements, expenses or contingent
liabilities; less (f) payments (and reserves for payments) of debt service (and
premiums or penalties thereon, if any) on indebtedness of the Partnership
attributable to the Turbines 2 and 3 Project.
1.34 "Division II Payout" means the point at which all Partners have
received distributions from Division II Cash Flow from Capital Events or
Division II Cash Flow from Operations in an aggregate amount equal to: (i)
$5,254,773 for CLOC, or (ii) $6,099,775 for ESCA, plus (iii) any cash
contributions and the cash value, as determined by the Management Committee, of
any property contributed to the Turbines 2 and 3 Project after December 31,
1988, plus (iv) a simple return of ten percent (10%) per annum on the sum of
(i), (ii) and (iii) accrued from and after December 31, 1988, provided, however,
that the 10% distribution of Division II Cash Flow from Operations to the
Managing Partner under Section 5.3(a) shall not be considered a distribution in
computing whether Division II Payout has been achieved.
1.35 "ESCA Operating Agreement" means that certain Limited Liability
Company Agreement of ESCA, LLC, a Delaware limited liability company dated as of
the date hereof.
1.36 "Escrow Account" means an interest-bearing deposit account acceptable
to the partners of each Joint Venture and established in the name of Managing
Partner with a bank acceptable to the Partners pursuant to an escrow or other
similar agreement which is acceptable to each such Partner and contains
distribution provisions in form attached as Exhibit E to this Agreement.
1.37 "Excess Revenues" means, with respect to a period and a Project, one
half of the difference between (a) the revenue for the Project for the period,
minus (b) the revenue which would have been produced if the Project had operated
continuously during the period at 85% of
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nominal capacity (calculated at an assumed capacity of 80 MW for the CPD Project
and the CFP Project and 70 MW for the CED Project).
1.38 "Fair Market Value" shall mean the fair market value of an asset, as
reasonably agreed to among the Partners in arm's-length negotiations, net of
liabilities secured by such asset or assumed by the Partnership with regard to
such asset.
1.39 "FPLE" means FPL Energy Operating Services, Inc. a Florida
corporation.
1.40 "Indenture" means that certain Trust Indenture dated as of the date
hereof, by and between Caithness Coso Funding Corp., the Joint Ventures and U.S.
Bank Trust National Association.
1.41 "Interest" means a partnership interest in the Partnership with the
rights, terms and preferences described in this Agreement.
1.42 "Joint Venture" means any or all of CED, CPD and the Partnership.
1.43 "Management Committee" means the Management Committee established
pursuant to Article VIII.
1.44 "Managing Partner" means New CLOC.
1.45 "Maximum Payment" means an amount equal to the Preferred Return.
1.46 "Meeting" means a meeting of Partners or of the Management Committee
duly called in accordance with Article VIII hereof.
1.47 "MPE" means Mission Power Engineering Company, a California
corporation.
1.48 "Navy Contract" means the Original Service Contract N62474-79-C-5382
dated December 6, 1979 between the United States Navy and CECI, as amended and
restated, and assigned.
1.49 "Navy Power Payment" means the payment for NAVWPNCEN Power, as
defined in Section 3(d) of Modification P00008 to the Navy Contract, delivered
with respect to Turbine 1.
1.50 "Navy Sinking Fund Payments" means the periodic payments set aside by
CFP to fund its obligations to the Navy upon termination of the Navy Contract as
described in Section 8 of Modification P00008 to the Navy Contract.
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1.51 "Net Profit" and "Net Loss" of the Partnership means the net "income"
and net "loss", respectively, of the Partnership, as those terms are used in
1.10(b).
1.52 "Operator" means such operator as is designated by the Managing
Partner pursuant to Article VII.
1.53 "Original Agreement" means the 1987 Agreement, as amended prior to
the date hereof.
1.54 "Partners" means the Managing Partner, ESCA and all substituted or
additional Partners. Where no distinction is required by the context in which
the term is used herein, "Partner" means any one of the Partners.
1.55 "Plant Operations" means the operation and maintenance of all aspects
of Turbine 1 operation and Turbines 2 and 3 operations which do not constitute
Resource Operations, including operation of the Transmission Line, power
transmission facilities and substation interconnection facilities.
1.56 "Power Sales Contract" means the Agreement between CLJV and the
Southern California Edison Company, a California corporation, dated June 4,
1984, as amended, assigned to CFP on July 14, 1987.
1.57 "Preferred Return" means, (a) $7,500,000, plus (b) the amount of
Preferred Return Interest accrued during any previous Preferred Return Year that
was not paid from distributions from the Escrow Account for that Preferred
Return year, less (c) the sum of all distributions from the Escrow Account
previously applied to reduce the Preferred Return. Notwithstanding the
foregoing, the Preferred Return was prepaid in full at a discount to the parties
entitled thereto on December 16, 1992; provided, however, that if for any
Preferred Return Year for which the Preferred Return would have been paid if
such prepayment had not been made the Distribution Condition is not satisfied,
then ESCA shall promptly pay to the Escrow Account an amount equal to its
proportionate share (based on the percentage share of the Preferred Return paid
to it) of $715,000, which is the amount of the Preferred Return allocable to
each Preferred Return Year after taking into account the discount in connection
with the prepayment, to be distributed pursuant to Exhibit E.
1.58 "Preferred Return Interest" means, (a) an amount equivalent to the
aggregate of the interest which would have accrued from March 19, 1991 through
the date of determination on the amount of the Preferred Return, as adjusted to
reflect distributions for each previous Preferred Return Year, at a per annum
rate of 10%, less (b) the sum of all distributions from the Escrow Account
previously applied to reduce Preferred Return Interest.
1.59 "Preferred Return Year" means each of the periods beginning on July 1
and ending on the immediately subsequent June 30. The first Preferred Return
Year shall begin on
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July 1, 1991, and the last Preferred Return Year shall end on the date on which
the Preferred Return would have been reduced to zero if there had been no
prepayment.
1.60 "Project Manager" shall mean the person appointed pursuant to Section
8.5.
1.61 "Projects" means the three geothermal power projects owned by the
Joint Ventures.
1.62 "Regulation" means the Treasury Regulations promulgated under the
Code, as such Regulations may be amended from time to time including
corresponding provisions of any succeeding Regulations.
1.63 "Resource Operations" means the well drilling and well operation and
maintenance work for the Turbine 1 Project Area and the Turbines 2 and 3 Project
Area, as well as the operation and maintenance of the geothermal resource
related to the Turbine 1 Project Area and the Turbines 2 and 3 Project Area, the
surface steam gathering system and brine disposal system, together with
construction and maintenance of buildings, roads and other surface structures on
the Turbine 1 Project Area and the Turbines 2 and 3 Project Area.
1.64 "Section," unless preceded by the words "Code" or "Regulation," means
a Section of this Agreement.
1.65 "Transmission Line" means the 28.8 mile (approximate) power line
further described in Exhibit C.
1.66 "Tudesco Royalties" means the amounts payable to Tudesco Geosource
Ltd. pursuant to the Agreement dated March 26, 1987 between CLJV and Tudesco
Geosource Ltd.
1.67 "Turbine 1" means Unit 1 of the geothermal power plant with a maximum
net output of approximately 25 megawatts and its associated facilities as
constructed by AMJV (including but not limited to the surface steam gathering
system, brine disposal system, power transmission facilities, substation
interconnection facilities and other facilities and equipment necessary to
generate, meter, sell and deliver power from Unit 1) together with any
replacements or substitutes; but excludes all geothermal resources and wells.
1.68 "Turbine 1 Project" means the construction and operation of Turbine
1, and the development and operation of the Turbine 1 Project Area Rights and,
from and after the date of this Agreement and subject to and in accordance with
the terms and conditions of the Co-Tenancy Agreement, the rights and interests
under the BLM Leases.
1.69 "Turbine 1 Project Area" means the area described in Exhibit A.
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1.70 "Turbine 1 Project Area Rights" means the rights, titles, interests,
estates, powers and privileges CLJV has pursuant to the Navy Contract with
respect to the Turbine 1 Project Area, including rights to all wells, the
Transmission Line, the Turbine 1 plant site, and other facilities (and all
improvements, equipment, fixtures and other items appurtenant or accessorial to
such wells or facilities), and including rights of access and egress to the
Turbine 1 Project Area, subject to the terms and conditions of the Navy
Contract, and, from and after the date of this Agreement and subject to and in
accordance with the terms and conditions of the Co-Tenancy Agreement, the rights
and interests under the BLM Leases.
1.71 "Turbine 1 Project Authorizations" means all permits, authorizations,
rights of way and licenses necessary or appropriate to operate and maintain
Turbine 1 and the geothermal resources subject to the Turbine 1 Project Area
Rights.
1.72 "Turbines 2 and 3" mean Units 2 and 3 of the geothermal power plant,
each having a maximum net output of approximately 25 megawatts and their
associated facilities as constructed by MPE pursuant to the Turnkey Contract
(including but not limited to the surface steam gathering system, brine disposal
system, power hookups to connect Units 2 and 3 to the Transmission Line and
other facilities and equipment necessary to generate meter, sell and deliver
power from Units 2 and 3); but excludes all geothermal resources and wells, and
excludes the Transmission Line.
1.73 "Turbines 2 and 3 Project" means the construction and operation of
geothermal power plants on the Turbines 2 and 3 Project Area, and the
development and operation of the Turbines 2 and 3 Project Area Rights and, from
and after the date of this Agreement and subject to and in accordance with the
terms and conditions of the Co-Tenancy Agreement, the rights and interests under
the BLM Leases.
1.74 "Turbines 2 and 3 Project Area" means the area described in Exhibit
B.
1.75 "Turbines 2 and 3 Project Area Rights" means the rights, titles,
interests, estates, powers and privileges which CFP II has assigned to CFP with
respect to the Turbines 2 and 3 Project Area, including rights to all wells, the
plant site, and other facilities (and all improvements, equipment, fixtures and
other items appurtenant or accessorial to those wells and facilities), including
rights of access and egress to the Turbines 2 and 3 Project Area, subject to the
terms and conditions of the Navy Contract, and, from and after the date of this
Agreement and subject to and in accordance with the terms and conditions of the
Co-Tenancy Agreement, the rights and interests under the BLM Leases.
1.76 "Turbines 2 and 3 Project Authorizations" means all permits,
authorizations, rights of way and licenses necessary or appropriate to operate
and maintain the Turbines 2 and 3 Project and the geothermal resources subject
to the Turbines 2 and 3 Project Area Rights.
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1.77 "Turnkey Contract" means the Contract for the Construction of the
Coso Geothermal Project (Units 2 and 3) dated December 14, 1987, between MPE and
CFP II, assigned to the Partnership on July 14, 1988, as amended.
ARTICLE II
PARTNERSHIP FORMATION; IDENTIFICATION; AND TERM
2.1 Formation. This Partnership was organized under the Act on July 7,
---------
1987 and shall be continued under and governed by the Act and this Agreement.
2.2 Amendment. The parties hereto agree to amend and restate the
---------
Original Agreement. The Managing Partner shall do, make or cause to be made
all such filings, recording, publishing and other acts as may be necessary or
appropriate from time to time in connection therewith, and as required to
preserve the existence of the Partnership.
2.3 Name, Principal Executive Office, Registered Office and Registered
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Agent for Service of Process. The name of the Partnership shall be COSO FINANCE
- ----------------------------
PARTNERS, or such other name or names as may be selected by the Management
Committee from time to time. The principal executive office of the Partnership
and the office at which shall be kept the records, if any, required by the Act
shall be 1114 Avenue of the Americas, 41st Floor, New York, New York 10036,
unless changed by the Managing Partner with prior written notice given to the
Interest holders of such change. The Partnership may also maintain such other
offices at such other places as the Managing Partner may deem advisable. The
name of the Partnership's agent for service of process is Corporation Service
Company, 80 State Street, Albany, New York 12207 and Corporation Service
Company, which will do business in California as CSC-Lawyers Incorporating
Services, 2730 Gateway Oak Drive, Sacramento, California 95833.
2.4 Term. The Partnership shall continue so long as it has any
----
geothermal property interests in the Turbine 1 Project Area Rights or the
Turbines 2 and 3 Project Area Rights, or any obligations outstanding to any
lender having provided construction or term financing to the Partnership, or any
assignee thereof, unless the Partnership is terminated earlier in accordance
with Article XIII; provided, however, that subsequent to such time the
-------- -------
Partnership shall exist only to the extent and for the purposes necessary to
wind up the affairs of the Partnership.
ARTICLE III
PURPOSE AND NATURE OF BUSINESS; CERTAIN OBLIGATIONS
3.1 Purpose. The purpose of the Partnership and the business to be
-------
carried on by it, subject to the limitations contained elsewhere in this
Agreement, are:
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(a) To hold Turbine 1 and the Division I Assigned Rights in connection
with the exercise of the Buy-Out rights under the AMJV Project Agreement; to
acquire the rights to, and to construct and finance Turbines 2 and 3 and to
acquire the Division II Assigned Rights; and to operate Turbine 1, Turbines 2
and 3 and the Combined Project;
(b) To raise sufficient capital through borrowings from banks or other
lenders to finance, or refinance, the acquisition or construction of Turbine 1
and Turbines 2 and 3 and to acquire the AMJV Royalties (for Division II) and the
acquisition of the Division I Assigned Rights and the Division II Assigned
Rights, and to provide for the development and the exploitation of the lands
subject to the Turbine 1 Project Area Rights and the Turbines 2 and 3 Project
Area Rights;
(c) To borrow money for any legitimate Partnership purpose and in
connection therewith to issue notes, bonds, debentures and other evidences of
indebtedness and to secure the same and hypothecate any, all or substantially
all of the assets of the Partnership by mortgage, deed of trust, pledge or other
lien in furtherance of the foregoing purposes of the Partnership;
(d) To enter into and perform contracts and agreements and to carry on
any other activities necessary to, or desirable or incidental in connection
with, the accomplishment of the foregoing purposes of the Partnership; and
(e) To engage in any kind of activity and to enter into and perform
obligations of any kind necessary to, or in connection with, or incidental to,
the accomplishment of the purposes and business of the Partnership, so long as
such activities and obligations may lawfully be engaged in or performed by a
partnership under the Act. Such purpose and business of the Partnership shall
include the entering into by the Partnership of the transactions described in
that certain preliminary Offering Circular of Caithness Coso Funding Corp. dated
May 5, 1999 (as it may have been revised, the "Offering Circular"), including
without limitation the making by the Partnership of certain loans to and the
pledging by the Partnership of certain funds and assets of the Partnership for
payment of certain obligations of affiliated partnerships, all to the extent
provided for and described in the Offering Circular and the definitive documents
entered into in accordance therewith.
ARTICLE IV
CAPITAL
4.1 Partners' Capital Contributions to the Partnership.
--------------------------------------------------
(a) CECI and CG-80 have caused CLJV to assign to the Partnership for
the benefit of CLOC and ESCA, respectively, all of the Division I Assigned
Rights and rights to
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Turbine 1 held by CECI and CG-80, respectively, under the CLJV Agreement.
Concurrently with the execution of the 1987 Agreement, the Partnership assumed,
and took the Division I Assigned Rights and related contributed property subject
to, all liabilities secured by the contributed property at the time of
contribution or assumed by the Partnership with regard to such asset.
(b) The respective Capital Contributions of the Partners as of July
7, 1987 were as follows (the Cash Contributions to be made at a time to be
determined by the Management Committee):
CLOC ESCA
-------------- --------------
Property - at historical cost $ 9,236,891 $ 8,529,298
Deemed net value appreciation 834,012 3,580,680
-------------- --------------
Property - net deemed value $ 10,070,903 $ 12,109,978
Cash Accounts Receivable 0 2,695,000
At deemed net value 0 521,000
-------------- --------------
$ 10,070,903 $ 15,325,978
(c) The value of respective Capital Contributions at any particular
time is to be determined by reference to the books and records of the
Partnership.
4.2 Restrictions Relating to Capital; No Withdrawal. Except as otherwise
-----------------------------------------------
specifically provided in this Agreement or in the Act, no Partner shall have the
right to withdraw or reduce its Capital Contributions, to receive interest on
its Capital Contributions, to partition Partnership assets or to receive
property other than cash in return for its Capital Contributions.
4.3 Additional Capital Contributions; Additional Partners.
-----------------------------------------------------
(a) No Partner shall be required or entitled to make any additional
Capital Contributions to the Partnership except with the consent of, and in
accordance with the terms, conditions and procedures determined by, the
Management Committee. Such additional capital shall be contributed by the
Partners in proportion to their percentage distributions set forth in Sections
5.1(b) and 5.2(b), and shall be attributed by the Management Committee either to
the Turbine 1 Project or to the Turbines 2 and 3 Project, for purposes of
determining Division I Payout or Division II Payout, respectively.
(b) Except as provided in Article X, no additional Partners shall be
admitted to the Partnership except with the consent of, and in accordance with
the terms (including the relative rights, duties, and interest of such
additional Partners), conditions and procedures agreed to by all Partners;
provided, however, that any Partner may, without the consent of any other
Partner or the Management Committee, subdivide its Interest, through formation
of a partnership,
15
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corporation or other arrangement that would hold that Partner's Interest, so
long as that Partner remains the owner of the controlling portion of such
Interest.
ARTICLE V
CURRENT DISTRIBUTIONS
5.1 Division I Cash Flow From Operations. Subject to Article XIII (that
------------------------------------
is, other than in liquidation of a Partner's Interest in the Partnership as
provided in Section 13.4 (a)), Division I Cash Flow from Operations shall be
applied or distributed on each Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or funds are
on deposit in the Escrow Account sufficient to reduce the Preferred Return to
zero and the Distribution Condition will be satisfied for the Preferred Return
Year);
(i) until Division I Payout is achieved for all Partners, to
distribute 10% to New CLOC, and 90% to and among New CLOC and ESCA in the
proportion for each that the remaining sum necessary to be distributed in order
to achieve Division I Payout to each of them bears to the sum of the same for
both Partners; and
(ii) after Division I Payout is achieved by all Partners, to
distribute 46.4% to New CLOC and 53.6% to ESCA;
provided, however, that all amounts distributable to New CLOC pursuant to this
Section 5.1 (a) on the Distribution Date shall be deposited into the Escrow
Account until (a) the Joint Ventures have deposited therein an amount, in the
aggregate, equal to the Maximum Payment for the Preferred Return Year in which
the Distribution Date occurs, or (b) the Partnership has deposited therein an
amount, in the aggregate, equal to the Excess Revenues for the Partnership's
Project for the Preferred Return Year; and
(b) after the Preferred Return has been reduced to zero, in the manner
provided in Section 5.1(a)(i) and (ii), without regard to the proviso.
5.2 Division II Cash Flow from Operations. Subject to Article XIII (that
-------------------------------------
is, other than in liquidation of a Partner's Interest in the Partnership as
provided in Section 13.4 (a)) , Division II Cash Flow from Operations shall be
applied or distributed on each Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or will be
reduced to zero through the distribution of funds on deposit in the Escrow
Account):
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(i) until Division II Payout is achieved for all Partners, to
distribute 10% to New CLOC, and 90% to and among New CLOC and ESCA in the
proportion for each that the remaining sum necessary to be distributed in order
to achieve Division II Payout to each of them then bears to the sum of the same
for both Partners; and
(ii) after Division II Payout is achieved by all Partners, to
distribute 46.4% to New CLOC and 53.6% to ESCA;
provided, however, that all amounts distributable to New CLOC pursuant to this
Section 5.2 (a) on the Distribution Date shall be deposited into the Escrow
Account until (a) the Joint Ventures have deposited therein an amount, in the
aggregate, equal to the Maximum Payment for the Preferred Return Year in which
the Distribution Date relates, or (b) the Partnership has deposited therein an
amount, in the aggregate, equal to the Excess Revenues for the Partnership's
Project for the Preferred Return Year; and
(b) after the Preferred Return has been reduced to zero, in the manner
provided in Section 5.2(a)(i) and (ii), without regard to the proviso.
5.3 Division I Cash Flow From Capital Events. Subject to Article XIII
----------------------------------------
(that is, other than in liquidation of a Partner's Interest in the Partnership
as provided in Section 13.4(a)), Division I Cash Flow from Capital Events shall,
unless otherwise agreed by the Partners, be applied or distributed on each
Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or will be
reduced to zero through the application of funds on deposit in the Escrow
Account):
(i) to deposit 46.4% in the Escrow Account; and
(ii) to distribute 53.6% to ESCA;
(b) after the Preferred Return has been reduced to zero, 46.4% to New
CLOC and 53.6% to ESCA.
5.4 Division II Cash Flow From Capital Events. Subject to Article XIII
-----------------------------------------
(that is, other than in liquidation of a Partner's Interest in the Partnership
as provided in Section 13.4 (a)), Division II Cash Flow from Capital Events
shall, unless otherwise agreed by the Partners, be applied or distributed on
each Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or will be
reduced to zero through the application of funds on deposit in the Escrow
Account):
(i) to deposit 46.4% in the Escrow Account; and
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<PAGE>
(ii) to distribute 53.6% to ESCA;
(b) after the Preferred Return has been reduced to zero, 46.4% to New
CLOC and 53.6% to ESCA.
5.5 Characterization of Escrow Account Deposits and Payments. For tax and
--------------------------------------------------------
accounting purposes, (a) all amounts deposited in the Escrow Account pursuant to
Sections 5.1 (a), 5.2 (a), 5.3 (a) and 5.4 (a) shall be deemed to have been
distributed by the Partnership to New CLOC and to have been distributed as a
dividend by New CLOC to the Managing Partner, (b) the Managing Partner shall be
deemed to have directed the Partnership to make the deposits in the Escrow
Account on behalf of the Managing Partner, and (c) any payments from the Escrow
Account shall be deemed to have been made by the Managing Partner.
5.6 Intentionally Deleted.
18
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ARTICLE VI
ALLOCATIONS
6.1 Allocation of Net Profit and Net Loss.
-------------------------------------
(a) The Net Profit or Net Loss of the Partnership which is
attributable to the Turbine 1 Project (exclusive of other items of income, gain,
loss, deduction or credit that are otherwise allocated under this Article VI)
shall be allocated to and among the Partners in the same manner that Division I
Cash Flow from Operations is (or would have been had there been Division I Cash
Flow from Operations) distributed under the provisions of Section 5.1.
(b) The Net Profit or Net Loss of the Partnership which is
attributable to the Turbines 2 and 3 Project (exclusive of other items of
income, gain, loss, deduction or credit that are otherwise allocated under this
Article VI) shall be allocated to and among the Partners in the same proportion
that Division II Cash Flow from Operations is (or would have been had there been
Division II Cash Flow from Operations) distributed to them under the provisions
of Section 5.2.
6.2 Allocation of Net Gain and Net Loss from Capital Events.
-------------------------------------------------------
(a) The net Book gain (Book gain in excess of Book loss) of the
Partnership from Division I Capital Events, and the net Book loss (Book loss in
excess of Book gain) of the Partnership from Division I Capital Events, shall be
allocated to and among the Partners in the same manner that Division I Cash Flow
from Capital Events is (or would have been had there been Division I Cash Flow
from Capital Events) distributed under the provisions of Section 5.3.
(b) The net Book gain (Book gain in excess of Book loss) of the
Partnership from Division II Capital Events, and the net Book loss (Book loss in
excess of Book gain) of the Partnership from Division II Capital Events, shall
be allocated to and among the Partners in the same manner that Division II Cash
Flow from Capital Events is (or would have been had there been Division II Cash
Flow from Capital Events) distributed under the provisions of Section 5.4.
6.3 Allocation of Depreciation.
--------------------------
(a) Book depreciation of the Partnership from the Turbine 1 Project
shall be allocated to and among the Partners in the same manner that Division I
Cash Flow from Capital Events is (or would have been had there been Division I
Cash Flow from Capital Events) distributed under the provisions of Section 5.3.
(b) Book depreciation of the Partnership from the Turbines 2 and 3
Project shall be allocated to and among the Partnership in the same manner that
Division II Cash Flow
19
<PAGE>
from Capital Events is (or would have been had there been Division II Cash Flow
from Capital Events) distributed under the provisions of Section 5.4.
6.4 Allocation of Depletion. Book percentage depletion of the
-----------------------
Partnership and/or Book cost depletion of the Partnership shall be allocated to
and among the Partners as follows:
(a) Book percentage depletion for the Turbine 1 Project shall be
allocated to and among the Partners in the proportions in which the Partners are
allocated the related "gross income from the property" for the same applicable
accounting period. Unless otherwise required, Book percentage depletion and the
related "gross income from the property" for the Turbine 1 Project shall be
allocated to and among the Partners in the same manner that Division I Cash Flow
from Operations is (or would have been had there been Division I Cash Flow from
Operations) distributed under the provisions of Section 5.1.
(b) Book percentage depletion for the Turbines 2 and 3 Project shall
be allocated to and among the Partners in the proportions in which the Partners
are allocated the related "gross income from the property" for the same
applicable accounting period. Unless otherwise required, Book percentage
depletion and the related "gross income from the property" for the Turbines 2
and 3 Project shall be allocated to and among the Partners in the same manner
that Division II Cash Flow from Operations is (or would have been had there been
Division II Cash Flow from Operations) distributed under the provisions of
Section 5.2.
(c) Book cost depletion for the Turbine 1 Project shall be allocated
to and among the Partners in the proportions in which the Partners are allocated
the related "adjusted cost basis of the property" used to compute cost
depletion. Unless otherwise required, the Book cost depletion and the related
"adjusted cost basis of the property" for the Turbine 1 Project shall be
allocated to and among the Partners in the same manner that Division I Cash Flow
from Operations is (or would have been had there been Division I Cash Flow from
Operations) distributed under the provisions of Section 5.1.
(d) Book cost depletion for the Turbines 2 and 3 Project shall be
allocated to and among the Partners in the proportions in which the Partners are
allocated the related "adjusted cost basis of the property" used to compute cost
depletion. Unless otherwise required, the Book cost depletion and the related
"adjusted cost basis of the property" for the Turbines 2 and 3 Project shall be
allocated to and among the Partners in the same manner that Division II Cash
Flow from Operations is (or would have been had there been Division II Cash Flow
from Operations) distributed under the provisions of Section 5.2.
6.5 Allocation of Intangible Drilling and Development Costs. The Book
-------------------------------------------------------
deduction for intangible drilling and development costs of the Partnership shall
be allocated to and among the Partners as follows:
20
<PAGE>
(a) Intangible drilling and development costs for the Turbine 1
Project paid from additional Capital Contributions shall be allocated 100% to
the Partner from whom the additional Capital Contributions for the deductible
items were received, effective from and after July 1, 1988.
(b) Intangible drilling and development costs for the Turbines 2 and
3 Project paid from additional Capital Contributions to the Turbines 2 and 3
Project shall be allocated 100% to the Partner from whom the additional Capital
Contributions for the deductible items were received.
(c) Intangible drilling and development costs for the Turbine 1
Project paid from funds borrowed by the Partnership shall be allocated among the
Partners in the same manner that Division I Cash Flow from Capital Events is
distributed under the provisions of Section 5.3.
(d) Intangible drilling and development costs for the Turbines 2 and
3 Project paid from funds borrowed by the Partnership shall be allocated among
the Partners in the same manner that Division II Cash Flow from Capital Events
is distributed under the provisions of Section 5.4.
6.6 Allocations For Tax Purposes.
----------------------------
(a) All items of Partnership income, gain, loss, and deduction for
federal and state income tax purposes shall be allocated to and among the
Partners in the same manner that the corresponding Book items of the Partnership
are allocated in Sections 6.1 through 6.5, except as otherwise provided in Code
Section 704(c) and Regulation Section 1.704-1(b)(4)(i).
(b) For purposes of Regulation Section 1.46-3(f)(2)(ii) concerning
the allocation of the adjusted tax basis of property for purposes of tax credits
allowable under Code Section 38, the adjusted tax basis of the Turbine 1 Project
shall be allocated in the same manner that Division I Cash Flow from Capital
Events is distributed under the provisions of Section 5.3, and the adjusted tax
basis of the Turbines 2 and 3 Project shall be allocated in the same manner as
Division II Cash Flow from Capital Events is distributed under the provisions of
Section 5.4.
(c) In the event that the Partnership has taxable income that is
characterized as ordinary income by reason of the recapture provisions of the
Code, each Partner's allocation of taxable gain from the sale or exchange of
Partnership assets (to the extent possible) shall include a proportionate share
of the recapture income equal to the Partner's (and his predecessors in
interest's) share of prior cumulative depreciation, cost recovery or other
deductions for the applicable Project with respect to the assets which gave rise
to the recapture income (but not to exceed the amount of gain allocated to each
Partner).
21
<PAGE>
6.7 Intentionally Deleted.
6.8 Regulatory and Curative Allocations.
-----------------------------------
(a) Notwithstanding the foregoing provisions of this Article VI, the
Partnership shall allocate items of book income and gain in a manner that
constitutes a "minimum gain chargeback" as described in Section 1.704-2 of the
Treasury Regulations and the term "minimum gain" shall have the meaning assigned
to it therein. Determinations of each Partner's share of minimum gain shall be
made in accordance with Section 1.704-2 of the Treasury Regulations. In
addition, "partner nonrecourse deductions" shall be allocated to the Partners
bearing the risk of loss with respect to such deductions in accordance with
Section 1.704-2 of the Treasury Regulations.
(b) The Partners acknowledge and ratify the following modifications
to the provisions of this Article VI that were adopted pursuant to discussions
among the Partners and the Partnership accountants:
(i) For purposes of allocating income with respect to each
year, distributions are to be taken into account on the day in which they occur,
and the effective profit and loss percentages shall be determined as of each
date such distributions occur;
(ii) The following items are allocated in the ratios that apply
to Capital Events cash flow: depreciation, write-offs of plant and well capital
costs, fees paid to Southern California Edison related to transmission lines,
and alternative minimum tax adjustments and preferences associated with
property, plant and equipment; and
(iii) The initial capital contributions of the Partners are
determined by reference to the generally accepted accounting principle financial
statement figures for such capital contributions.
22
<PAGE>
(c) As stated in Treasury Regulations Section 1.704-1(b)(4)(i), when
any property of the Partnership is reflected in the Capital Accounts of the
Partners and on the books of the Partnership at a book value that differs from
the adjusted tax basis of such property, then certain book items with respect to
such property will differ from certain tax items with respect to that property.
Since the Capital Accounts of the Partners are required to be adjusted solely
for allocation of the book items, the Partners' shares of the corresponding tax
items are not independently reflected by adjustments to the Capital Accounts.
These tax items must be shared among the Partners in a manner that takes account
of the variation between the adjusted tax basis of the applicable property and
its book value pursuant to or in the same manner as variations between the
adjusted tax basis and fair market value of property contributed to the
Partnership are taken into account in determining the Partners' share of tax
items under Code Section 704(c). In making allocations of tax items of the
Partnership, the Partnership shall comply with the foregoing principles.
(d) The Partners intend that the allocation of items of income, gain,
loss, deduction and credit pursuant to this Agreement result in Capital Account
balances that achieve the economic sharing provisions reflected in Article V, as
amended. Notwithstanding any other provisions contained herein, allocations of
income, gain, loss and deductions shall be applied and amended by the Managing
Partner as necessary to produce such result, including special allocations of
gross income and gross deductions and amendment of prior tax returns. This
Section 6.8(d) shall control notwithstanding any reallocation of income, loss or
items thereof by the Internal Revenue Service or other taxing authority.
ARTICLE VII
RIGHTS, DUTIES, LIABILITIES AND
COMPENSATION OF THE MANAGING PARTNER
7.1 General.
-------
(a) Except as otherwise provided in this Agreement, the Managing
Partner shall be responsible for the conduct of the business of the Partnership
and for Resource Operations. The Managing Partner shall devote to the business
affairs of the Partnership such time and effort as the Managing Partner may from
time to time deem necessary. Pursuant to that certain Operations and
Maintenance Agreement, made and entered into by the Partnership, COC and FPLE,
dated as of the date hereof, and that certain Field Operations and Maintenance
Agreement, executed by COC and the Partnership, dated as of the date hereof
(FPLE and COC are individually and collectively referred to herein as
"Operator") as either may be amended, COC shall act as Operator, provided,
however, that certain field and maintenance operations shall be performed by
FPLE.
23
<PAGE>
(b) The Managing Partner and COC, in its capacity as the Operator,
shall be subject to all directives of the Management Committee with respect to
the performance of their respective duties hereunder, and shall be liable to the
Partnership for all damages, losses and expenses incurred by the Partnership as
a result of noncompliance with such directives.
7.2 General Rights and Powers of Managing Partner. Except as otherwise
---------------------------------------------
provided herein, including the provisions of Article VIII:
(a) The management and control of the day-to-day business and affairs
of the Partnership shall rest with the Managing Partner, which shall have such
rights and powers as are necessary, advisable or convenient to the discharge of
its duties under this Agreement and to the management of the business affairs of
the Partnership in furtherance of the purposes of the Partnership as set forth
in Article III.
(b) In furtherance of the purposes of the Partnership as set forth in
Article III of this Agreement, the Managing Partner is hereby granted the right,
power and authority to do on behalf of the Partnership all things which, in its
reasonable judgment, are necessary, proper or desirable to carry out its duties
and responsibilities hereunder, including, but not limited to, the following:
from time to time to incur all reasonable expenditures pursuant to the Budget;
to employ and dismiss from employment any and all employees, agents,
contractors, brokers, attorneys and accountants except for the partnership's
auditor; to create, by grant or otherwise, easements and servitudes; to borrow
money up to an aggregate principal amount of $100,000 at any time outstanding;
and to execute, acknowledge and deliver any and all contracts, agreements or
other instruments to effectuate any and all of the foregoing. Subject to the
direction of the Management Committee, the Managing Partner shall be responsible
for the following:
(i) maintain and protect the assets of the Partnership and the
interests of the Partners;
(ii) obtain such consultants, technicians, agents, and
contractors as it deems may be required for Project operations;
(iii) make all reports and disburse funds in accordance with the
Budget for all payments required under this Agreement with respect to Project
operations and under all agreements, permits, authorizations, and other rights
relating thereto;
(iv) submit the Budget, cost projections and any other budgets
for Project operations to the Management Committee;
(v) keep full and accurate records and accounts of the
transactions entered into by it on behalf of the Partnership;
24
<PAGE>
(vi) do all such acts and things and conduct all such steps as
may reasonably be necessary or advisable in its judgment for the efficient and
economical conduct of Project operations; and
(vii) secure adequate and reasonable insurance (to the extent
possible and with the Partners and Partnership as named insureds) covering those
insurable risks with respect to the Partnership and Partnership operations that
can be insured at reasonable costs, including risk of personal injuries to or
deaths of employees or others, risks of fire, and all other risks ordinarily
insured against in similar operations, and adjust losses and claims pertaining
to or arising out of such insurance. To the extent possible, and to the extent
not inconsistent with requirements of lenders to the Partnership, or as
determined by the Management Committee, the Partnership shall maintain the
following insurance:
(1) Worker's Compensation Insurance covering all employees
of the Partnership employed in, on or about the business premises, Turbine 1 and
Turbines 2 and 3 to provide statutory benefits as required by the laws of
California;
(2) Policies of insurance on standard insurance Service
Office forms with commercial insurers acceptable to the Management Committee
providing comprehensive commercial general liability coverage and comprehensive
commercial automotive liability coverage. Said policies shall cover generally
all liabilities which might arise under, or in the performance or nonperformance
of, this Agreement, including but not limited to products liability/completed
operations coverage, for the Partnership, the Partners and their respective
parents, subsidiaries or affiliated entities and each of their officers,
directors, employees, or agents (hereinafter in this subsection (2) collectively
called the "Insureds"). The policy shall also contain a blanket broad form
contractual endorsement and a severability of interest clause. The Insureds
shall be designated as a named insured, and the policies shall be endorsed to be
primary to any insurance which may be maintained by or on behalf of the Partners
and their parents, affiliates and their respective officers, directors or
employees. The policies shall have limits of liability agreeable to the
Management Committee.
In the event that the policies are on a "claims made"
basis, the retroactive date of the policies shall be July 7, 1987 for the
Turbine 1 Project and July 13, 1988 for the Turbines 2 and 3 Project.
Furthermore, if the policy is on a "claims made" basis, the Managing Partner's
responsibility to maintain such coverage shall survive the termination of this
Agreement until the expiration of the maximum statutory period of limitations in
the State of Florida and any jurisdiction where the Partnership has property for
actions based in contract or in tort; if coverage is on an "occurrence" basis,
such insurance shall be maintained by the Managing Partner during the entire
term of this Agreement. The policy shall not be canceled or materially altered
without at least 30 days' written notice to each Partner and the Partnership.
(3) A program of property insurance with limits and
coverages as agreed by the Management Committee, insuring risks of physical loss
or damage, including
25
<PAGE>
without limitation, boiler and machinery exposures, loss or damage to any
equipment, or to Partnership property. The Managing Partner shall with the
assistance of the Management Committee undertake or make provisions to
investigate and settle any claim against third parties or insurers as a result
of property damage to Partnership property. With respect to any claim against
insurance procured pursuant to this Section the Managing Partner shall, at its
discretion with the cooperation and assistance of the Partners, pursue any right
of subrogation on behalf of the Partners or the applicable insurer.
7.3 Expenses. The Partnership shall reimburse the following expenses of
--------
the Partnership incurred by either of the Partners, limited to the amounts set
forth in the applicable Budget approved in accordance with Section 7.4:
(a) All organization fees and expenses of the Partnership;
(b) The actual costs of goods and materials used by or for the
Partnership by the Managing Partner, any subcontractors or the Partnership;
(c) All employee time and costs and related overhead of the Managing
Partner attributable to the business of the Partnership;
(d) All operational expenses of the Partnership that may be paid by
the Managing Partner pursuant to the terms hereof, including, without
limitation, the following: obligations related to Division I Assigned Rights and
Division II Assigned Rights; all costs of borrowed money paid to lenders; taxes
and assessments on Partnership assets and other taxes applicable to the
Partnership; legal, accounting, appraisal, audit and brokerage fees; fees and
expenses paid to independent consultants or insurance brokers; and
(e) All accounting, documentation, professional and reporting expenses
of the Partnership paid or to be paid to any person, including, without
limitation, the following: preparation and documentation of Partnership
accountings and audits; preparation and documentation of Partnership state and
federal tax returns; expenses of revising, amending, converting, modifying, or
terminating this Agreement or the Partnership; costs incurred in connection with
any litigation in which the Partnership is involved as well as any examination,
investigation or other proceedings conducted by any regulatory agency with
respect to the Partnership, including legal and accounting fees incurred in
connection therewith; costs of any computer equipment or services used for or by
the Partnership; the costs of preparation and dissemination of informational
material and documentation relating to a potential sale of Partnership Interests
to third parties or relating to a potential acquisition, sale, financing or
refinancing of Partnership assets; and all other expenses due to any Person in
connection with the maintenance and operation of the Partnership.
26
<PAGE>
7.4 Budgets, Mechanism for Reimbursements.
-------------------------------------
(a) The Managing Partner shall prepare the Budget for the Partnership,
which shall include a capital expenditure budget and an annual budget for
Partnership operations. The Budget shall be presented to the Management
Committee for approval no later than ninety (90) days prior to the beginning of
the calendar year to which such Budget relates. Once the Budget has been
approved by the Management Committee, the Managing Partner may pay all
Partnership expenses, reimburse itself for expenditures permitted by Section
7.3, and otherwise apply all available Partnership funds in accordance with the
approved Budget. If all or any portion of a proposed Budget is not approved by
the Management Committee, the Managing Partner shall have the right to retain
Sandwell Corporation or, upon prior written notice to the other Partners, other
independent engineering firm not objected to in writing by the other Partners
within ten (10) days after receipt of the Managing Partner's designation of such
other firm to review the proposed budget. If such independent engineering firm
certifies that the proposed budget is reasonably designed to permit the Managing
Partner to operate and maintain a project of the type of the Combined Project
and to maximize revenues and net income to the Partnership, such proposed budget
shall be deemed to be the Budget. If the independent engineering firm fails to
provide such certification prior to the commencement of the subject budget year,
the Budget shall be the same as in the immediately preceding year, adjusted for
inflation in accordance with the national Consumer Price Index. The Managing
Partner shall be liable to the Partnership for all payments found to be in
noncompliance with an approved Budget (including, without limitation, any Budget
that is deemed to be approved pursuant to the two immediately preceding
sentences) except for any such payment as may be ratified by the Management
Committee or otherwise expressly permitted under this Agreement without
Management Committee approval.
(b) Subject to the approval of the Management Committee, the
reasonable costs incurred by the Partners in connection with matters to be
considered by the Management Committee as well as any other activities of the
Partners assigned to such Partners by the Management Committee shall be
reimbursed by the Partnership in accordance with the amounts set forth in the
applicable Budget approved in accordance with Section 7.4(a).
7.5 Third Party Reliance. Any person dealing with the Partnership as to
--------------------
any matter with respect to which the Managing Partner is granted authority
hereunder may rely solely on written advice from the Managing Partner as to any
matter relating to this Agreement, as to compliance herewith and as to the
authority of the Managing Partner to act on behalf of the Partnership, and as
between the Partnership or the Managing Partner, on the one hand, and such other
person, on the other hand, the facts stated in such written advice from the
Managing Partner will be conclusive and binding on the Partnership and the
Managing Partner.
27
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ARTICLE VIII
MANAGEMENT OF PARTNERSHIP
8.1 Management Committee. Subject to requirements of the Act or other
--------------------
applicable law the business operations of the Partnership shall be overseen by a
Management Committee, consisting of two delegates appointed by New CLOC and two
delegates appointed by ESCA. New CLOC and ESCA shall each be fully empowered to
substitute for its own delegates and to appoint alternates. The decision of the
Management Committee shall be required for all actions set forth in Section 8.4.
8.2 Meetings. The Partnership shall hold Meetings to transact all
--------
Partnership business for which a meeting or a vote of the Partners is required
by the Act. Each Partner shall send two delegates to each Meeting. Each
Partner may substitute or change delegates at will, and shall notify the other
Partner of the names of such delegates prior to each Meeting.
8.3 Procedures. Management Committee Meetings and Partnership Meetings
----------
shall occur and be conducted pursuant to the following procedures:
(a) The Partnership and the Management Committee shall hold a Meeting
on the second Tuesday of January, April, July and October of each year and on
such other dates as shall be called by a Partner on written notice of not less
than fifteen (15) business days given by the calling party to all Partners. All
meetings shall, unless otherwise waived by at least three delegates, be preceded
by no less than fifteen (15) business days by an agenda and supporting
documentation provided by the calling Partner (or by the Managing Partner for
regular meetings), describing, in reasonable detail, the issues to be presented
to the Management Committee for voting. Meetings shall be held at the Managing
Partner's office and begin at 10:00 A.M. unless another time or place is agreed
to.
(b) A quorum of three (3) delegates (including alternates to delegates
not present) must be present to convene a Meeting and/or vote on Partnership or
Management Committee matters.
(c) All votes on Partnership or Management Committee action shall
require a favorable vote of at least a majority of the delegates comprising the
quorum present at the Meeting; provided, however, that said favorable vote must
be composed of at least one favorable vote by a delegate representing New CLOC
and one favorable vote by a delegate representing ESCA.
(d) Action by the Partnership and the Management Committee may be
taken at any time without a meeting upon the written consent of at least three
(3) delegates after proper advance written notice is given to all delegates
setting forth in detail the action which is proposed to be taken by the
Partnership or Management Committee.
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(e) In any event, delegates may vote at a meeting or by a letter,
telex, telegram, or other written communication addressed to the other delegates
or by telephone confirmed subsequently in writing.
(f) The Partnership and the Management Committee may also take action
by vote of at least three (3) delegates given by the telephone and subsequently
confirmed in writing to all delegates. The notice provision in Section 8.3(a)
shall apply also to such vote by telephone, provided, however, that vote may be
taken without notice, if in the reasonable opinion of the three delegates so
voting, there exists an emergency situation precluding such advance notice, and
that all reasonable efforts have been made to notify all Partners of the
emergency and the vote.
(g) Minutes shall be prepared for all Meetings, and shall be approved
by the Partners or the Management Committee, as applicable, prior to being
entered into the permanent minute book maintained by the Managing Partner for
the Partnership.
8.4 Limitations on Authority of Managing Partner. The Managing Partner
--------------------------------------------
shall have no authority to do any act prohibited by law, nor shall the Managing
Partner, without the consent of the Management Committee, have any authority to:
(a) Permit any creditor who makes a loan to the Partnership to take,
as a condition of making such loan, any direct or indirect interest in the
profits, capital, assets or property of the Partnership other than as a secured
creditor;
(b) Sell or lease the Partnership's rights in commercial geothermal
wells, power plants and other substantial assets owned by the Partnership;
(c) make or amend contracts for the sale of electricity;
(d) Terminate, liquidate and wind up the Partnership, except upon the
occurrence of an event which, under the Act, dissolves or terminates the
Partnership;
(e) Approve and establish procedures and ongoing review of all budgets
and the budget process, including each Budget;
(f) Change the Partnership's auditor;
(g) Create, incur, or assume any indebtedness for borrowed money other
than in the ordinary course of Partnership business or create, incur, or assume
any indebtedness in aggregate principal amount at any time outstanding greater
than $100,000;
(h) Obtain refinancing or replacements of any mortgages or other
security instruments related in any way to any Partnership property, or repay in
whole or in part,
29
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refinance, recast, modify, consolidate or extend any of the terms of any
indebtedness owed by the Partnership or affecting all or any portion of any
Partnership property;
(i) Modify, amend or waive any provision of any material agreement to
which the Partnership is a party;
(j) Acquire, amend or terminate any geothermal leases;
(k) Select or discharge the person employed as the Project Manager of
the Combined Project;
(l) Engage and discharge outside consultants, construction
contractors, engineers or similar entities or professionals, including contracts
with third party Project operators in connection with work to be performed by or
for the benefit of the Partnership in instances where the estimated or incurred
cost of said work exceeds $100,000; excluding, however, contracts for drilling
of wells and all related supplies and equipment, provided the estimated costs of
such contracts do not exceed the amounts budgeted for such items in an approved
Budget; further provided that any contract between the Partnership and the
Operator, the Managing Partner or any of their affiliates must have the approval
of the Management Committee;
(m) All other functions for which Partnership approval is required by
applicable law or for which Management Committee approval is required by this
Agreement;
(n) (i) do any act in contravention of this Agreement or not in
furtherance of the purposes of the Partnership set forth in Article III; (ii) do
any act which would make it impossible to carry on the ordinary business of the
Partnership; (iii) confess a judgment against the Partnership; (iv) possess
Partnership property or assign rights in specific Partnership property, for
other than a Partnership purpose; (v) change or reorganize the Partnership into
any other legal form; or (vi) admit a person as a Partner, except as provided in
this Agreement.
(o) Issue any Additional Notes pursuant to Section 8.06 of the
Indenture.
Notwithstanding anything to the contrary set forth herein, the
Managing Partner shall have the authority, without the approval of the
Management Committee, to administer the definitive documents entered into by the
Partnership in accordance with and as generally described in the Offering
Circular, including any amendments, waivers, extensions, indulgences, minor
adjustments, or other loan administration matters with respect to such documents
(other than amendments materially affecting the Partnership or any Partner).
8.5 Project Manager. The Project Manager shall be the on-site senior
---------------
manager responsible for the day-to-day management of the Combined Project. The
Project Manager shall report regularly to the Management Committee. He shall be
employed by the Managing Partner
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on terms and conditions approved by the Management Committee, and subject to
periodic review and change. The Project Manager may be terminated with or
without cause by the vote of two delegates to the Management Committee.
ARTICLE IX
REPRESENTATIONS AND COVENANTS OF PARTNERS
9.1 Representation of Partners. Each Partner represents to each other
--------------------------
Partner that it is an entity duly organized and validly existing under the laws
of its jurisdiction of organization, and qualified to do business in the State
of California, that all action required by such Partner to authorize that
Partner to enter into this Agreement has been taken, and that this Agreement is
a binding agreement of that Partner, enforceable in accordance with its terms.
9.2 Covenants of Partners. Each Partner covenants that it will not
---------------------
engage in any business or in any other activities other than performing its
obligations under this Agreement to the extent such business or other activities
are otherwise not permitted by agreements between the Partnership and financing
entities.
ARTICLE X
ASSIGNMENTS OR TRANSFERS OF INTERESTS
10.1 Assignments. Subject to compliance with applicable federal and state
-----------
securities laws, and subject to Section 4.3(b), a Partner may transfer all or a
portion of his Interest in the Partnership, by an executed and acknowledged
written instrument, only with the consent of the Management Committee. Subject
to compliance with applicable federal and state securities laws, assignments
will be recognized by the Partnership as effective only on the first day of the
calendar month following the receipt by the Partnership of written notice of the
assignment. The Partnership may charge the assigning or transferring Partner
and any Partner requesting a change of name, type of ownership, etc., a fee not
to exceed the expenses, including actual legal expenses, incurred in effecting
the assignment or transfer of his interest in the Partnership or other change in
the records of the Partnership.
10.2 Substituted Partners. No assignee of the whole or any portion of a
--------------------
Partner's Interest in the Partnership shall have the right to become a
substituted Partner in the place of his assignor unless all of the following
conditions are satisfied:
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(a) The fully executed and acknowledged written instrument of
assignment that has been filed with the Partnership sets forth the intention of
the assignor that the assignee become a substituted Partner in his place;
(b) The assignor and assignee execute and acknowledge such other
instruments as the Management Committee may deem necessary or desirable to
effect such admission, including the written acceptance and adoption by the
assignee of the provisions of this Agreement, the form and content of which
shall be provided by the Management Committee;
(c) Any transfer fee and legal expenses, if any, referred to in
paragraph (a) above required to be paid shall have been paid;
(d) The transfer shall not be in violation of any applicable federal
or state securities laws, including the Securities Act of 1933, as amended, it
being understood and agreed that the Management Committee may require as a
condition of such transfer that the Partnership be furnished with an appropriate
opinion of counsel to the foregoing effect, which counsel and opinion shall be
satisfactory to the Management Committee; and
(e) The Management Committee has consented to the assignment (which
consent may be granted or withheld at the sole discretion of the Management
Committee).
10.3 Management Committee Option. The Management Committee may elect to
---------------------------
treat an assignee who has not become a substituted Partner as a substituted
Partner in the place of his assignor should it deem, in its sole discretion,
that such treatment is in the best interest of the Partnership for any of its
purposes or for any of the purposes of this Agreement.
10.4 Amendment of Agreement. The Managing Partner will be required to
----------------------
prepare an amendment to this Agreement for signature by the Partners to reflect
the substitution of Partners. Until this Agreement is so amended, an assignee
shall not become a substituted Partner.
10.5 Insolvency. Upon the bankruptcy, insolvency, dissolution, or other
----------
cessation to exist as a legal entity of a Partner not an individual, the
authorized representative of such entity shall have all the rights of a Partner
for the purpose of effecting the orderly winding up and disposition of the
business of such entity and such power as such entity possessed to constitute a
successor as an assignee of its interest in the Partnership and to join with
such assignee in making application to substitute such assignee as a Partner.
10.6 Special Restrictions Relating to Non-U.S. Persons. Each transferee of
-------------------------------------------------
an Interest shall certify whether or not such transferee is a U.S. person. Such
certifications shall be made on the transfer application required to be
submitted pursuant to Section 10.2. Each Partner shall notify the Managing
Partner if it becomes a non-U.S. person within 30 days of such change. Prior to
a disposition of a "United States Real Property Interest," as defined in Code
Section 897,
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or a distribution pursuant to a disposition of a "United States Real Property
Interest," each Partner shall, if requested to do so by the Managing Partner,
certify as a to its U.S. person status.
10.7 Amendments in Respect of Transfers; Admission of Partners; Etc. The
---------------------------------------------------------------
Managing Partner, at the discretion of the Management Committee, shall amend any
Partnership document listing the Partners from time to time to reflect and the
admission, substitution or withdrawal of Partners, provided that such documents
shall be amended no less often than quarterly. No such admission, substitution
or withdrawal shall be effective until all appropriate Partnership documents are
so amended.
ARTICLE XI
LOANS TO THE PARTNERSHIP
11.1 Authority to Borrow. Subject to the approval of the Management
-------------------
Committee and to the limitations elsewhere provided in this Agreement, the
Partnership may from time to time borrow such amounts from such persons
(including the Managing Partner or any other Partner and its affiliates) on such
security and payable on such terms as the Managing Partner may determine.
11.2 Loans from Partners. If a Partner shall, with the prior consent of
-------------------
the Management Committee, make any loan or loans to the Partnership or advance
money on its behalf, the amount of any such loan or advance shall not increase
the applicable Capital Account of the lending Partner or entitle such lending
Partner to any increase in his share of the distributions of the Partnership or
result in his having any greater share of Partnership allocations of Net Profit
and Net Loss. The amount of any such loan or advance shall be a debt due from
the Partnership to such lending Partner, repayable upon such terms and
conditions and bearing interest at such rates as shall be mutually agreed upon
by the lending Partner and the Management Committee, and such loan or advance
may, subject to approval of the Management Committee, be secured by a mortgage,
deed of trust, pledge, security interest or other lien in or on any, all or
substantially all of the properties and other assets of the Partnership.
ARTICLE XII
BOOKS, RECORDS AND REPORTS
12.1 Books. The Partnership, at its expense, shall maintain books and
-----
records for the Partnership at the Managing Partner's designated office, and all
Partners shall have the right to inspect and examine such books and records, and
to copy them (at their own expense), but only for a valid business purpose
related to the conduct of the Partnership's business, upon reasonable notice and
during regular business hours.
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12.2 Reports. The Partnership shall cause to be prepared and delivered
-------
to Partners, at its expense, the following reports (all unaudited reports to be
certified by the Chief Financial Officer of the Managing Partner):
(a) Within 60 days after the end of the first three quarterly periods
of the Partnership's fiscal year, a quarterly report containing the following:
(i) A balance sheet, which may be unaudited;
(ii) A statement of income for the three-month period then
ended, and for the year to date at such quarter end, which may be unaudited;
(iii) A statement of changes in financial position for the
three-month period then ended, and for the year to date at such quarter end,
which may be unaudited;
(iv) Other pertinent information regarding the Partnership and
its activities during the three-month period covered by the report; and
(v) A statement setting forth in reasonable detail the
services rendered by the Managing Partner to the Partnership and the amounts
charged for those services, and the Managing Partner shall provide such further
detailed information as any Partner may reasonably request.
(b) Within 75 days after the end of each fiscal year of the
Partnership, all information concerning the Partnership reasonably necessary for
the preparation of the Partners' federal and state income tax returns.
(c) Within 45 days after the end of each fiscal year of the
Partnership, an annual report containing (i) a balance sheet as of the end of
its fiscal year and statements of income, Partners' equity and changes in
financial position, for the year then ended, all of which shall be prepared in
accordance with generally accepted accounting principles consistently applied
and accompanied by an auditor's report containing to the extent available an
unqualified opinion of an independent certified public accountant; (ii) a report
of the activities of the Partnership during the period covered by the report.
(d) Within 27 days after the end of each fiscal year of the
Partnership, unaudited versions of the financial statements described in
12.2(c).
(e) Copies of any documents delivered to any institution providing
financing to the Partnership pursuant to the requirements of any Partnership
loan documents.
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12.3 Accounting Decisions. Except as otherwise provided in this
--------------------
Agreement all decisions as to accounting matters shall be made by the Managing
Partner as directed by the Management Committee.
12.4 Income Tax Elections and Proceedings.
------------------------------------
(a) The Management Committee shall direct the Managing Partner to
make such elections under the tax laws of the United States, the several States
and other relevant jurisdictions as to the treatment of the Partnership's items
of income, gain, loss, deduction and credit and as to all other relevant matters
as it reasonably believes necessary, appropriate or desirable.
(b) In the event the Partnership is subject to administrative or
judicial proceedings for the assessment and collection of deficiencies for
federal, state or local taxes or for the refund of overpayments of federal,
state or local taxes arising out of a Partner's distributive share of the tax
items of the Partnership, the Managing Partner shall act as, and shall have all
the power and duties assigned to, the "tax matters partner" under Code Sections
6221-6232 and the Regulations thereunder. The Partners agree to perform all
acts necessary under Code Section 6231 and the Regulations thereunder to
designate the Managing Partner as the "tax matters partner."
(c) No Partner shall, on such Partner's federal or state income tax
return, treat any "partnership item" (as defined in Code Section 6231(a)(3) and
the Regulations thereunder) in a manner which is inconsistent with the treatment
of such "partnership item" on the Partnership's return without first submitting
its proposed treatment to the other Partner for its advance review.
(d) Bank Accounts. The Managing Partner may designate from time to
-------------
time those persons authorized to execute checks and other items on the
Partnership bank accounts. The funds of the Partnership shall not be commingled
with the funds of any other person. The Managing Partner shall have fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing Partner's possession or control, and
it shall not employ, or take actions to permit another to employ, such funds or
assets in any manner except as provided in this Agreement.
(e) The Managing Partner shall make an election, solely for purposes
of Code Section 614(b)(3), to make a pooling agreement with respect to the
Turbine 1 Project Area and the Turbines 2 and 3 Project Area, unless otherwise
directed by the Management Committee.
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ARTICLE XIII
DISSOLUTION AND TERMINATION OF THE PARTNERSHIP AND THE
LIQUIDATION OF A PARTNER'S INTEREST IN THE PARTNERSHIP
13.1 Dissolution. Only the happening of any one of the following events
-----------
shall dissolve the Partnership:
(a) The expiration of the Term of the Partnership;
(b) The expiration of 60 days after the Partnership's election to
dissolve the Partnership (provided that no Partner shall, without such approvals
as may be required from lenders providing financing to the Partnership in
accordance with the relevant loan or financing agreements, seek the dissolution
of the Partnership);
(c) The entry of a decree of judicial dissolution of the Partnership
pursuant to the Act; or
(d) The occurrence of any event that would cause the dissolution of
the Partnership under the Act or that would make it unlawful for the business of
the Partnership to be continued.
13.2 Distributions in Liquidation of the Partnership and in Liquidation
------------------------------------------------------------------
of a Partner's Interest in the Partnership:
- ------------------------------------------
(a) In the event of a distribution in connection with the
liquidation of the Partnership, the occurrence of which is described in Section
13.4(b), the Partnership shall apply and distribute the proceeds from the
liquidation of the assets of the Partnership and collection of the receivables
of the Partnership, together with assets distributed in kind, to the extent
sufficient therefor, in the following order of priority:
(i) First, to the payment and discharge of all liabilities,
obligations and debts of the Partnership and the expenses of liquidation, paid
in the order then required by California law;
(ii) Second, to the creation and setting up of any reserves
which the Management Committee may deem necessary, appropriate or desirable for
any future, contingent or unforeseen liabilities, obligations or debts of the
Partnership which are not yet payable or have not yet been paid. The Partnership
may pay, but is not obligated to pay, such reserves to an independent escrow
holder designated by the Management Committee, to be held by it for the purpose
of disbursing such reserves in payment of any of the aforementioned liabilities,
obligations and debts and, at the expiration of such period as the Management
Committee shall
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<PAGE>
deem necessary, advisable or desirable, to distribute the balance thereafter
remaining in the manner hereinafter provided;
(iii) Third, to the payment and discharge of all of the
liabilities, obligations and debts of the Partnership owing to Partners, but if
the amount available for payment is insufficient, then pro rata in accordance
with the amount of those liabilities, obligations and debts; and
(iv) Finally, to the Partners with positive Capital Accounts,
in accordance with their respective Capital Accounts after taking into account
all Capital Account adjustments for the Partnership taxable year during which
such liquidation occurs (other than those made pursuant to this Section 13.2, or
Section 13.3).
(b) Except as otherwise provided in Regulation Section 1.704-
1(b)(2)(ii)(b), a distribution to a Partner in liquidation of such Partner's
interest in the Partnership (as described in Section 13.4(c)), but other than in
liquidation of the Partnership (the occurrence of which is described in Section
13.4(b)), shall be in an amount equal to each Partner's Capital Account after
taking into account all Capital Account adjustments for the Partnership taxable
year during which such liquidation occurs (other than those made pursuant to
this Section 13.2 or Section 13.3).
(c) For purposes of this Section 13.2, the Partnership taxable year
shall be determined without regard to Code Section 706(c)(2)(A).
13.3 Deficit Capital Account.
-----------------------
(a) If any Partner has a deficit balance in its Capital Account
following the liquidation of such Partner's Interest in the Partnership (the
occurrence of which is described in Section 13.4(a)), as determined after taking
into account all Capital Account adjustments for the Partnership taxable year
during which such liquidation occurs (other than those made pursuant to this
Section 13.3), such Partner must pay to the Partnership the amount of such
deficit balance.
(b) This amount shall, in the event of a distribution in connection
with the liquidation of the Partnership (the occurrence of which is described in
Section 13.4(b)), be paid to creditors of the Partnership or distributed to the
other Partners with positive Capital Accounts in accordance with their Capital
Account balances as provided in Section 13.2(a). This payment must be made no
later than the end of the taxable year during such liquidation of the Partner's
Interest in the Partnership occurs (or, if later, within 90 days after the date
of such liquidation).
(c) The Partners intend that the provisions of this Section 13.3,
will constitute an unconditional obligation of a Partner to restore the amount
of the deficit in its Capital Account, as described in Regulation Section 1.704-
1(b)(2)(ii)(b)(3). The Regulations control in the case of any conflict between
the Regulations and this Section 13.3.
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(d) For purposes of this Section 13.3, the Partnership taxable year
shall be determined without regard to Code Section 706(c)(2)(A).
13.4 Liquidation of the Partnership and Liquidation of a Partner &
-------------------------------------------------------------
Interest in the Partnership.
- ---------------------------
(a) For purposes of Sections 1.10, 5.1, 5.2, 5.3, 5.4 and 13.3(a),
a liquidation of a Partner's Interest in the Partnership occurs upon the earlier
of (i) the date upon which there is a liquidation of the Partnership or (ii) the
date upon which there is a liquidation of the Partner's Interest in the
Partnership.
(b) For purposes of Section 13.4(a) and Sections 13.2(a) and
13.3(b), the liquidation of the Partnership occurs upon the earlier of (i) the
date upon which the Partnership is terminated under Code Section 708(b)(1), or
(ii) the date upon which the Partnership ceases to be a going concern (even
though it may continue in existence for the purpose of winding up its affairs,
paying its debts, and distributing any remaining balance to its Partners).
(c) For purposes of Sections 13.4(a) and 13.2(b), the liquidation
of a Partner's Interest in the Partnership means the termination of a Partner's
entire Interest in the Partnership by means of a distribution, or a series of
distributions, to the Partner by the Partnership. A series of distributions will
come within the meaning of this term whether they are made in one year or in
more than one year. Where a Partner's Interest is to be liquidated by a series
of distributions, the Interest will not be considered as liquidated until the
final distribution has been made.
(d) The liquidation of a Partner's Interest in the Partnership, the
occurrence of which is described in Section 13.4(a), will not be delayed after
the Partnership's primary business activities have been terminated for a
principal purpose of deferring any distribution pursuant to Section 13.2(a)(iv),
or deferring any Partner's obligation under Section 13.3.
13.5 Time of Liquidation. Subject to Section 13.4(d) a reasonable time
-------------------
shall be allowed for the orderly liquidation of the assets of the Partnership
and the discharge of liabilities to creditors so as to enable the Partnership to
minimize to the extent it deems practicable, advisable or desirable the normal
losses attendant upon a liquidation.
13.6 Liquidation Statement. Each of the Partners shall be furnished
---------------------
with a statement prepared by the Partnership, which shall set forth the assets
and liabilities of the Partnership as of the date of complete liquidation. Upon
the Partnership complying with the foregoing distribution plan, the Partners
shall cease to be such and the Managing Partner may execute, acknowledge and
cause to be filed and recorded a certificate of cancellation of the Partnership
or other appropriate documents evidencing its dissolution and winding up.
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ARTICLE XIV
LIMITATION OF LIABILITY OF MANAGING PARTNER AND
INDEMNIFICATION OF THE MANAGING PARTNER AND OTHERS
14.1 Limitation on Liability of Managing Partner. None of the Managing
-------------------------------------------
Partner or its officers, directors, members, shareholders, employees or agents
will be liable to the Partnership or the Partners for any expense, loss or
liability suffered by the Partnership or the Partners in connection with the
Partnership or its activities; provided that, in the event such expense, loss or
liability arose out of any action or inaction of a Managing Partner or its
affiliates or such other persons, as the case may be, the foregoing shall only
apply if (i) such course of conduct did not constitute gross negligence, acts of
bad faith or willful misconduct, and (ii) the Managing Partner, its affiliates
or such other persons, as the case may be, had previously determined in good
faith that such course of conduct was in the best interests of the Partnership.
14.2 Indemnification of the Managing Partner.
---------------------------------------
(a) The Partnership shall indemnify and hold harmless the Managing
Partner, and its officers, directors, members, shareholders, employees and
agents (individually, an "Indemnitee") from and against any and all losses,
claims, demands, costs, damages, liabilities, joint and several, expenses of any
nature (including attorneys' fees and disbursements), judgments, fines,
settlements and other amounts arising from any and all claims, demands, actions,
suits or proceedings, civil, criminal, administrative or investigative,
(including without limitation any action brought by the Project Manager for
unlawful termination of employment) in which the Indemnitee may be involved, or
threatened to be involved, as a party or otherwise arising out of or incidental
to the business of the Partnership, including without limitation liabilities
under the federal and state securities laws, regardless of whether the
Indemnitee continues to be the Managing Partner, or an officer, director,
member, shareholder, employee or agent of the Managing Partner at the time any
such liability or expense is paid, if the Indemnitee's conduct did not
constitute actual fraud, willful misconduct or gross negligence and if the
Indemnitee acted in a manner it reasonably believed to be in the best interests
of the Partnership. The termination of any action, suit or proceeding by
settlement or upon a plea of nolo contendre, or its equivalent, shall not, in
and of itself, create a presumption or otherwise constitute evidence that the
Indemnitee acted in a manner contrary to that specified above.
(b) Reasonable expenses incurred by an Indemnitee in defending any
claim, demand, action, suit or proceeding subject to this Section 14.2 shall,
from time to time, be advanced by the Partnership prior to the final disposition
of such claim, demand, action, suit or proceeding upon receipt by the
Partnership of an undertaking by or on behalf of the Indemnitee to repay such
amount if it shall be determined that such person is not entitled to be
indemnified as authorized in this Section 14.2.
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(c) The indemnification provided by this Section 14.2 shall be in
addition to any other rights to which those indemnified may be entitled under
any agreement, vote of the Partners, as a matter of law or equity or otherwise,
both as to action in the Indemnitee's capacity as Managing Partner, as an
affiliate or as an officer, director, employee or agent of a Managing Partner or
an affiliate and as to any action in another capacity, and shall continue as to
an Indemnitee who has ceased to serve in such capacity and shall inure to the
benefit of the heirs, successors, assigns and administrators of the Indemnitee.
(d) The Partnership may purchase and maintain insurance, at the
Partnership's expense, on behalf of the Managing Partner and such other persons
as the Management Committee shall determine, against any liability that may be
asserted against or expense that may be incurred by such person in connection
with the activities of the Partnership and/or the Managing Partner's acts or
omissions as Managing Partner of the Partnership regardless of whether the
Partnership would have the power to indemnify such person against such liability
under the provisions of this Agreement.
(e) Any indemnification hereunder shall be satisfied solely out of
the assets of the Partnership. No Partner shall be subject to personal
liability by reason of these indemnification provisions.
(f) An Indemnitee shall not be denied indemnification in whole or in
part under this Section 14.2 by reason of the fact that the Indemnitee had an
interest in the transaction with respect to which the indemnification applies if
the transaction was otherwise permitted by the terms of this Agreement.
(g) The provisions of this Section 14.2 are for the benefit of the
Indemnitees, their heirs and personal representatives, and shall not be deemed
to create any rights for the benefit of any other Persons.
14.3 Management Committee Indemnification. The Partnership shall
------------------------------------
indemnify and save harmless the delegates to the Management Committee, including
the alternates, against all actions, claims, demands, costs and liabilities
arising out of the acts (or failure to act) of any such person in good faith
within the scope of their authority in the course of the Partnership's business,
and such persons shall not be liable for any obligations, liabilities or
commitments incurred by or on behalf of the Partnership as a result of any such
acts or failure to act, provided that the foregoing shall not entitle a member
to indemnification for gross negligence or willful misconduct.
14.4 Survival of Rights. The rights of the Managing Partner, and its
------------------
respective officers, directors, shareholders, employees or agents under this
Article XIV shall survive the termination of the Managing Partner's status as a
Partner of the Partnership.
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ARTICLE XV
GENERAL PROVISIONS
15.1 Arbitration. Any controversy or claim arising out of or relating to
-----------
this Agreement, or the breach thereof, which cannot be settled by agreement of
the Partners, shall be settled by arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association and judgment upon the
award rendered thereunder may be entered in any court having jurisdiction
thereof.
15.2 Press Releases. No Partner may issue a press release naming another
--------------
Partner in connection with the Partnership without the prior consent of the
Partner or Partners to be named; provided, however, that this provision shall
not prohibit the naming of a Partner in public documents when applicable law so
requires.
15.3 Notices.
-------
(a) Except as otherwise provided herein, any notice, distribution,
offer, report or other communication which is to be given to any Partner in
connection with the Partnership or this Agreement shall be in writing and shall
be deemed to have been duly given when delivered in person or sent by first-
class mail or by telecopy, telegram or telex, confirmed by letter sent to the
address set forth on Exhibit D to this Agreement or to such other address as a
Partner may notify the Managing Partner in writing.
(b) Delivery of a notice, demand, request or report sent by first
class mail or by telecopy, telegraph or telex shall be deemed to be effected at
the time when a duly addressed letter containing the same (or a confirmation
thereof in the case of a telecopy, telegram or telex message) is deposited,
postage prepaid, in the United States mail. The Managing Partner and the
Partnership, however, may act upon any telecopy, telegram or telex message
received by it from any Partner notwithstanding that such telecopy, telegram or
telex message is not subsequently confirmed by letter as aforesaid.
(c) Copies of any notices provided to any Partner in connection with
any documents relating to the Partnership's rights in the Combined Project, or
loan documents or other financing documents (or any documents relating thereto)
shall be forwarded to each other Partner promptly upon receipt.
15.4 Survival of Rights. This Agreement shall be binding upon, and, as to
------------------
permitted or accepted successors, transferees and assigns, inure to the benefit
of the Partners and the Partnership and their respective heirs, legatees, legal
representatives, successors, transferees and assigns, in all cases whether by
the laws of descent and distribution, merger, reverse merger, consolidation,
sale of assets, other sale, operation of law or otherwise.
41
<PAGE>
15.5 Construction. The language in all parts of this Agreement shall be
------------
in all cases construed simply according to its fair meaning and not strictly for
or against the Partners or the Managing Partner.
15.6 Section Headings. The captions of the Articles or Sections in this
----------------
Agreement are for convenience only and in no way define, limit, extend or
describe the scope or intent of any of the provisions hereof, shall not be
deemed part of this Agreement and shall not be used in construing or
interpreting this Agreement.
15.7 Agreement in Counterparts. This Agreement and any amendments hereto
-------------------------
may be executed in multiple counterparts, each of which shall be deemed an
original agreement and all of which shall constitute one and the same agreement,
notwithstanding the fact that all parties are not signatories to the original or
the same counterpart. For purposes of recording this instrument, if required,
multiple signature pages and acknowledgment pages may be attached to each
counterpart; the signature pages and the acknowledgment pages pertaining thereto
may be detached from the counterpart, when executed, and attached to another
counterpart, which other counterpart may thereafter be recorded.
15.8 Governing Law. This Agreement shall be construed according to the
-------------
internal laws, but not the laws pertaining to choice or conflict of laws, of the
State of California.
15.9 Additional Documents. Each Partner, upon the request of the
--------------------
Management Committee, agrees to perform all further acts and execute,
acknowledge and deliver all further documents which may be reasonably necessary,
appropriate or desirable to carry out the provisions of this Agreement,
including but not limited to acknowledging before a notary public any signature
heretofore or hereafter made by a Partner.
15.10 Severability. Should any portion or provision of this Agreement be
------------
declared illegal, invalid or unenforceable in any jurisdiction, then such
portion or provision shall be deemed to be severable from this Agreement as to
such jurisdiction (but, to the extent permitted by law, not elsewhere) and in
any event such illegality, invalidity or unenforceability shall not affect the
remainder hereof.
15.11 Pronouns and Plurals. Whenever the context may require, any pronoun
--------------------
used in this Agreement shall include the corresponding masculine, feminine or
neuter forms, and the singular form of nouns, pronouns and verbs shall include
the plural and vice versa.
15.12 Third Party Beneficiaries. There are no third party beneficiaries
-------------------------
of this Agreement.
15.13 Partition. The Partners agree that any assets the Partnership may
---------
at any time have may not be suitable for partition. Each Partner hereby
irrevocably waives any and all rights that
42
<PAGE>
he may have to maintain any action for partition of any assets the Partnership
may at any time have.
15.14 Security Interest and Right of Set-Off. As security for any
--------------------------------------
withholding tax or other liability or obligation to which the Partnership may be
subject as a result of any act or status of any Partner or to which the
Partnership becomes subject with respect to the Interests of any Partner, the
Partnership shall have (and each Partner hereby grants to the Partnership) a
security interest in all Division I or Division II Cash Flow from Operations or
Division I or Division II Cash Flow from Capital Events distributable to such
Partner to the extent of the amount of such withholding tax or other liability
or obligation. The Partnership shall have a right to setoff against any such
cash distributable in the amount of such withholding tax or other liability or
obligation.
15.15 Entire Agreement. This Agreement delivered by the Partners
----------------
constitutes the entire agreement of the Partners with respect to, and supersedes
all prior written and prior and contemporaneous oral agreements, understandings
and negotiations, including the Original Agreement, with respect to, the subject
matter hereof.
15.16 Waiver. No failure by any party to insist upon the strict
------
performance of any covenant, duty, agreement or condition of this Agreement or
to exercise any right or remedy consequent upon a breach thereof shall
constitute a waiver of any such breach or any other covenant, duty, agreement or
condition.
15.17 Attorneys' Fees. In the event of any litigation or arbitration
----------------
between the parties hereto with respect to the subject matter hereof, the
unsuccessful party to such litigation or arbitration shall pay to the successful
party all costs and expenses, including, without limitation, reasonable
attorneys' fees and expenses, incurred therein by the successful party, all of
which shall be included in and as a part of the judgment or decision rendered in
such litigation or arbitration.
END OF PAGE
43
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as
of the date first set forth above.
By: New CLOC Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ Christopher T. McCallion
----------------------------
Christopher T. McCallion
Executive Vice President
By: ESCA, LLC,
a Delaware limited liability company,
its General Partner
By: Caithness Geothermal 1980 Ltd., L.P.
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
----------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ Christopher T. McCallion
----------------------------
Christopher T. McCallion
Executive Vice President
By: ESI Geothermal, Inc.,
a Florida corporation,
its Member
By: /s/ Kenneth P. Hoffman
-----------------------------
Name: Kenneth P. Hoffman
Title: Vice President
44
<PAGE>
EXHIBIT A
TURBINE 1 PROJECT AREA
The Turbine 1 Project Area shall consist of the two parcels designated
below each of which consists of the following partial sections of Township 22
South, Range 39 East, Mount Diablo base and Meridian, in the County of Inyo,
State of California, including the surface area thereof and the subsurface areas
thereunder, except that: (1) the assignment of rights to Parcel A does not
include the geothermal resource underlying the North 2 of Section 8; (2) the
assignment of rights to Parcel A, with respect to the North 2 of Section 8 is
subject to the Partial Release as set forth and subject to the conditions in the
Deed of Trust (Navy 1) dated July 14, 1987 executed by CLJV and CFP; (3) the
assignment of rights to Parcel B is subject to release and reconveyance upon the
satisfaction of the conditions set forth in and subject to the conditions in the
Letter Agreement between Coso Finance Partners and Credit Suisse, dated July 14,
1987 and (4) the assignment of rights to each of the following section and
partial sections are subject to an easement of access for CLJV or its assignees
to use for construction, maintenance or operation of plants to be built adjacent
to or in the immediate vicinity of Turbine 1:
Parcel A: Southeast 1/4 of Section 7;
All of Section 8;
Southwest 1/4 of Section 9;
Parcel B: Northeast 1/4 of Section 18
North 2 of the North 2 of Section 17.
45
<PAGE>
EXHIBIT B
TURBINES 2 and 3 PROJECT AREA
The Turbines 2 and 3 Project Area shall consist of the parcels described
below, including the surface rights and subsurface rights:
The Southwest quarter of the Southwest quarter of Section 4; the South half
of the South half of Section 5; the South half of the Southeast quarter of
Section 6; the Southeast quarter of the Southwest quarter of Section 6; the
Northeast quarter of Section 7; the North half of Section 8; and the North
half and the Southeast quarter of Section 9; all located in Township 22
South, Range 39 East, Mount Diablo Base and Meridian, in the County of
Inyo, State of California.
46
<PAGE>
EXHIBIT C
RIGHT-OF-WAY DESCRIPTION
FOR
COSO-INYOKERN 115 KV TRANSMISSION LINE
_______________
The COSO-Inyokern 115 KV Transmission Line begins at survey station
0+00 at the Inyokern Substation in the SE 1/4, SE 1/4 of Section 20, T26S, R39E,
in Kern County, California and goes Northerly approximately 28.3 miles ending at
survey station 1505+03.87 at COSO Geothermal Plant No. 1 Switch Yard in SW 1/4,
NW 1/4 of Section 8, T22S, R39E in Inyo County, California. The Transmission
Line is located entirely within the boundaries of the China Lake Naval Weapons
Center.
The right-of-way for the transmission line is a strip of land 200 feet
wide of which 65 feet of this right-of-way is located to the left (Westerly) of
the transmission line centerline and 135 feet is located to the right (Easterly)
of the transmission centerline.
The Transmission centerline is described as follows:
Sections 20, 7, 8, 5 & 6 of T26S, R39E
--------------------------------------
Beginning at survey station 0+00, which is located on the North
boundary fence line of the Inyokern sub-station and is 400 feet West and 320
feet North of the SE Corner of Section 20, T26S, R39E. Thence, from station
0+00, N21(degrees)11'57"W a distance of 255.00 feet to an angle point at station
2+55.00; thence N17(degrees)40'18"W a distance of 21,637 feet to the Leliter
Road crossing at station 218+92 which is a point on the North boundary of
Section 6, T26S, R39E and is 1410 feet West of the NE Corner of Section 6, T26S,
R39E.
Sections 31, 30 & 19 of T25S, R39E
----------------------------------
Thence, from station 218+92, N17(degrees)40'18"W a distance of 13,228
to station 351+20 which is a Point on the West boundary of Section 19, T25S,
R39E and is 1960 feet North of the SW Corner of Section 19, T25S, R39E.
Sections 24, 13, 12, 1 & 2 of T25S, R38E
----------------------------------------
Thence, from station 351+20, N17(degrees)40'18"W a distance of 20,165
feet to survey station 552+85 which is a point on the Kern and Inyo County Line
and on the North boundary of Section 2, T25S, R38E and is 540 feet West of the
NE Corner of Section 2, T25S, R38E.
47
<PAGE>
Sections 35, 34, 27, 22, 15, 10 & 3 of T24S, R38E
-------------------------------------------------
Thence, from station 552+85, N17(degrees)40'18"W a distance of 980.65
feet to an angle point at station 562+65.65; thence N00(degrees)32'59"E a
distance of 1849.86 feet to an angle point at station 581+15.51; thence
N18(degrees)55"43"W a distance of 8200.72 feet to an angle point at station
663+16.23; thence N17(degrees)49'44"W a distance of 6843.04 feet to an angle
point at station 731+59.27; thence N09(degrees)26'36"E a distance of 13,280.99
feet to an angle point at Equation station 864+40.26 Back = 873+79.76 Ahead;
thence N07(degrees)43'29"E a distance of 1460 feet to survey station 888+39.76
which is a point on the North boundary of Section 3, T24S, R38E and is 1680 feet
West of the NE Corner of Section 3, T24S, R38E.
Sections 34, 27, 26, 23, 24, 13, 12 & 1, T23S, R38E
---------------------------------------------------
Thence from station 888+39.76, N07(degrees)43'29"E a distance of
5111.45 to an angle point at station 939+51.21; thence N31(degrees)43'12"E a
distance of 9820.50 feet to an angle point at station 1037+71.71; thence
N31(degrees)14'47"E a distance of 10,758.97 feet to an angle point at station
1145+30.68; thence N10(degrees)29'29"W a distance of 8780.38 feet to survey
station 1233+11.06 which is a point on the North boundary of Section 1, T23S,
R38E and is 1600 feet West of the NE Corner of Section 1, T23S, R38E.
Section 36 of T22S, R38E
------------------------
Thence, from station 1233+11.06, N10(degrees)29'29"W a distance of
1200.00 feet to an angle point at station 1245+11.06; thence N43(degrees)08'19"E
a distance of 2718.94 feet to survey station 1272+30 which is a point on the
East boundary of Section 36, T22S, R38E and is 2180 feet South of the NE Corner
of Section 36, T22S, R38E.
Section 31, 30, 19, 18, 7 & 8 of T22S, R39E
-------------------------------------------
Thence, from station 1272+30, N43(degrees)08'19"E a distance of
1922.34 feet to an angle point at station 1291+52.34; thence N06(degrees)45'07"E
a distance of 12,581.98 feet to an angle point at station 1417+34.32; thence
N00(degrees)50'59"W a distance of 4,017.81 feet to an angle point at station
1457+52.13; thence N55(degrees)41'23"E a distance of 1,152.30 feet to an angle
point at station 1469+04.43; thence N13(degrees)42'55"E a distance of 1,065.66
feet to, an angle point at station 1479+70.09; thence N81(degrees)26'21"E a
distance of 1,169.68 feet to an angle point at station 1491+39.77; thence
N25(degrees)26'31"E a distance of 1,135.98 feet to an angle point at station
1502+75.75; thence N05(degrees)40'26"E a distance of 228.12 feet to the end of
the COSO-Inyokern 115 KV Transmission Line at survey station 1505+03.87. This
ending point is located at the COSO Geothermal Plant No. 1 Switch Yard in the SW
1/4, NW 1/4 of Section 8, T22S, R39E in Inyo County, California.
48
<PAGE>
EXHIBIT D
ADDRESSES OF PARTIES FOR NOTICES
--------------------------------
If to CFP:
Coso Finance Partners
c/o Caithness Energy, LLC
1114 Avenue of the Americas
New York, New York 10036
Attn: President
If to ESCA:
Caithness Geothermal 1980, Ltd.
c/o Caithness Energy, LLC
1114 Avenue of the Americas
New York, New York 10036
Attn: President
and
ESI Geothermal, Inc.
700 Universe Boulevard
June Beach, Florida 33408
Attn: Vice President - Business Management
49
<PAGE>
EXHIBIT E
ESCROW ACCOUNT DISTRIBUTION PROVISIONS
1. Amounts deposited in the Escrow Account with respect to a Preferred
Return Year shall be distributed promptly after it is determined whether the
Distribution Condition is satisfied with respect to that Preferred Return Year,
as follows:
(a) if the Distribution Condition was satisfied for the Preferred
Return Year:
(i) first, to CCH, ESCA and Navy II Group, as directed in
writing by an authorized representative thereof, until distributions pursuant to
this Section 1(a)(i) equal the lesser of (a) the Maximum Payment for the
Preferred Return Year, and (b) the amount or deposit in the Escrow Account;
(ii) the balance to the Managing Partner; or
(b) to the Managing Partner, if the Distribution Condition was not
satisfied for the Preferred Return Year.
2. Amounts deposited in the Escrow Account pursuant to Sections
5.2(a)(ii) of the CPD and CED Partnership Agreements and Sections 5.3(a)(ii) and
5.4(a)(ii) of the CFP Partnership Agreement shall be distributed within fifteen
days after deposit to CCH, ESCA and Navy II Group, as directed in writing by an
authorized representative thereof.
3. All amounts distributed pursuant to Section 1(a)(i) and Section 2 will
be applied (i) first, to reduce Preferred Return Interest, and (ii) second, to
reduce the Preferred Return.
4. For the purpose of Section 1, "Distribution Condition" means the
generation of Excess Revenues by at least one Project during the Preferred
Return Year.
50
<PAGE>
EXHIBIT 3.4
THIRD AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT
OF
COSO ENERGY DEVELOPERS
This THIRD AMENDED AND RESTATED GENERAL PARTNERSHIP AGREEMENT (the
"Agreement"), of Coso Energy Developers (the "Partnership"), dated as of May 28,
1999, is between (a) Caithness Coso Holdings, LLC, a Delaware limited liability
company (successor by merger with Caithness Coso Holdings, L.P., a California
limited partnership) ("CCH"), of which the general partners are Caithness BLM
Group, L.P., a Delaware limited partnership (successor by merger with Caithness
BLM Group, L.P., a New Jersey limited partnership) ("BLM Group") and Caithness
CEA Geothermal, L.P., a Delaware limited partnership ("CCG"), and (b) New CHIP
Company, LLC, a Delaware limited liability company ("New CHIP").
RECITALS
--------
Effective May 1, 1985, CalEnergy Company, Inc., a Delaware corporation
(formerly known as California Energy Company, Inc.) ("CECI") entered into a
lease for Parcel 20 (the "BLM Lease") with the United States Department of the
Interior, Bureau of Land Management ("BLM") to develop geothermal energy at
China Lake, California, and to sell the resultant electricity.
CECI and Caithness Geothermal 1980 Ltd., a Delaware limited partnership
(successor by merger with Caithness Geothermal 1980 Ltd., a New Jersey limited
partnership) ("CG-80"), caused the formation of the China Lake Joint Venture
("CLJV"), a California joint venture. CLJV acquired rights pursuant to the Navy
Contract to develop geothermal resources on the Naval Weapons Center near China
Lake, California.
CECI, MJV (as defined below) and Coso Land Company, a California joint
venture comprised of CECI and CG-80, entered into a Joint Venture Agreement to
form the Coso Geothermal Company ("CGC"), a California joint venture, effective
as of March 15, 1983 (as in existence, amended and restated from time to time,
the "CGC Agreement"). The CGC Agreement sets forth the relationship between the
joint venturers regarding the development and operation of a geothermal power
generating system for the BLM Project (as defined below); established a
management committee; designated CECI the "Operator"; set forth the Operator's
rights and duties; and provided guidelines for conduct of the geothermal power
project.
CECI assigned its rights and obligations under the BLM Lease to Coso Land
Company ("CLC"), a California joint venture between CECI and CG-80 which
assignment was subsequently approved by the BLM. CLC assigned and transferred
certain of its leasehold interests to CGC.
<PAGE>
CGC entered into an agreement (the "Power Sales Agreement") with Southern
California Edison Company to sell electricity generated from the BLM Project to
Southern California Edison Company.
CGC financed further development and operations of the BLM Project pursuant
to certain debt and equity financing, the proceeds of which were used to
construct the BLM Project, through the use of this Partnership.
CECI, MJV, CLC, Caithness Corporation, a Delaware corporation
("Caithness"), Mt. Whitney, Pacific, CG-80, CG 80-I (as defined below), and West
Coast Geothermal Ltd., a Delaware limited partnership (successor by merger with
West Coast Geothermal Ltd., a New Jersey limited partnership) ("West Coast")
have, or have caused CGC, as applicable, to assign to the Partnership their
proportionate share of the BLM Assigned Rights.
CECI and CG-80 caused CLJV to assign to the Partnership their proportionate
share of the Navy II Assigned Rights.
CECI caused the formation of CHIP, and Caithness Corporation in its
capacity as a general partner of BLM Group and Navy II Group, L.P., a Delaware
limited partnership (successor by merger with Navy II Group, L.P., a New Jersey
limited partnership) ("Navy II Group") caused the formation of CCH, and CHIP and
CCH caused the formation of the Partnership to carry out the obligations and
receive the benefits relating to the BLM Assigned Rights and Navy II Assigned
Rights (as defined below), and to the BLM Project and Navy II Project,
respectively, that otherwise would have been attributable to CLC, CGC and CLJV.
The Navy II Assigned Rights were assigned to Coso Power Developers, a
California general partnership ("CPD"), and the Navy II Group withdrew from CCH
and CCG was admitted as a substitute partner.
Pursuant to that certain Agreement and Plan of Merger dated as of February
25, 1999, CHIP was merged with and into New CHIP, and New CHIP became the
successor-in-interest to CHIP.
Concurrently with this Agreement, the Partnership is acquiring, subject to
BLM approval, an undivided interest as a tenant-in-common in and to the
Additional BLM Leases (as hereinafter defined) and has entered into the Co-
Tenancy Agreement (as hereinafter defined) in order to utilize the resources
from said lands for the BLM Project.
The parties hereto desire to provide for the continued existence and
governance of the Partnership and to set forth in detail their respective rights
and duties relating to the Partnership.
2
<PAGE>
NOW, THEREFORE, in consideration of the mutual covenants, conditions and
agreements herein contained, the parties agree as follows:
ARTICLE I
DEFINITIONS
The capitalized words and phrases used in this Agreement shall, unless the
context otherwise requires, have the meanings specified in this Article I.
1.1 "Act" means the California Uniform Partnership Act, as amended from
time to time.
1.2 "Additional BLM Leases" means that certain (i) Geothermal Resources
Lease, Serial No. CA-11384, by and between the United States of America, acting
through the BLM, and the LADWP, effective as of February 1, 1982, as amended;
(ii) Geothermal Resources Lease, Serial No. CA-11385, by and between the United
States of America, acting through the BLM, and the LADWP, effective as of
February 1, 1982, as amended; and, (iii) Geothermal Resources Lease, Serial No.
CA-11383, by and between the United States of America, acting through the BLM,
and the LADWP, effective as of February 1, 1982, as amended.
1.3 "Additional Capital Contributions" has the meaning defined in Section
4.2 of this Agreement.
1.4 "Agreement" or "Partnership Agreement" means this Partnership
Agreement, as amended from time to time. Words such as "herein", "hereof",
"hereto" and "hereunder", refer to this Agreement as a whole, unless the context
otherwise requires.
1.5 "BLM Assigned Rights" means the following rights assigned by CGC and
CLC and by Pacific to the Partnership in partial consideration of the issuance
of Interests to CHIP and CCH:
(a) the BLM Project Area Rights;
(b) the BLM Power Sales Contract;
(c) an assignment of all assignable BLM Project Authorizations;
(d) an assignment of Pacific's rights to receive certain cash flows
from CGC; and
(e) the rights and obligations under the Memorandum of Understanding
between CGC and Mission Power Engineering Company.
3
<PAGE>
The BLM Assigned Rights are subject to all related obligations and liabilities
assumed by the Partnership.
1.6 "BLM Capital Account" means that portion of the Capital Account for
each Partner pertaining to the BLM Project, maintained in accordance with the
provisions of Section 1.22 of this Agreement.
1.7 "BLM Capital Contribution" means the Capital Contribution of each
Partner with respect to the BLM Project.
1.8 "BLM Capital Event" means any of the following: (a) a sale,
repayment, exchange, transfer, assignment or other disposition of all or a
portion of any BLM asset (but not including occasional sales in the ordinary
course of business of inventory, furniture, fixtures and equipment); (b) any
financing or refinancing of, or with respect to, a BLM Project asset; (c) any
condemnation or deeding in lieu of condemnation of a BLM Project asset; (d) any
collection with respect to property, hazard or casualty insurance (but not
business interruption insurance) or any damage award; or (e) any other BLM
Project transaction the proceeds of which, in accordance with generally accepted
accounting principles, are considered to be capital in nature.
1.9 "BLM Cash Flow from Capital Events" means Cash Flow from Capital
Events pertaining to ownership and operation of the BLM Project.
1.10 "BLM Cash Flow from Operations" means Cash Flow from Operations
pertaining to ownership and operation of the BLM Project.
1.11 "BLM Group" means Caithness BLM Group L.P., a Delaware limited
partnership (successor by merger with BLM Group L.P., a New Jersey limited
partnership).
1.12 "BLM Lease" means the lease to Parcel 20, lease #CA-11402, dated
April 19, 1985 and effective May 1, 1985, between the BLM and CECI, assigned to
CLC and further assigned to CGC and further assigned to the Partnership.
1.13 "BLM Payout" means the point at which each Partner has received
aggregate distributions of BLM Cash Flow from Operations and BLM Cash Flow from
Capital Events in an amount equal to (a) its initial BLM Capital Contribution
set forth in Section 4.1(b), plus (b) any cash contributions and the cash value,
as determined by the Management Committee, of any property contributed to the
Partnership for the BLM Project by that Partner after the date of this
Agreement; provided, however, that the distribution of BLM Cash Flow from
Operations to the Managing Partner under Section 5.1(a)(i) shall not be
considered a distribution in computing whether BLM Payout has been achieved.
4
<PAGE>
1.14 "BLM Power Sales Contract" means the Power Sales Contract dated
September 7, 1983 between Southern California Edison Company and CGC as
subsequently amended.
1.15 "BLM Project" means the construction and operation of geothermal
power plants on the BLM Project Area and the development and operation of the
BLM Project Area Rights and, from and after the date of this Agreement and
subject to and in accordance with the terms and conditions of the Co-Tenancy
Agreement, the rights and interests under the Additional BLM Leases.
1.16 "BLM Project Area" means the area subject to the BLM Lease, defined
in Exhibit A.
1.17 "BLM Project Area Rights" means the rights, titles, interests,
estates, powers and privileges CGC has pursuant to the BLM Lease with respect to
the Project Area, including rights to all wells, the Transmission Line, the
plant site, and other facilities (and all improvements, equipment, fixtures and
other items appurtenant or accessorial to those wells or facilities), and
including rights of access and egress to the BLM Project Area, subject to the
terms and conditions of the BLM Lease, and, subject to and in accordance with
the terms and conditions of the Co-Tenancy Agreement, the rights and interests
under the Additional BLM Leases.
1.18 "BLM Project Authorizations" means all permits, authorizations,
rights of way and licenses necessary or appropriate to operate and maintain the
BLM Project and the geothermal resources subject to the BLM Project Area Rights.
1.19 "Book", when used to modify an item of income, gain, loss or
deduction, or any word in reference thereto, means the amount thereof taken into
account for capital accounting purposes under the principles of Section 1.22 and
Regulation Section 1.704-1(b)(2)(iv).
1.20 "Budget" means each of the budgets to be prepared by the Managing
Partner and approved by the Management Committee pursuant to Section 7.4.
1.21 "Business Day" means any day that is not a Saturday, Sunday or a day
on which banking institutions in the City of San Francisco, State of California,
are authorized or required to close by law, executive order or Regulation.
1.22 "Capital Account" with respect to each Partner means the capital
account of that Partner determined and maintained throughout the full term of
the Partnership in accordance with the rules set forth in Regulation Section
1.704-1(b) (2)(iv). The initial balance of each Partner's Capital Account is
set forth in the Partnership books and records. In the event the Management
Committee determines that it is prudent to modify the manner in which the
5
<PAGE>
Capital Accounts are maintained, or any debits or credits thereto (including,
without limitation, debits or credits relating to liabilities which are secured
by contributed or distributed property, or assumed by the Partnership with
regard to such asset with the approval of the Partnership), are accounted for,
in order to comply with such Regulations or if unanticipated events otherwise
cause the Partners' Capital Accounts not to comply with such Regulations, the
Management Committee may make such modification, provided that it is not likely
to have material effect on the amounts distributable to any Partner. Subject to
the three previous sentences:
(a) Each Partner's Capital Account shall be increased by (i) the
amount of money contributed by such Partner to the Partnership, (ii) the Fair
Market Value of property contributed by such Partner to the Partnership (net of
liabilities secured by such contributed property that the Partnership is
considered to assume or take subject to under Code Section 752), and (iii)
Partnership income and gain (or items thereof) allocated to such Partner; and
shall be decreased by (iv) the amount of money distributed to such Partner by
the Partnership; (v) the Fair Market Value of property distributed to such
Partner by the Partnership (net of liabilities secured by such distributed
property that such Partner is considered to assume or take subject to under Code
Section 752); (vi) Partnership loss or deductions (or item thereof) allocated to
such Partner; (vii) the Partner's share of expenditures of the Partnership
described in Code Section 705(a)(2)(B), including for this purpose losses which
are nondeductible under Code Section 267(a)(1) or Code Section 707(b); and
(viii) the Partner's share of amounts paid or incurred by the Partnership to
organize the Partnership or to promote the sale of (or to sell) an interest in
the Partnership (except to the extent properly amortizable for tax purposes).
(b) For this purpose, "income" refers to all items of income
(including all items of gain and including income exempt from tax) as properly
determined for Book purposes, and "loss" refers to all items of loss (including
all items of deduction) as properly determined for Book purposes.
(c) An assumption of a Partner's unsecured liability by the
Partnership shall be treated as a distribution of money to the Partner. An
assumption of the Partnership's unsecured liability by a Partner shall be
treated as a cash contribution to the Partnership.
(d) Capital Accounts shall be adjusted appropriately on account of
investment tax credit and investment tax credit recapture in accordance with the
principles of Code Section 48(q) and Regulation Section 1.704-1(b).
(e) In the event that assets of the Partnership other than cash are
distributed to a Partner in kind, Capital Accounts shall be adjusted for the
hypothetical Book gain or Book loss that would have been realized by the
Partnership if the distributed assets had been sold for their Fair Market Value
in a cash sale (in order to reflect unrealized Book gain or Book loss).
6
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(f) At the option of the Management Committee, in the event of a
contribution of money or other property (other than a de minimus amount) to the
Partnership by a new or existing Partner as consideration for an interest in the
Partnership, or in connection with a distribution of money or other property
(other than a de minimus amount) by the Partnership to a continuing Partner as
consideration for an interest in the Partnership, Capital Accounts shall be
adjusted for the hypothetical Book gain or Book loss that would have been
realized by the Partnership if all Partnership assets had been sold for their
Fair Market Value in a cash sale (in order to reflect unrealized Book gain or
Book loss).
(g) In the event of a distribution of money or other property (other
than a de minimus amount) by the Partnership to a retiring Partner as
consideration for its interest in the Partnership, Capital Accounts shall be
adjusted for the hypothetical Book gain or Book loss that would have been
realized by the Partnership if all Partnership assets had been sold for their
Fair Market Value in a cash sale (in order to reflect unrealized Book gain or
Book loss).
1.23 "Capital Contribution" means the amount of money plus the Fair Market
Value of property contributed by a Partner to the Partnership.
1.24 "Capital Event" means any of the following: (a) a sale, repayment,
exchange, transfer, assignment or other disposition of all or a portion of any
asset (but not including occasional sales in the ordinary course of business of
inventory, furniture, fixtures and equipment); (b) any financing or refinancing
of, or with respect to, an asset; (c) any condemnation or deeding in lieu of
condemnation of a Project asset; (d) any collection with respect to property,
hazard or casualty insurance (but not business interruption insurance) or any
damage award; or (e) any other transaction the proceeds of which, in accordance
with generally accepted accounting principles, are considered to be capital in
nature.
1.25 "Cash Flow from Capital Events" shall mean the net proceeds from each
Capital Event which the Management Committee makes available for distribution
after the Management Committee has set aside the amounts deemed prudent by the
Management Committee to: (a) replace tangible property disposed of or destroyed
and (b) provide working capital for the Partnership.
1.26 "Cash Flow from Operations" means, with respect to any fiscal period
and determined on the basis of a closing or interim closing of the books as of
the end of such period: (a) all cash receipts received during such fiscal
period by the Partnership (other than Cash Flow from Capital Events and Capital
Contributions); plus (b) any amounts that were originally reserved from amounts
that would otherwise have been Cash Flow from Operations that are no longer
deemed by the Management Committee to be required as reserves; less (c) all cash
outlays during such fiscal period to pay expenses of the Partnership; less (d)
any amounts set aside as reserves, including reserves for capital improvements,
expenses or contingent liabilities; less (e) payments (and reserves for
payments) of debt service (and premiums or penalties thereon, if any) on
indebtedness of the Partnership.
7
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1.27 "CCG" means Caithness CEA Geothermal, a Delaware limited partnership.
1.28 "CFP" means Coso Finance Partners, a California general partnership.
1.29 "CGC Agreement" means the Joint Venture Agreement effective March 15,
1983 between CECI, MJV and CLC as may be amended from time to time.
1.30 "CLC" means Coso Land Company, a California joint venture between COC
(as assignee of CECI) and CG-80.
1.31 "COC" means Coso Operating Company, LLC, a Delaware limited liability
company.
1.32 "Code" means the Internal Revenue Code of 1986, as amended from time
to time, and any succeeding law.
1.33 "Co-Tenancy Agreement" means that certain Co-Tenancy Agreement, dated
as of even date herewith, by and between, CPD, the Partnership, and Coso Finance
Partners, a California general partnership.
1.34 "CPD" means Coso Power Developers, a California general partnership.
1.35 "CTLP" means Coso Transmission Line Partners, a California general
partnership, the general partners of which are Coso Power Developers and the
Partnership.
1.36 "Distribution Date" means the 45th day following the end of each
calendar quarter, commencing with the second quarter of 1988, or the next
succeeding Business Day if such day is not a Business Day.
1.37 "Escrow Account" means an interest-bearing deposit account acceptable
to the partners of each Joint Venture and established in the name of the
Managing Partner with a bank acceptable to the Partners, pursuant to an escrow
or other similar agreement which is acceptable to each such Partner and contains
distribution provisions in form attached as Exhibit D to this Agreement.
1.38 "Excess Revenues" means, with respect to a period and a Project, one-
half of the difference between (a) the revenue for the Project for the period,
minus (b) the revenue which would have been produced if the Project had operated
continuously during the period at 85% of nominal capacity (calculated at an
assumed capacity of 80 MW for the CPD Project and the CFP Project and 70 MW for
the CED Project).
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1.39 "Fair Market Value" shall mean the fair market value of an asset, as
reasonably agreed to among the Partners in arm's-length negotiations, net of
liabilities secured by such asset or assumed by the Partnership with regard to
such asset.
1.40 "FPLE" means FPL Energy Operating Services, a Florida corporation.
1.41 "Interest" means a partnership interest in the Partnership with the
rights, terms and preferences described in this Agreement.
1.42 "Joint Venture" means any or all of the Partnership, CPD and CFP.
1.43 "Management Committee" means the Management Committee established
pursuant to Article VIII.
1.44 "Managing Partner" means New CHIP.
1.45 "Maximum Payment" means an amount equal to the Preferred Return.
1.46 "Meeting" means a meeting of Partners or of the Management Committee
duly called in accordance with Article VIII hereof.
1.47 "MJV" means Mojave Joint Venture, a joint venture between CG-80, West
Coast and Pacific.
1.48 "Mt. Whitney" means Mt. Whitney Geothermal Ltd., a Delaware limited
partnership (successor by merger with Mt. Whitney Geothermal Ltd., a New Jersey
limited partnership).
1.49 "Navy II Assigned Rights" means the following rights that were
originally assigned to the Partnership by CLJV (subject to Section 4.1) in
partial consideration of the issuance of Interests to CHIP and CCH, and
subsequently were assigned to Coso Power Developers, a California general
partnership:
(a) the Navy II Project Area Rights;
(b) the Navy II Power Sales Contract; and
(c) an assignment of all assignable Navy II Project Authorizations.
1.50 "Navy II Group" means the Caithness Navy II Group, LLC, a Delaware
limited liability company (successor by merger with Caithness Navy II Group,
L.P., a New Jersey limited partnership).
9
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1.51 "Navy II Power Sales Contract" means the Power Sales Contract dated
February 1, 1985 between Southern California Edison Company and CLJV as
subsequently amended.
1.52 "Navy II Project" means the construction and operation of geothermal
power plants on the Navy II Project Area, and the development and operation of
the Navy II Project Area Rights.
1.53 "Navy II Project Area" means the area described in Exhibit A.
1.54 "Navy II Project Area Rights" means the rights, titles, interests,
estates, powers and privileges pursuant to the Navy Contract with respect to the
Navy II Project Area, including rights to all wells, the plant site, the
Transmission Line and other facilities (and all improvements, equipment,
fixtures and other items appurtenant or accessorial to those wells and
facilities), including rights of access and egress to the Navy II Project Area,
subject to the terms and conditions of the Navy Contract.
1.55 "Navy II Project Authorizations" means all permits, authorizations,
rights of way and licenses necessary or appropriate to operate and maintain the
Navy II Project and the geothermal resources subject to the Navy II Project Area
Rights.
1.56 "Navy Contract" means the Original Service Contract N 62474-79-C-5382
entered into between CECI and the United States Navy dated December 6, 1979,
together with all subsequent modifications thereto.
1.57 "Net Profit" and "Net Loss" as used in connection with the BLM
Project means the net "income" and net "loss" as those terms are used in Section
1.22(b), relative to the BLM Project.
1.58 "Operator" means such operator as is designated by the Managing
Partner pursuant to Article VII.
1.59 "Original Agreement" means the Restated General Partnership Agreement
of Coso Energy Developers dated March 31, 1988, as amended prior to the date
hereof.
1.60 "Pacific" means Pacific Geothermal Ltd., L.P., a Delaware limited
partnership (successor by merger with Pacific Geothermal Ltd., L.P., a New
Jersey limited partnership).
1.61 "Partners" means the Managing Partner, CCH, and all substituted or
additional Partners. Where no distinction is required by the context in which
the term is used herein, "Partner" means any one of the Partners.
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1.62 "Partnership" means Coso Energy Developers, a California general
partnership, as such partnership may be constituted from time to time.
1.63 "Plant Operations" means the operation and maintenance of all facets
of the BLM Project operation which do not constitute Resource Operations,
including operation of the Transmission Line, power transmission facilities and
substation interconnection facilities.
1.64 "Preferred Return" means (a) $7,500,000, plus (b) the amount of
Preferred Return Interest accrued during any previous Preferred Return Year that
was not paid from distributions from the Escrow Account for that Preferred
Return Year, less (c) the sum of all distributions from the Escrow Account
previously applied to reduce the Preferred Return. Notwithstanding the
foregoing, the Preferred Return was prepaid in full at a discount to the parties
entitled thereto on December 16, 1992; provided, however, that if for any
Preferred Return Year for which the Preferred Return would have been paid if
such prepayment had not been made the Distribution Condition is not satisfied,
then CCH shall promptly pay to the Escrow Account an amount equal to its
proportionate share (based on the percentage share of the Preferred Return paid
to it) of $715,000, which is the amount of the Preferred Return allocable to
each Preferred Return Year after taking into account the discount in connection
with the prepayment, to be distributed pursuant to Exhibit D.
---------
1.65 "Preferred Return Interest" means (a) an amount equivalent to the
interest which would have accrued from March 19, 1991 through the date of
determination on the amount of the Preferred Return, as adjusted to reflect
distributions for each previous Preferred Return Year, at a per annum rate of
10%, less (b) the sum of all distributions from the Escrow Account applied to
reduce Preferred Return Interest.
1.66 "Preferred Return Year" means each of the periods beginning on July 1
and ending on the immediately subsequent June 30. The first Preferred Return
Year shall begin on July 1, 1991, and the last Preferred Return Year shall end
on the date on which the Preferred Return would have been reduced to zero if
there had been no prepayment.
1.67 "Projects" means the three geothermal power projects owned by the
Joint Ventures.
1.68 "Regulation" means the Treasury Regulations promulgated under the
Code, as such Regulation may be amended from time to time including
corresponding provisions of any succeeding Regulations.
1.69 "Resource Operations" means the well drilling and well operation and
maintenance work for the BLM Project Area, as well as the operation and
maintenance of the geothermal resource related to the BLM Project Area, the
surface steam gathering system and brine disposal system, together with
construction and maintenance of buildings, roads and other surface structures on
the BLM Project Area.
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1.70 "Section", unless preceded by the words "Code" or "Regulation", means
a Section of this Agreement.
1.71 "Transmission Line" means the power line constructed pursuant to a
construction contract entered into by the Partnership, a preliminary description
of the right-of-way for which is included as Exhibit C hereof.
ARTICLE II
PARTNERSHIP AMENDMENT; IDENTIFICATION; AND TERM
2.1 Amendment. The parties hereto agree to amend and restate the Original
---------
Agreement. The Managing Partner shall do, make or cause to be made all such
filings, recording, publishing and other acts as may be necessary or appropriate
from time to time in connection therewith, and as required to preserve the
existence of the Partnership.
2.2 Name, Principal Executive Office, Registered Office and Registered
------------------------------------------------------------------
Agent for Service of Process. The name of the Partnership shall be COSO ENERGY
- ----------------------------
DEVELOPERS, or such other name or names as may be selected by the Management
Committee from time to time. The principal executive office of the Partnership
and the office at which shall be kept the records, if any, required by the Act
shall be 1114 Avenue of the Americas, 41/st/ Floor, New York, New York 10036,
unless changed by the Managing Partner. The Partnership may also maintain such
other offices at such other places as the Managing Partner may deem advisable.
The name of the Partnership's agent for service of process is Corporation
Service Company, 80 State Street, Albany, New York 12207 and Corporation Service
Company, which will do business in California as CSCC--Lawyers Incorporating
Services, 2730 Gateway Oak Drive, Sacramento, California 95833.
2.3 Term. The term of the Partnership commenced on March 31, 1988 and
----
shall continue so long as it has any geothermal property interests in the BLM
Project Area Rights, or so long as it has any obligations outstanding to any
lender having provided construction or term financing to the Partnership, or any
assignee thereof, unless the Partnership is terminated earlier in accordance
with Article XIII; provided, however, that nothing contained herein shall be
deemed to give a Partner a right to withdraw from the Partnership.
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ARTICLE III
PURPOSE AND NATURE OF BUSINESS; CERTAIN OBLIGATIONS
3.1 Purpose. The purpose of the Partnership and the business to be
-------
carried on by it, subject to the limitations contained elsewhere in this
Agreement, are:
(a) To hold the BLM Assigned Rights (subject to the conditions of this
Agreement), to develop the same, and to develop, construct, own and operate the
BLM Project;
(b) To raise sufficient capital through borrowings from banks or other
lenders to finance the construction of the BLM Project, and to provide for the
development and the exploitation of the lands subject to the BLM Project Area
Rights;
(c) To borrow money for any legitimate Partnership purpose and in
connection therewith to issue notes, bonds, debentures and other evidences of
indebtedness and to secure the same and hypothecate any, all or substantially
all of the assets of the Partnership by mortgage, deed of trust, pledge or other
lien in furtherance of the foregoing purposes of the Partnership;
(d) To enter into and perform contracts and agreements and to carry on
any other activities necessary to, or desirable or incidental in connection
with, the accomplishment of the foregoing purposes of the Partnership;
(e) To engage in any kind of activity and to enter into and perform
obligations of any kind necessary to, or in connection with, or incidental to,
the accomplishment of the purposes and business of the Partnership, so long as
such activities and obligations may lawfully be engaged in or performed by a
partnership under the Act; and
(f) To be a general partner of CTLP.
Such purpose and business of the Partnership shall include the entering
into by the Partnership of the transactions described in that certain
preliminary Offering Circular of Caithness Coso Funding Corp. dated May 5, 1999
(as it may have been revised, the "Offering Circular"), including without
limitation the making by the Partnership of certain loans to and the pledging by
the Partnership of certain funds of the Partnership for payment of certain
obligations of affiliated partnerships, all to the extent provided for and
described in the Offering Circular and the definitive documents entered into in
accordance therewith.
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ARTICLE IV
CAPITAL
4.1 Partners' Capital Contributions to the Partnership.
--------------------------------------------------
(a) CECI, CLC, Pacific, Mt. Whitney, West Coast, Caithness and MJV
caused CGC to assign to the Partnership, for the benefit of New CHIP and CCH,
respectively, all of the BLM Assigned Rights and rights to the BLM Project held
by CGC and Pacific, respectively, under the CGC Agreement and by Pacific under
an assignment from CGC. The Partnership has assumed and taken the contributed
property subject to all liabilities secured by the contributed property at the
time of contribution or assumed by the Partnership with regard to such asset.
(b) The Partners agree that the fair market value of each Partner's
BLM Capital Contribution is as indicated in the books and records of the
Partnership.
4.2 Additional Capital Contributions. Each Partner shall have the right,
--------------------------------
but not the obligation, to make additional capital contributions ("Additional
Capital Contributions") under the terms of this Section 4.2.
(a) A Partner may make an Additional Capital Contribution only if one
or both of the following conditions has occurred:
(i) the Management Committee has approved a Budget authorizing
Additional Capital Contributions; or
(ii) a Partner has notified the Management Committee in writing
that, in that Partner's best business judgment, the Partnership requires
additional equity capital for any bona fide reasonable business purpose relating
to drilling and construction necessary to bring on line for commercial
operations the power plants to provide electricity for the BLM Power Sales
Contract (such notice to include a proposed required capital amount and
description of the uses and schedule of application of the funds), and the
Management Committee has not approved the proposal within 10 days of the notice.
(b) (i) If the conditions described in (a) above have occurred,
either Partner without first being required to obtain the approval of the other
Partner shall give written notice to the other Partner, which shall specify the
amount of Additional Capital Contributions required and the contribution date
("Contribution Date") upon which the Partners shall contribute the Additional
Capital Contributions to the capital of the Partnership. The Additional Capital
Contributions shall be contributed to the capital of the Partnership by each of
the Partners in the ratio of 50/50;
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(ii) In the event that at any time either Partner shall fail to
contribute its share of the Additional Capital Contributions on the Contribution
Date (for purposes of this subsection (ii), a "Defaulting Partner"), as provided
in Section 4.2(b)(i), then, as to each such default, the other Partner (for
purposes of this subsection (ii), the "Contributing Partner") shall have the
right, but not the obligation, to make the contribution of Additional Capital
Contributions which the Defaulting Partner failed to make (but only after the
Contributing Partner made the full amount of its own Additional Capital
Contributions) on behalf of the Defaulting Partner by giving notice to the
Defaulting Partner within twenty days after the Contribution Date, in which
event such sum shall become and be treated as a loan ("Default Loan") by the
Contributing Partner to the Defaulting Partner bearing interest at the rate of
two percentage points above the rate of interest publicly announced by Chase
Manhattan Bank N.A., in New York, from time to time as its "Prime" or "Base"
rate of interest, and due and payable in full on the date which is six months
after the Contribution Date (the "Default Date"). The Defaulting Partner shall
have no obligation to repay the Default Loan, but in the event the Defaulting
Partner does not repay the Default Loan, plus all accrued but unpaid interest
thereon, in full by the Default Date, the respective Capital Accounts shall be
adjusted to reflect the Additional Capital Contributions, including all such
unpaid interest, as follows: for Additional Capital Contributions relating to
the BLM Capital Accounts, the percentages attributable to the Contributing
Partner in Sections 5.1(b) and 5.2, shall be increased by such number of
percentage points as would provide a 22% internal rate of return to the
Contributing Partner.
4.3 Restrictions Relating to Capital; No Withdrawal. Except as otherwise
-----------------------------------------------
specifically provided in this Agreement or in the Act, no Partner shall have the
right to withdraw or reduce its Capital Contributions, to receive interest on
its Capital Contributions, to partition Partnership assets or to receive
property other than cash in return for its Capital Contributions.
4.4 Additional Partners. No additional Partners shall be admitted to the
-------------------
Partnership except with the consent of, and in accordance with the terms
(including the relative rights, duties, and interest of such additional
Partners), conditions and procedures agreed to by all Partners; provided
however, that any Partner may, without the consent of any other Partner or the
Management Committee, subdivide its Interest, through formation of a
partnership, corporation or other arrangement that would hold that Partner's
Interest so long as that Partner remains the owner of a portion of the Interest.
4.5 Right of First Offer. Each Partner grants to the other Partner a
--------------------
right of first offer with respect to any desired or proposed sale or transfer,
whether originated by that Partner or a third party (a "Disposition") of all or
part of the Interest of the Partner proposing to make the Disposition (the
"Disposing Partner"), upon the terms and conditions of this Section 4.5.
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(a) The right of first offer described in this Section 4.5 shall not
be effective unless the following conditions are satisfied:
(i) The Disposition shall involve the granting of a seat on the
Partnership's Management Committee, whether a present grant, a future right or
contingent opportunity of any kind to that seat; and
(ii) The Disposition shall become effective, with respect to any
unit or plant to be constructed, during the development stage of the unit or
plant constructed to provide electricity for the BLM Power Sales Contract up to
and including the time the unit or plant has been completed and goes on line for
commercial operations.
(b) Any Disposing Partner desiring to make a Disposition of all or
part of its Interest under conditions satisfying subsection (a) above shall send
a notice to the other Partner (the "Non-Disposing Partner") of the intended
Disposition, including the name of the proposed purchaser, a description of the
portion of the interest to be sold or transferred and the terms of the
Disposition. For a period of 30 days after receipt of the notice, the Non-
Disposing Partner shall have the right to purchase the portion of the notice.
The purchase right shall be exercised by notifying the Disposing Partner in
writing of the decision to exercise that right. If the Non-Disposing Partner
exercised the right to purchase within 30 days of receipt of the notice, the
Non-Disposing Partner must complete the purchase within 60 days of the notice of
intent to purchase. Failure to give notice of intent to purchase or to
consummate the purchase within the time limits described above shall allow the
Disposing Partner to proceed with the intended Disposition on the terms
described in the original notice; provided, however, that if the Disposing
Partner amends any material term of the sale or transfer, or changes the nature
or amount of the Interest to be sold or transferred, the Non-Disposing Partner
shall again have the right, as described in this Section 4.5, to purchase the
offered Interest on the amended terms and conditions.
(c) If the Non-Disposing Partner exercises its right to purchase the
Interest to be disposed of, the Disposing Partner shall cooperate in all
reasonable ways and in good faith with the Non-Disposing Partner to consummate
the sale of the Interest within the time period described in (b) above.
(d) No purchase by a Partner of any portion of an Interest under this
Section 4.5 shall in any way cause the purchasing Partner to increase its number
of seats, or the Disposing Partner to reduce its number of seats, on the
Management Committee.
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ARTICLE V
CURRENT DISTRIBUTIONS
5.1 BLM Cash Flow from Operations. Subject to Article XIII (that is,
-----------------------------
other than in liquidation of a Partner's Interest in the Partnership as provided
in Section 13.4(a)) and to Section 4.2, BLM Cash Flow from Operations shall be
applied or distributed on each Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or funds are
on deposit in the Escrow Account sufficient to reduce the Preferred Return to
zero, and the Distribution Condition will be satisfied for the Preferred Return
Year):
(i) until BLM Payout is achieved for all Partners, to distribute
3.81% to New CHIP, and 96.19% to New CHIP and CCH in proportion to the remaining
amounts necessary to be distributed to New CHIP and CCH in order to achieve BLM
Payout; and
(ii) after BLM Payout is achieved for all Partners, to distribute
48% to New CHIP and 52% to CCH;
provided, however, that all amounts distributable to New CHIP pursuant to this
Section 5.1(a) on a Distribution Date shall be deposited into the Escrow Account
until (a) the Joint Ventures have deposited therein an amount, in the aggregate,
equal to the Maximum Payment for the Preferred Return Year in which the
Distribution Date occurs, or (b) the Partnership has deposited therein during
the Preferred Return Year an amount, in the aggregate, equal to the Excess
Revenues for the Preferred Return Year; and
(b) after the Preferred Return has been reduced to zero, in the manner
provided in Section 5.1(a), without regard to the proviso in Section 5.1(a).
5.2 BLM Cash Flow from Capital Events. Subject to Article XIII (that is,
---------------------------------
other than in liquidation of a Partner's Interest in the Partnership as provided
in Section 13.4(a)) and to Section 4.2, BLM Cash Flow from Capital Events shall
be applied or distributed on each Distribution Date as follows:
(a) until the Preferred Return has been reduced to zero (or will be
reduced to zero through the application of funds on deposit in the Escrow
Account):
(i) 52% to CCH; and
(ii) 48% shall be deposited in the Escrow Account; and
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(b) after the Preferred Return has been reduced to zero, 48% to CHIP
and 52% to CCH.
5.3 Characterization of Escrow Account Deposits and Payments. For tax and
--------------------------------------------------------
accounting purposes, (a) all amounts deposited in the Escrow Account pursuant to
Section 5.1(a) and Section 5.2(a) shall be deemed to have been distributed by
the Partnership to New CHIP and to have been distributed to New CHIP, (b) New
CHIP shall be deemed to have directed the Partnership to make the deposits in
the Escrow Account on behalf of New CHIP, and (c) and any payments from the
Escrow Account shall be deemed to have been made by New CHIP.
ARTICLE VI
ALLOCATIONS
6.1 Allocation of Net Profit and Net Loss.
-------------------------------------
(a) For each fiscal year of the Partnership, the Net Profit or Net
Loss of the Partnership which is attributable to the BLM Project, and each item
of income or deduction entering into the computation thereof (exclusive of other
items of income, gain, loss, deduction or credit that are otherwise allocated
under this Article VI) shall be allocated to and among the Partners in the same
proportion that BLM Cash Flow from Operations is (or would have been had there
- ----------
been BLM Cash Flow from Operations) distributed to them under the provisions of
Section 5.1 hereof for such fiscal year.
6.2 Allocation of Net Gain and Net Loss from Capital Events. The net
-------------------------------------------------------
Book gain (book gain in excess of Book loss) of the Partnership from BLM Capital
Events and the net Book loss (Book loss in excess of Book gain) of the
Partnership from BLM Capital Events shall be allocated to and among the Partners
in the same manner that BLM Cash Flow from Capital Events is distributed under
the provisions of Section 5.2.
6.3 Allocation of Intangible Drilling and Development Costs. The Book
-------------------------------------------------------
deduction for intangible drilling and development costs of the Partnership shall
be allocated to and among the Partners as follows:
(i) Intangible drilling and development costs with respect to the
BLM Project paid from Additional Capital Contributions (which for the purposes
of this subsection shall be deemed to include any Default Loan under Section 4.2
which has not been paid in full) shall be allocated 98% to the Partner from whom
the Additional Capital Contributions (or the Default Loan) for the deductible
items were received, and 2% to the Partners in the manner described in Section
5.2.
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(ii) Intangible drilling and development costs for the BLM Project
paid from funds borrowed by the Partnership shall be allocated among the
Partners in the same manner that BLM Cash Flow from Capital Events is
distributed under the provisions of Section 5.2.
6.4 Allocation for Tax Purposes.
---------------------------
(a) All items of Partnership income, gain, loss, and deduction for
federal and state income tax purposes shall be allocated to and among the
Partners in the same manner that the corresponding Book items of the Partnership
are allocated in Sections 6.1 through 6.3, except as otherwise provided in
Regulation Section 1.704-1(b)(4)(i) and except that solely for Federal, local
and state income and franchise tax purposes and not for Book or Capital Account
purposes, income, gain, loss and deduction with respect to property properly
carried on the Partnership's books at a value other than its tax basis shall be
allocated, (i) in the case of property contributed in kind, in accordance with
the requirements of Code Section 704(c) and such Regulations as may be
promulgated thereunder from time to time, and (ii) in the case of other
property, in accordance with the principles provided in Regulations under Code
Section 704(b).
(b) In the event that the Partnership has taxable income that is
characterized as ordinary income by reason of the recapture provisions of the
Code, each Partner's allocation of taxable gain from the sale or exchange of
Partnership assets (to the extent possible) shall include a proportionate share
of the recapture income equal to the Partner's (and his predecessors in
interest's) share of prior cumulative depreciation, cost recovery or other
deductions with respect to the assets which gave rise to the recapture income
(but not to exceed the amount of gain allocated to each Partner).
6.5 Allocation in Event of Transfer of Partnership Interest during the
------------------------------------------------------------------
Year. The Capital Account of any Partner shall carry over to the transferee of
- ----
any Partner to the extent it relates to the transferred interest. Except to the
extent otherwise required by the Code and any Regulations thereunder, if a
Partnership interest or part thereof is transferred, the portion of each such
item allocable to such Partnership interest shall be allocated between the
transferor and transferee in proportion to the number of days in such fiscal
year the Partnership interest is held by said transferor and transferee (as
determined in accordance with Section 10.1), except that, if they so agree
between themselves and so notify the Managing Partner in writing within 30 days
of the transfer, extraordinary items, including capital gains and losses, may be
allocated to the person who held the Partnership interest on the date such item
was realized by the Partnership.
6.6 Regulatory and Curative Allocations.
-----------------------------------
(a) Notwithstanding the foregoing provisions of this Article VI, the
Partnership shall allocate items of book income and gain in a manner that
constitutes a
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"minimum gain chargeback" as described in Section 1.704-2 of the Treasury
Regulations and the term "minimum gain" shall have the meaning assigned to it
therein. Determinations of each Partner's share of minimum gain shall be made in
accordance with Section 1.704-2 of the Treasury Regulations. In addition,
"partner nonrecourse deductions" shall be allocated to the Partners bearing the
risk of loss with respect to such deductions in accordance with Section 1.704-2
of the Treasury Regulations.
(b) The Partners acknowledge and ratify the following modifications to
the provisions of this Article VI that were adopted pursuant to discussions
among the Partners and the Partnership accountants:
(i) For purposes of allocating income with respect to each year,
distributions are to be taken into account on the day in which they occur, and
the effective profit and loss percentages shall be determined as of each date
such distributions occur;
(ii) The following items are allocated in the ratios that apply
to Capital Events cash flow: depreciation, write-offs of plant and well capital
costs, fees paid to Southern California Edison related to transmission lines,
and alternative minimum tax adjustments and preferences associated with
property, plant and equipment; and
(iii) The initial capital contributions of the Partners are
determined by reference to the generally accepted accounting principle financial
statement figures for such capital contributions.
(c) As stated in Treasury Regulations Section 1.704-1(b)(4)(i), when
any property of the Partnership is reflected in the Capital Accounts of the
Partners and on the books of the Partnership at a book value that differs from
the adjusted tax basis of such property, then certain book items with respect to
such property will differ from certain tax items with respect to that property.
Since the Capital Accounts of the Partners are required to be adjusted solely
for allocation of the book items, the Partners' shares of the corresponding tax
items are not independently reflected by adjustments to the Capital Accounts.
These tax items must be shared among the Partners in a manner that takes account
of the variation between the adjusted tax basis of the applicable property and
its book value pursuant to or in the same manner as variations between the
adjusted tax basis and fair market value of property contributed to the
Partnership are taken into account in determining the Partners' share of tax
items under Code Section 704(c). In making allocations of tax items of the
Partnership, the Partnership shall comply with the foregoing principles.
(d) The Partners intend that the allocation of items of income, gain,
loss, deduction and credit pursuant to this Agreement result in Capital Account
balances that achieve the economic sharing provisions reflected in Article V, as
amended. Notwithstanding any other provisions contained herein, allocations of
income, gain, loss and deductions shall be applied and amended by the Managing
Partner as necessary to produce such result, including
20
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special allocations of gross income and gross deductions and amendment of prior
tax returns. This Section 6.6(d) shall control notwithstanding any reallocation
of income, loss or items thereof by the Internal Revenue Service or other taxing
authority.
ARTICLE VII
RIGHTS, DUTIES, LIABILITIES AND COMPENSATION
OF THE MANAGING PARTNER
7.1 General.
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(a) Except as otherwise provided in this Agreement, the Managing
Partner shall be responsible for the conduct of the business of the Partnership
and for Project operations. The Managing Partner shall devote to the business
affairs of the Partnership such time and effort as the Managing Partner may from
time to time deem necessary. Pursuant to that certain Amended and Restated
Operations and Maintenance Agreement, made and entered into by the Partnership,
COC and FPLE, dated February 25, 1999, and to that certain Amended and Restated
Field Operations Agreement, executed by COC and the Partnership, dated February
25, 1999 (FPLE and COC are individually and collectively referred to herein as
"Operator"), as either may be amended, COC shall act as Operator, provided,
however, that certain field and maintenance operations shall be performed by
FPLE.
(b) The Managing Partner and the Operator shall be subject to all
directives of the Management Committee with respect to the performance of their
respective duties hereunder, and shall be liable to the Partnership for all
damages, losses and expenses incurred by the Partnership as a result of
noncompliance with such directives.
7.2 General Rights and Powers of Managing Partner. Except as otherwise
---------------------------------------------
provided herein, including the provisions of Article VIII:
(a) The management and control of the day-to-day business and affairs
of the Partnership shall rest with the Managing Partner, which shall have such
rights and powers as are necessary, advisable or convenient to the discharge of
its duties under this Agreement and to the management of the business affairs of
the Partnership in furtherance of the purposes of the Partnership as set forth
in Article III.
(b) In furtherance of the purposes of the Partnership as set forth in
Article III of this Agreement, the Managing Partner is hereby granted the right,
power and authority to do on behalf of the Partnership all things which, in its
reasonable judgment, are necessary, property or desirable to carry out its
duties and responsibilities hereunder, including, but not limited to, the
following: from time to time to incur all reasonable expenditures pursuant to
the Budget; to employ and dismiss from employment any and all
21
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employees, agents, contractors, brokers, attorneys and accountants except for
the partnership's auditor; to create, by grant or otherwise, easements and
servitudes; to borrow money up to an aggregate principal amount of $100,000 at
any time outstanding; and to execute, acknowledge and deliver any and all
contracts, agreements or other instruments to effectuate any and all of the
foregoing. Subject to the direction of the Management Committee, the Managing
Partner shall be responsible for the following:
(i) maintain and protect the assets of the Partnership and the
interests of the Partners;
(ii) obtain such consultants, technicians, agents, and
contractors as it deems may be required for Project operations;
(iii) make all reports and disburse funds in accordance with the
Budget for all payments required under this Agreement with respect to Project
operations and under all agreements, permits, authorizations, and other rights
relating thereto;
(iv) submit the Budget, cost projections and any other budgets
for Project operations to the Management Committee;
(v) keep full and accurate records and accounts of the
transactions entered into by it on behalf of the Partnership;
(vi) do all such acts and things and conduct all such steps as
may reasonably be necessary if advisable in its judgment for the efficient and
economical conduct of Project operations; and
(vii) secure adequate and reasonable insurance (to the extent
possible and with the Partners and Partnership as named insureds) covering those
insurable risks with respect to the Partnership and Partnership operations that
can be insured at reasonable costs, including risk of personal injuries to or
deaths of employees or others, risks of fire, and all other risks ordinarily
insured against in similar operations, and adjust losses and claims pertaining
to or arising out of such insurance.
7.3 Expenses. The Partnership shall reimburse the following expenses of
--------
the Partnership incurred by either of the Partners limited to the amounts set
forth in the applicable Budget approved in accordance with Section 7.4:
(a) all organizational fees and expenses of the Partnership and of the
Partners;
(b) the actual costs of goods and materials used by or for the
Partnership by the Managing Partner, any subcontractors or the Partnership;
22
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(c) all employee time and costs and related overhead of the Managing
Partner attributable to the business of the Partnership;
(d) all operational expenses of the Partnership that may be paid by
the Managing Partner pursuant to the terms hereof, including, without
limitation, the following: obligations related to BLM Assigned Rights or Navy II
Assigned Rights; all costs of borrowed money paid to lenders; taxes and
assessments on Partnership assets and other taxes applicable to the Partnership;
legal, accounting, appraisal, audit and brokerage fees; fees and expenses paid
to independent consultants or insurance brokers; and
(e) all accounting, documentation, professional and reporting expenses
of the Partnership paid or to be paid to any person, including, without
limitation, the following: preparation and documentation of Partnership
accountings and audits; preparation and documentation of Partnership state and
federal tax returns; expenses of revising, amending, converting, modifying, or
terminating this Agreement or the Partnership; costs incurred in connection with
any litigation in which the Partnership is involved as well as any examination,
investigation or other proceedings conducted by any regulatory agency with
respect to the Partnership, including legal and accounting fees incurred in
connection therewith; costs of any computer equipment or services used for or by
the Partnership; and the costs of preparation and dissemination of informational
material and documentation relating to a potential sale by the Partnership of
Partnership Interests to third parties or relating to a potential acquisition,
sale, financing or refinancing of Partnership assets.
7.4 Budget; Mechanism for Reimbursements.
------------------------------------
(a) The Managing Partner shall prepare the Budget for the Partnership,
which shall include a capital expenditure budget and a budget for Partnership
operations for each quarter, which is to be presented to the Management
Committee for approval no later than forty-five (45) days prior to the beginning
of the applicable quarter. Once the Budget has been approved by the Management
Committee, the Managing Partner may pay all Partnership expenses, reimburse
itself for expenditures permitted by Section 7.3, and otherwise apply all
available Partnership funds in accordance with the approved Budget.
(b) Subject to the approval of the Management Committee, the
reasonable costs incurred by the Partners in connection with matters to be
considered by the Management Committee as well as any other activities of the
Partners assigned to such Partners by the Management Committee shall be
reimbursed by the Partnership in accordance with the amounts set forth in the
applicable Budget approved in accordance with Section 7.4(a).
7.5 Third Party Reliance. Any person dealing with the Partnership as to
--------------------
any matter with respect to which the Managing Partner is granted authority
hereunder may rely solely on written advice from the Managing Partner as to any
matter relating to this Agreement, as to
23
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compliance herewith and as to the authority of the Managing Partner to act on
behalf of the Partnership, and as between the Partnership or the Managing
Partner, on the one hand, and such other person, on the other hand, the facts
stated in such written advice from the Managing Partner will be conclusive and
binding on the Partnership and the Managing Partner.
7.6 Justification of Expenses. In connection with the reimbursement or
-------------------------
payment by the Partnership of any expenses under this Agreement to any Partner,
each Partner shall have the right to receive from the Partner claiming
reimbursement or payments such supporting documentation as may be reasonably
requested to justify such reimbursement or payments.
ARTICLE VIII
MANAGEMENT OF PARTNERSHIP
8.1 Management Committee. Subject to requirements of the Act or other
--------------------
applicable law the business operations of the Partnership shall be overseen by a
Management Committee, consisting of two delegates appointed by New CHIP and two
delegates appointed by CCH. New CHIP and CCH shall each be fully empowered to
substitute for its own delegates and to appoint alternates. The decision of the
Management Committee shall be required for all actions set forth at Section 8.4.
8.2 Meetings. The Partnership shall hold Meetings to transact all
--------
Partnership business for which a meeting or a vote of the Partners is required
by the Act. Each Partner shall send two delegates to each Meeting. Each Partner
may substitute or change delegates at will, and shall notify the other Partner
of the names of such delegates prior to each Meeting.
8.3 Procedures. Management Committee Meetings and Partnership Meetings
----------
shall occur and be conducted pursuant to the following procedures:
(a) The Partnership and the Management Committee shall hold a Meeting
on the second Tuesday of January, April, July and October of each year and on
such other dates as shall be called by a Partner on written notice of not less
than fifteen (15) business days given by the calling party to all Partners which
notice shall be accompanied by an agenda and supporting documentation
describing, in reasonable detail, the issues to be presented to the Management
Committee for voting. Meetings shall be held at the Managing Partner's office
and begin at 10:00 A.M. unless another time or place is agreed to.
(b) A quorum of three delegates (including alternates to delegates not
present) must be present to convene a Meeting and/or vote on Partnership or
Management Committee matters.
24
<PAGE>
(c) All votes on Partnership or Management Committee action shall
require a favorable vote of at least a majority of the delegates comprising the
quorum present at the Meeting; provided, however, that said favorable vote must
be composed of at least one favorable vote by a delegate representing New CHIP
and one favorable vote by a delegate representing CCH.
(d) Action by the Partnership and the Management Committee may be
taken at any time without a meeting upon the written consent of at least three
delegates. For the purposes of this provision, written consent shall be deemed
given by a delegate if said delegate does not make an objection to the action
proposed in the form of written consent sent to the delegates within 15 days
after the actual receipt of such form of written consent by such delegate.
(e) The Partnership and the Management Committee may also take action
by vote of at least three delegates given by the telephone which vote shall be
subsequently confirmed in writing to all delegates. The notice provision in
Section 8.3(a) shall apply also to such vote by telephone, provided, however,
that vote may be taken without notice, if in the reasonable opinion of the three
delegates so voting, there exists an emergency situation precluding such advance
notice, and that all reasonable efforts have been made to notify all Partners of
the emergency and the vote.
(f) Minutes shall be prepared for all Meetings, and shall be approved
by the Partners or the Management Committee, as applicable, prior to being
entered into the permanent minute book maintained by the Managing Partner for
the Partnership.
8.4 Limitations on Authority of Managing Partner. The Managing Partner
--------------------------------------------
(including the Managing Partner acting in his capacity as Operator) shall have
no authority to do any act prohibited by law, nor shall the Managing Partner,
without the consent of the Management Committee, have any authority to:
(a) permit any creditor who makes a non-recourse loan to the
Partnership to take, as a condition of making such loan, any direct or indirect
interest in the profits, capital, assets or property of the Partnership other
than as a secured creditor;
(b) sell or lease the Partnership's rights in commercial geothermal
wells, power plants and other substantial assets owned by the Partnership;
(c) make or amend contracts for the sale of electricity;
(d) terminate, liquidate and wind up the Partnership, except upon the
occurrence of an event which, under the Act, dissolves or terminates the
Partnership;
25
<PAGE>
(e) approve and establish procedures and ongoing review of all budgets
and the budget process, including each Budget;
(f) change the Partnership's auditor;
(g) create, incur, or assume any indebtedness for borrowed money other
than in the ordinary course of Partnership business;
(h) obtain refinancing or replacements of any mortgages or other
security instruments related in any way to any Partnership property, or repay in
whole or in part, refinance, recast, modify, consolidate or extend any of the
terms of any indebtedness owed by the Partnership or affecting all or any
portion of any Partnership property;
(i) modify, amend or waive any provision of any material agreement to
which the Partnership is a party;
(j) create, incur, or assume any indebtedness in aggregate principal
amount at any time outstanding greater than $100,000;
(k) acquire, amend or terminate any geothermal leases;
(l) engage and discharge outside consultants, construction
contractors, engineers or similar entities or professionals, including contracts
with third party Project operators in connection with work to be performed by or
for the benefit of the Partnership in instances where the estimated or incurred
cost of said work exceeds $1,000,000; excluding, however, contracts for drilling
of wells and all related supplies and equipment, provided the estimated costs of
such contracts do not exceed the amounts budgeted for such items in an approved
Budget; further provided that any contract between the Partnership and the
Operator, the Managing Partner or any of their affiliates must have the approval
of the Management Committee.
(m) all other functions for which Partnership approval is required by
applicable law or for which Management Committee approval is required by this
Agreement; or
(n) (i) do any act in contravention of this Agreement or not in
furtherance of the purposes of the Partnership set forth in Article III; (ii) do
any act which would make it impossible to carry on the ordinary business of the
Partnership; (iii) confess a judgment against the Partnership; (iv) possess
Partnership property or assign rights in specific Partnership property, for
other than a Partnership purpose; (v) change or reorganize the Partnership into
any other legal form; or (vi) admit a person as a Partner, except as provided in
this Agreement.
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<PAGE>
Notwithstanding anything to the contrary set forth herein, the Managing
Partner shall have the authority, without the approval of the Management
Committee, to administer the definitive documents entered into by the
Partnership in accordance with and as generally described in the Offering
Circular, including any amendments, waivers, extensions, indulgences, minor
adjustments, or other loan administration matters with respect to such documents
(other than amendments materially affecting the Partnership or any Partner).
ARTICLE IX
REPRESENTATIONS AND COVENANTS OF PARTNERS
9.1 Representation of Partners. Each Partner represents to each other
--------------------------
Partner that it is an entity duly organized and validly existing under the laws
of its jurisdiction, and qualified to do business in the State of California,
that all action required by such Partner to authorize that Partner to enter into
this Agreement has been taken, and that this Agreement is a binding agreement of
that Partner, enforceable in accordance with its terms.
9.2 Covenants of Partners. Each Partner covenants that it will not
---------------------
engage in any business or in any other activities other than performing its
obligations under this Agreement to the extent such business or other activities
are limited by agreements between the Partnership and lenders providing
financing to the Partnership.
ARTICLE X
ASSIGNMENTS OR TRANSFERS OF INTERESTS
10.1 Assignments. Subject to compliance with applicable federal and state
-----------
securities laws, and subject to Sections 4.4 and 4.5, a Partner may transfer all
or a portion of his Interest in the Partnership, by an executed and acknowledged
written instrument, only with the consent of the Management Committee. Subject
to compliance with applicable federal and state securities laws, assignments
will be recognized by the Partnership only effective the last day of the
calendar month following the receipt by the Partnership of written notice of the
assignment. The Partnership may charge the assigning or transferring Partner
and any Partner requesting a change of name, type of ownership, etc., a fee not
to exceed the expenses, including actual legal expenses, incurred in effecting
the assignment or transfer of his interest in the Partnership or other change in
the records of the Partnership.
10.2 Substituted Partners. No assignee of the whole or any portion of a
--------------------
Partners' Interest in the Partnership shall have the right to become a
substituted Partner in the place of his assignor unless all of the following
conditions are satisfied:
27
<PAGE>
(a) the fully executed and acknowledged written instrument of
assignment that has been filed with the Partnership sets forth the intention of
the assignor that the assignee become a substituted Partner in his place;
(b) the assignor and assignee execute and acknowledge such other
instruments as the Management Committee may deem necessary or desirable to
effect such admission, including the written acceptance and adoption by the
assignee of the provisions of this Agreement and his execution, acknowledgment,
and delivery to the Management Committee of a Power of Attorney, the form and
content of which shall be provided by the Management Committee;
(c) any transfer fee and legal expenses, if any, referred to in
paragraph (a) above required to be paid shall have been paid;
(d) the transfer shall not be in violation of any applicable federal
or state securities laws, including the Securities Act of 1933, as amended, nor
shall it cause the termination of the Partnership under Section 708(b) of the
Code, it being understood and agreed that the Management Committee may require
as a condition to such transfer that the Partnership be furnished with an
appropriate opinion of counsel to the foregoing effect, which counsel and
opinion shall be satisfactory to the Management Committee; and
(e) the Management Committee has consented to the assignment (which
consent may be granted or withheld at the sole discretion of the Management
Committee).
10.3 Management Committee Option. The Management Committee may elect to
---------------------------
treat an assignee who has not become a substituted Partner as a substituted
Partner in the place of his assignor should it deem, in its sole discretion,
that such treatment is in the best interest of the Partnership for any of its
purposes or for any of the purposes of this Agreement.
10.4 Amendment of Agreement. The Managing Partner will be required to
----------------------
prepare an amendment to this Agreement for signature by the Partners to reflect
the substitution of Partners. Until this Agreement is so amended, an assignee
shall not become a substituted Partner.
10.5 Insolvency. Upon the bankruptcy, insolvency, dissolution, or other
----------
cessation to exist as a legal entity of a Partner not an individual, the
authorized representative of such entity shall have all the rights of a Partner
for the purpose of effecting the orderly winding up and disposition of the
business of such entity and such power as such entity possessed to constitute a
successor as an assignee of its interest in the Partnership and to join with
such assignee in making application to substitute such assignee as a Partner.
10.6 Special Restrictions Relating to Non-U.S. Persons. Each transferee of
-------------------------------------------------
an Interest shall certify whether or not such transferee is a U.S. person. Each
Partner shall notify
28
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the Managing Partner if it becomes a non-U.S. person within 30 days of such
change. Prior to a disposition of a "United States Real Property Interest," as
defined in Code Section 897, or a distribution pursuant to a disposition of a
"United States Real Property Interest," each Partner shall, if requested to do
so by the Managing Partner, certify as to its U.S. person status.
10.7 Amendments in Respect to Transfers; Admission of Partners. The
---------------------------------------------------------
Managing Partner, at the discretion of the Management Committee, shall promptly
amend any Partnership document listing the Partners from time to time to reflect
the admission, substitution or withdrawal of Partners. No such admission,
substitution or withdrawal shall be effective until all appropriate Partnership
documents are so amended.
ARTICLE XI
LOANS TO THE PARTNERSHIP
11.1 Authority to Borrow. Subject to the approval of the Management
-------------------
Committee and to the limitations elsewhere provided in this Agreement, the
Partnership may from time to time borrow such amounts from such persons
(including the Managing Partner or any other Partner and its affiliates) on such
security and payable on such terms as the Managing Partner may determine.
11.2 Loans from Partners. If a Partner shall, with the prior consent of
-------------------
the Management Committee, make any loan or loans to the Partnership or advance
money on its behalf, the amount of any such loan or advance shall not increase
the Capital Account of the lending Partner or entitle such lending Partner to
any increase in his share of the distributions of the Partnership or result in
his having any greater share of Partnership allocations of Net Profit and Net
Loss. The amount of any such loan or advance shall be a debt due from the
Partnership to such lending Partner, repayable upon such terms and conditions
and bearing interest at such rates as shall be mutually agreed upon by the
lending Partner and the Management Committee, and such loan or advance may,
subject to approval of the Management Committee, be secured by a mortgage, deed
of trust, pledge, security interest or other lien in or on any, all or
substantially all of the properties and other assets of the Partnership.
ARTICLE XII
BOOKS, RECORDS AND REPORTS
12.1 Books. The Partnership, at its expense, shall maintain books and
-----
records for the Partnership at the Managing Partner's designated office, and all
Partners shall have the right to inspect and examine such books and records, and
to copy them (at their own expense) during regular business hours.
29
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12.2 Reports. The Partnership shall cause to be prepared and delivered
-------
to the Partners, at its expense, the following reports (all unaudited reports to
be certified by the Chief Financial Officer of the Managing Partner):
(a) Within 60 days after the end of the first three quarterly periods
of the Partnership's fiscal year, a quarterly report containing the following:
(i) a balance sheet, which may be unaudited;
(ii) a statement of income for the three-month period then
ended, and for the year to date at such quarter end, which may be unaudited;
(iii) a statement of changes in cash flow for the three-month
period then ended, and for the year to date at such quarter end, which may be
unaudited;
(iv) other pertinent information regarding the Partnership and
its activities during the three-month period covered by the report; and
(v) a statement setting forth in reasonable detail the services
rendered by the Managing Partner to the Partnership and the amounts charged for
those services.
(b) Within 75 days after the end of each fiscal year of the
Partnership, all information concerning the Partnership reasonably necessary for
the preparation of the Partners' federal and state income tax returns.
(c) Within 90 days after the end of each fiscal year of the
Partnership, an annual report containing (i) a balance sheet as of the end of
its fiscal year and statements of income, Partners' equity and changes in
financial position, for the year then ended, all of which shall be prepared in
accordance with generally accepted accounting principles consistently applied
and accompanied by an auditor's report containing to the extent available an
unqualified opinion of an independent certified public accountant; and (ii) a
report of the activities of the Partnership during the period covered by the
report.
(d) Copies of any documents delivered to any institution providing
financing to the Partnership pursuant to the requirements of any Partnership
loan documents.
12.3 Accounting and Tax Decisions. Except as otherwise provided in this
----------------------------
Agreement all decisions as to accounting and tax matters shall be made by the
Managing Partner, and as directed by the Management Committee.
30
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12.4 Income Tax Election and Proceedings.
-----------------------------------
(a) The Management Committee shall direct the Managing Partner to make
such elections under the tax laws of the United States, the several States and
other relevant jurisdictions as to the treatment of the Partnership's items of
income, gain, loss, deduction and credit and as to all other relevant matters as
it reasonably believes necessary, appropriate or desirable.
(b) In the event the Partnership is subject to administrative or
judicial proceedings for the assessment and collection of deficiencies for
federal, state or local taxes or for the refund of overpayments of federal,
state or local taxes arising out of a Partner's distributive share of the tax
items of the Partnership, the Managing Partner shall act as, and shall have the
power and duties assigned to, the "tax matters partner" under Code Sections
6221-6232 and the Regulations thereunder. The Partners agree to perform all
acts necessary under Code Section 6231 and the Regulations thereunder to
designate the Managing Partner as the "tax matters partner."
(c) No Partner shall, on such Partner's federal or state income tax
return, treat any "partnership item" (as defined in Code Section 6231(a)(3) and
the Regulations thereunder) in a manner which is inconsistent with the treatment
of such "partnership item" on the Partnership's return without first submitting
its proposed treatment to the other Partner for its advance review.
12.5 Bank Accounts. The Managing Partner may designate from time to time
-------------
those persons authorized to execute checks and other items on the Partnership
bank accounts. The funds of the Partnership shall not be commingled with the
funds of any other person. The Managing Partner shall have fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing Partner's possession or control, and
it shall not employ, or take actions to permit another to employ, such funds or
assets in any manner except as provided in this Agreement.
ARTICLE XIII
DISSOLUTION AND TERMINATION OF THE PARTNERSHIP
AND THE LIQUIDATION OF A PARTNER'S
INTEREST IN THE PARTNERSHIP
13.1 Dissolution. Only the happening of any one of the following events
-----------
shall dissolve the Partnership:
(a) the expiration of the term of the Partnership;
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(b) the expiration of 60 days after the Partnership's election to
dissolve the Partnership (provided that no Partner shall, without such approvals
as may be required from lenders providing financing to the Partnership in
accordance with the relevant loan or financing agreements, seek the dissolution
of the Partnership during the term of any such agreements);
(c) the entry of a decree of judicial dissolution of the Partnership
pursuant to the Act; or
(d) the occurrence of any event that would cause the dissolution of
the Partnership under the Act or that would make it unlawful for the business of
the Partnership to be continued.
13.2 Distributions in Liquidation of the Partnership and in Liquidation
------------------------------------------------------------------
of a Partner's Interest in the Partnership.
- ------------------------------------------
(a) In the event of a distribution in connection with the liquidation
of the Partnership, the occurrence of which is described in Section 13.4(b), the
Partnership shall apply and distribute the proceeds from the liquidation of the
assets of the Partnership and collection of the receivables of the Partnership,
together with assets distributed in kind, to the extent sufficient therefor, in
the following order of priority:
(i) first, to the payment and discharge of all liabilities,
obligations and debts of the Partnership and the expenses of liquidation, paid
in the order then required by California law;
(ii) second, to the creation and setting up of any reserves
which the Management Committee may deem necessary, appropriate or desirable for
any future, contingent or unforeseen liabilities, obligations or debts of the
Partnership which are not yet payable or have not yet been paid. The Partnership
may pay, but is not obligated to pay, such reserves to an independent escrow
holder designated by the Management Committee, to be held by it for the purpose
of disbursing such reserves in payment of any of the aforementioned liabilities,
obligations and debts and, at the expiration of such period as the Management
Committee shall deem necessary, advisable or desirable, to distribute the
balance thereafter remaining in the manner hereinafter provided;
(iii) third, to the payment and discharge of all of the
liabilities, obligations and debts of the Partnership owing to Partners, but if
the amount available for payment is insufficient, then pro rata in accordance
with the amount of those liabilities, obligations and debts; and
(iv) fourth, to the Partners with positive Capital Accounts, in
accordance with their respective Capital Account after taking into account all
Capital Account
32
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adjustments for the Partnership taxable year during which such liquidation
occurs (other than those made pursuant to this Section 13.2, or Section 13.3).
(b) Except as otherwise provided in Regulation Section 1.704-
1(b)(2)(ii)(b), a distribution to a Partner in liquidation of such Partner's
interest in the Partnership (as described in Section 13.4(c), but other than in
liquidation of the Partnership (the occurrence of which is described in Section
13.4(b), shall be in an amount equal to each Partner's Capital Account after
taking into account all Capital Account adjustments for the Partnership taxable
year during which such liquidation occurs (other than those made pursuant to
this Section 13.2 or Section 13.3).
(c) For purposes of this Section 13.2, the Partnership taxable year
shall be determined without regard to Code Section 706(c)(2)(A).
13.3 Deficit Capital Account. Notwithstanding any other provision of
-----------------------
this Agreement to the contrary, upon liquidation of a Partner's interest in the
Partnership (whether or not in connection with the liquidation of the
Partnership), after all Capital Account adjustments for the taxable year during
which such liquidation occurs (other than those occurring as a result of any
contributions made pursuant to this Section 13.3), if such Partner has a
negative balance in its Capital Account, such Partner shall be obligated to pay
to the Partnership on or before the end of the taxable year in which such
liquidation occurs (or, if later, within ninety (90) days after the date of such
liquidation) an amount in cash equal to the difference between its negative
Capital Account and zero.
13.4 Liquidation of the Partnership and Liquidation of a Partner's
-------------------------------------------------------------
Interest in the Partnership.
- ---------------------------
(a) For purposes of Sections 1.22, 5.1, 5.2 and 13.3, a liquidation
of a Partner's Interest in the Partnership occurs upon the earlier of (i) the
date upon which there is a liquidation of the Partnership or (ii) the date upon
which there is a liquidation of the Partner's Interest in the Partnership.
(b) For purposes of Section 13.4(a) and Sections 13.2(a) and 13.3,
the liquidation of the Partnership occurs upon the earlier of (i) the date upon
which the Partnership is terminated under Code Section 708(b)(1), or (ii) the
date upon which the Partnership ceases to be a going concern (even though it may
continue in existence for the purpose of winding up its affairs, paying its
debts, and distributing any remaining balance to its Partners).
(c) For purposes of Sections 13.4(a) and 13.2(b), the liquidation of
a Partner's Interest in the Partnership means the termination of a Partner's
entire Interest in the Partnership by means of a distribution, or a series of
distributions, to the Partner by the Partnership. A series of distributions
will come within the meaning of this term whether they are made in one year or
in more than one year. Where a Partner's Interest is to be liquidated
33
<PAGE>
by a series of distributions, the Interest will not be considered as liquidated
until the final distribution has been made.
(d) The liquidation of a Partner's Interest in the Partnership, the
occurrence of which is described in Section 13.4(a) will not be delayed after
the Partnership's primary business activities have been terminated for a
principal purpose of deferring any distribution pursuant to Section 13.2(a)(iv),
or deferring a Partner's obligation under Section 13.3.
13.5 Time of Liquidation. Subject to Section 13.4(d) a reasonable time
-------------------
shall be allowed for the orderly liquidation of the assets of the Partnership
and the discharge of liabilities to creditors so as to enable the Partnership to
minimize to the extent it deems practicable, advisable or desirable the normal
losses attendant upon the liquidation.
13.6 Liquidation Statement. Each of the Partners shall be furnished
---------------------
with a statement prepared by the Partnership, which shall set forth the assets
and liabilities of the Partnership as of the date of complete liquidation. Upon
the Partnership complying with the foregoing distribution plan, the Partners
shall cease to be such and the Managing Partner may execute, acknowledge and
cause to be filed and recorded a certificate of cancellation of the Partnership
or other appropriate documents evidencing its dissolution and winding up.
ARTICLE XIV
LIMITATION OF LIABILITY OF MANAGING PARTNER AND
INDEMNIFICATION OF THE MANAGING PARTNER AND OTHERS
14.1 Limitation on Liability of Managing Partner. None of the Managing
-------------------------------------------
Partner in its capacity as such, or its officers, directors, shareholders,
employees or agents will be liable to the Partnership or the Partners for any
expense, loss or liability suffered by the Partnership or the Partners in
connection with the Partnership or its activities; provided that, in the event
such expense, loss or liability arose out of any action or inaction of a
Managing Partner or its affiliates or such other persons, as the case may be,
the foregoing shall only apply if (i) such course of conduct did not constitute
gross negligence, acts of bad faith or willful misconduct, and (ii) the Managing
Partner, its affiliate or such other person, as the case may be, had previously
determined in good faith that such course of conduct was in the best interests
of the Partnership.
14.2 Indemnification of the Managing Partner.
---------------------------------------
(a) The Partnership shall indemnify and hold harmless the Managing
Partner, and its officers, directors, shareholders, employees and agents
(individually, an "Indemnitee") from and against any and all losses, claims,
demands, costs, damages, liabilities, joint and several, expenses of any nature
(including attorneys' fees and
34
<PAGE>
disbursements), judgments, fines, settlements and other amounts arising from any
and all claims, demands, actions, suits or proceedings, civil, criminal,
administrative or investigative, in which the Indemnitee may be involved, or
threatened to be involved, as a party or otherwise arising out of or incidental
to the business of the Partnership, including without limitation liabilities
under the federal and state securities laws, regardless of whether the
Indemnitee continues to be the Managing Partner, or an officer, director,
shareholder, employee or agent of the Managing Partner at the time any such
liability or expense is paid, if the Indemnitee's conduct did not constitute
actual fraud, willful misconduct or gross negligence and if the Indemnitee acted
in a manner it reasonably believed to be in the best interests of the
Partnership. The termination of any action, suit or proceeding by settlement or
upon a plea of nolo contendere, or its equivalent, shall not, in and of itself,
create a presumption or otherwise constitute evidence that the Indemnitee acted
in a manner contrary to that specified above.
(b) Reasonable expenses incurred by an Indemnitee in defending any
claim, demand, action, suit or proceeding subject to this Section 14.2 shall,
from time to time, be advanced by the Partnership prior to the final disposition
of such claim, demand, action, suit or proceeding upon receipt by the
Partnership of an undertaking by or on behalf of the Indemnitee to repay such
amount if it shall be determined that such person is not entitled to, be
indemnified as authorized in this Section 14.2.
(c) The indemnification provided by this Section 14.2 shall be in
addition to any other rights to which those indemnified may be entitled under
any agreement, vote of the Partners, as a matter of law or equity or otherwise,
both as to action in the Indemnitee's capacity as Managing Partner, as an
affiliate or as an officer, director, employee or agent of a Managing Partner or
an affiliate and as to any action in another capacity, and shall continue as to
an Indemnitee who has ceased to serve in such capacity and shall inure to the
benefit of the heirs, successors, assigns and administrators of the Indemnitee.
(d) The Partnership may purchase and maintain insurance, at the
Partnership's expense, on behalf of the Managing Partner and such other persons
as the Management Committee shall determine, against any liability that may be
asserted against or expense that may be incurred by such person in connection
with the activities of the Partnership and/or the Managing Partner's acts or
omissions as Managing Partner of the Partnership regardless of whether the
Partnership would have the power to indemnify such person against such liability
under the provisions of this Agreement.
(e) Any indemnification hereunder shall be satisfied solely out of
the assets of the Partnership. No Partner shall be subject to personal
liability by reason of these indemnification provisions.
(f) An Indemnitee shall not be denied indemnification in whole or in
part under this Section 14.2 by reason of the fact that the Indemnitee had an
interest in the
35
<PAGE>
transaction with respect to which the indemnification applies if the transaction
was otherwise permitted by the terms of this Agreement.
(g) The provisions of this Section 14.2 are for the benefit of the
Indemnitees, their heirs and personal representatives, and shall not be deemed
to create any rights for the benefit of any other persons.
14.3 Management Committee Indemnification. The Partnership shall
------------------------------------
indemnify and save harmless the delegates to the Management Committee, including
the alternates, against all actions, claims, demands, costs and liabilities
arising out of the acts (or failure to act) of any such person in good faith
within the scope of their authority in the course of the Partnership's business,
and such persons shall not be liable for any obligations, liabilities or
commitments incurred by or on behalf of the Partnership as a result of any such
acts or failure to act, provided that the foregoing shall not entitle a member
to indemnification for gross negligence or willful misconduct.
14.4 Survival of Rights. The rights of the Managing Partner, and its
------------------
respective officers, directors, shareholders, employees or agents under this
Article XIV shall survive the termination of the Managing Partner's status as a
Partner of the Partnership.
ARTICLE XV
GENERAL PROVISIONS
15.1 Arbitration. Any controversy or claim arising out of or relating to
-----------
this Agreement, or the breach thereof, which cannot be settled by agreement of
the Partners, shall be settled by arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association and judgment upon the
award rendered thereunder may be entered in any court having jurisdiction
thereof.
15.2 Notices.
-------
(a) Except as otherwise provided herein, any notice, distribution,
offer, report or other communication that is to be given to any Partner in
connection with the Partnership or this Agreement shall be in writing and shall
be sent in person by first-class mail, by telecopy, or by nationally recognized
overnight courier services to the address set forth below or to such other
address as a Partner may notify the Management Committee in writing, and shall
be deemed delivered upon receipt.
New CHIP: New CHIP, LLC
c/o Caithness Power, L.L.C.
1114 Avenue of the Americas
36
<PAGE>
New York, New York 10036-7790
Attention: General Counsel
Telefacsimile: (212) 921-9239
CCH: Caithness Coso Holdings, L.L.C.
c/o Caithness Corporation
1114 Avenue of the Americas
New York, New York 10036-7790
Attention: General Counsel
Telefacsimile: (212) 921-9239
(b) Copies of any notices provided to any Partner in connection with
any loan documents or other financing documents (or any documents relating
thereto) shall be forwarded to each other Partner promptly upon receipt.
15.3 Survival of Rights. This Agreement shall be binding upon, and, as to
------------------
permitted or accepted successors, transferees and assigns, inure to the benefit
of the Partners and the Partnership and their respective heirs, legatees, legal
representatives, successors, transferees and assigns, in all cases whether by
the laws of descent and distribution, merger, reverse merger, consolidation,
sale of assets, other sale, operation of law or otherwise.
15.4 Construction. The language in all parts of this Agreement shall be
------------
in all cases construed simply according to its fair meaning and not strictly for
or against the Partners or the Managing Partner.
15.5 Section Headings. The captions of the Articles or Sections in this
----------------
Agreement are for convenience only and in no way define, limit, extend or
describe the scope or intent of any of the provisions hereof, shall not be
deemed part of this Agreement and shall not be used in construing or
interpreting this Agreement.
15.6 Agreement in Counterparts. This Agreement and any amendments hereto
-------------------------
may be executed in multiple counterparts, each of which shall be deemed an
original agreement and all of which shall constitute one and the same agreement,
notwithstanding the fact that all parties are not signatories to the original or
the same counterpart. For purposes of recording this instrument, if required,
multiple signature pages and acknowledgment pages may be attached to each
counterpart; the signature pages and the acknowledgment pages pertaining thereto
may be detached from the counterpart, when executed, and attached to another
counterpart, which other counterpart may thereafter be recorded.
15.7 Governing Law. This Agreement shall be construed according to the
-------------
internal laws, but not the laws pertaining to choice or conflict of laws, of the
State of California.
37
<PAGE>
15.8 Additional Documents. Each Partner, upon the request of the
--------------------
Management Committee, agrees to perform all further acts and execute,
acknowledge and deliver all further documents which may be reasonably necessary,
appropriate or desirable to carry out the provisions of this Agreement,
including but not limited to acknowledging before a notary public any signature
heretofore or hereafter made by a Partner.
15.9 Severability. Should any portion or provision of this Agreement be
------------
declared illegal, invalid or unenforceable in any jurisdiction, then such
portion or provision shall be deemed to be severable from this Agreement as to
such jurisdiction (but, to the extent permitted by law, not elsewhere) and in
any event such illegality, invalidity or unenforceability shall not affect the
remainder hereof.
15.10 Pronouns and Plurals. Whenever the context may require, any pronoun
--------------------
used in this Agreement shall include the corresponding masculine, feminine or
neuter forms, and the singular form of nouns, pronouns and verbs shall include
the plural and vice versa.
15.11 Third Party Beneficiaries. There are no third party beneficiaries
-------------------------
of this Agreement.
15.12 Partition. The Partners agree that any assets the Partnership may
---------
at any time have may not be suitable for partition. Each Partner hereby
irrevocably waives any and all rights that he may have to maintain any action
for partition of any assets the Partnership may at any time have.
15.13 Security Interest and Right of Set-Off. As security for any
--------------------------------------
withholding tax or other liability or obligation to which the Partnership may be
subject as a result of any act or status of any Partner or to which the
Partnership becomes subject with respect to the Interests of any Partner, the
Partnership shall have (and each Partner hereby grants to the Partnership) a
security interest in all Cash Flow from Operations or Cash Flow from Capital
Events distributable to such Partner to the extent of the amount of such
withholding tax or other liability or obligation. The Partnership shall have a
right to set-off against any such cash distributable in the amount of such
withholding tax or other liability or obligation.
15.14 Entire Agreement. This Agreement delivered by the Partners
----------------
constitutes the entire agreement of the Partners with respect to, and supersedes
all prior written and prior and contemporaneous oral agreements, understandings
and negotiations with respect to the subject matter hereof.
15.15 Waiver. No failure by any party to insist upon the strict
------
performance of any covenant, duty, agreement or condition of this Agreement or
to exercise any right or remedy consequent upon a breach thereof shall
constitute a waiver of any such breach or any other covenant, duty, agreement or
condition.
38
<PAGE>
15.16 Attorneys' Fees. In the event of any litigation or arbitration
---------------
between the parties hereto with respect to the subject matter hereof, the
unsuccessful party to such litigation or arbitration shall pay to the successful
party all costs and expenses, including, without limitation, reasonable
attorneys' fees and expenses, incurred therein by the successful party, all of
which shall be included in and as a part of the judgment or decision rendered in
such litigation or arbitration.
END OF PAGE
39
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of
the date first set forth above.
By: New CHIP Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ Christopher T. McCallion
---------------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness Coso Holdings, LLC,
a Delaware limited liability company,
its General Partner
By: Caithness CEA Geothermal, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing General Partner
By: /s/ Christopher T. McCallion
--------------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness BLM Group, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Geothermal 1980 Ltd., L.P.
a Delaware limited partnership
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
--------------------------------------
Christopher T. McCallion
Executive Vice President
40
<PAGE>
By: Caithness Geothermal 1980 Ltd., Special Group I, L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------------
Christopher T. McCallion
Executive Vice President
By: West Coast Geothermal Ltd., L.P.,
a Delaware limited partnership
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------------
Christopher T. McCallion
Executive Vice President
By: Pacific Geothermal Ltd., L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------------
Christopher T. McCallion
Executive Vice President
41
<PAGE>
By: Mt. Whitney Geothermal Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------------
Christopher T. McCallion
Executive Vice President
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
---------------------------------
Christopher T. McCallion
Executive Vice President
By: Dominion Energy, Inc.,
a Virginia corporation,
its Limited Partner
By: /s/ James W. Braswell
---------------------------------
Name: James W. Braswell
----------------------------
Title: Vice President
--------------------------
42
<PAGE>
EXHIBIT A
BLM PROJECT AREA
The BLM Project Area shall consist of the area under the BLM lease, defined
as follows:
T. 22 S., R 39 E., Mt. Diablo Meridian
Section 19, Lots 1-4, inclusive, E 1/2, E 1/2, W 1/2
Section 20,
Section 29,
Section 30, Lots 1-4, inclusive E 1/2, E 1/2, W 1/2
43
<PAGE>
EXHIBIT B
NAVY II PROJECT AREA
Navy 2 Lands
3,184 Acres
T. 21 S., R, 39 E., MDM
Sec. 33, SE4SE4
Sec. 34, W2
T. 22 S., R. 39 E., MDM
Sec. 3, W2
Sec. 10, W2
Sec. 15, W2
Sec. 16, All
Sec. 17, S2N2, S2
Sec. 18, SE4
T. 22 S., R. 38 E., MDM
Sec. 16, All
Also the following lands pledged to Navy I but subject to clawback:
T. 22 S., R. 39 E., MDM
Sec. 17, N2N2
Sec. 18, NE4
44
<PAGE>
EXHIBIT C
TRANSMISSION LINE DESCRIPTION
-----------------------------
Parcel A
- --------
Parcel A of the Coso-Inyokern transmission line corridor begins
at survey station 0+00 at the Inyokern substation in the SE1/4, SE1/4 of Section
20, T26S, R39E, in Kern County, California and goes Northerly approximately 27
miles ending at survey station 1380+00 NWC/BLM Geothermal Plant No. 1 Switchyard
in SE1/4, NW1/4 of Section 19, T22S, R39E in Inyo County, California. The
transmission line is located entirely within the boundaries of the China Lake
Naval Weapons Center.
The corridor for the transmission line is the eastern portion of
a common corridor which is a strip of land 200 feet wide of which 65 feet of
this corridor is located to the left (Westerly) of the 115 kV transmission line
centerline and 135 feet is located to the right (Easterly) of the 115 kV
transmission line centerline from station 0+00 to station 731+59.27. From
station 731+59.27 to station 1245+11.06, the corridor is a strip of land 250
feet wide of which 100 feet is located to the left (Westerly) and 150 feet is
located to the right (Easterly) of the 115 kV transmission line centerline. From
station 1245+11.06 to station 1291+52.54, the corridor is a strip of land 300
feet wide of which 100 feet of this corridor is located to the left (Westerly)
and 200 feet is located to the right (Easterly) of the 115 kV transmission line
centerline. From station 1291+52.54 to Station 1380+00 the corridor is a strip
of land 250 feet wide of which 100 feet is located to the left (Westerly) and
150 feet is located to the right (Easterly) of the 115 kV transmission line
centerline.
The transmission corridor centerline is described as follows:
Sections 20, 7, 8, 5, and 6 of T26S, R39E
-----------------------------------------
Beginning at survey station 0+00, which is located on the North boundary fence
line of the Inyokern substation and is 400 feet West, more or less, and 320 feet
North, more or less, of the SE Corner of Section 20, T26S, R39E. Thence, from
station 0+00, N21 degrees 11'57"W a distance of 255.00 feet to an angle point at
station 2+55.00; thence N17 degrees 40'18"W a distance of 21,637 feet, more or
less, to the Leliter Road crossing at station 218+92 which is a point on the
North boundary of Section 6, T26S, R39E and 1410 feet West, more or less, of the
NE Corner of Section 6, T26S, R39E.
Sections 31, 30 and 19 of T25S, R39E
------------------------------------
Thence, from station 218+92, N17 degrees 40'18"W a distance of 13,228 to station
351+20 which is a point on the West boundary of Section 19, T25S, R39E and is
1960 feet North, more or less, of the SW Corner of Section 19, T25S, R39E.
45
<PAGE>
Sections 24, 13, 12, 1 and 2 of T25S, R38E
------------------------------------------
Thence, from station 351+20, N17 degrees 40'18"W a distance of 20,165 feet, to
survey station 552+85 which is a point on the Kern and Inyo County Line and on
the North boundary of Section 2, T25S, R38E and is 540 feet West, more or less,
of the NE Corner of Section 2, T25S, R38E.
Sections 35, 34, 27, 22, 15, 10 and 3 of T24S, R38E
---------------------------------------------------
Thence, from station 552+85, N17 degrees 40'18"W a distance of 980.65 feet to an
angle point at station 562+65.65; thence, N00 degrees 32'59"E a distance of
1849.86 feet to an angle point at station 581+15.51; thence N18 degrees 55'43"W
a distance of 8200.72 feet to an angle point at station 663+16.23; thence N17
degrees 49'44"W a distance of 6844.77 feet to an angle point at station
731+59.27; thence, N09 degrees 26'36"E a distance of 13,279.45 feet to an angle
point at equation station 864+40.45 Back and 873+76 Ahead; thence N07 degrees
43'29"E a distance of 1460 feet to survey station 888+39.76 which is a point on
the North boundary of Section 3, T24S, R38E and is 1680 feet West, more or less,
of the NE Corner of Section 3, T24S, R38E.
Sections 34, 27, 26, 23, 24, 13, 12 and 1 of T23S, R38E
-------------------------------------------------------
Thence, from station 888+39.76, N07 degrees 43'29"E a distance of 5111.45 feet
to an angle point at station 939+51.21; thence N31 degrees 43'12"E a distance of
9820.50 feet to an angle point at station 1037+71.71; thence N31 degrees 14'47"E
a distance of 10,758.97 feet to an angle point at station 1145+30.68; thence N10
degrees 29'2 9"W a distance of 8780.38 feet to survey station 1233+11.06 which
is a point on the North boundary of Section 1, T23S, R38E and is 1600 feet West,
more or less, of the NE Corner of Section 1, T23S, R38E.
Section 36 of T22S, R38E
------------------------
Thence, from station 1233+11.06, N10 degrees 29'29"W a distance of 1200.00 feet
to an angle point at station 1245+11.06; thence N43 degrees 08'19"E a distance
of 2718.94 feet to survey station 1272+30 which is a point on the East boundary
of Section 36, T22S, R38E and is 2180 feet South, more or less, of the NE Corner
of Section 36, T22S, R38E.
Sections 31, 30 and 19 of T22S, R39E
------------------------------------
Thence, from station 1272+30, N43 degrees 08'19"E a distance of 1922.34 feet to
an angle point at station 1291+52.34; thence N06 degrees 45'07"E a distance of
8634.99 feet to the end of Parcel A of the Coso-Inyokern transmission line
corridor at survey station 1380+00. This point is located at the NWC-BLM
Geothermal Plant No. 1 switchyard in the SE3, NW3 of Section 19, T22S, R39E in
Inyo County, California.
46
<PAGE>
Parcel B
- --------
Parcel B of the Coso-Inyokern 230 kV transmission line corridor
begins at station 0+00 at BLM (West) Geothermal Plant No. 1 switchyard in the SE
3, NW 3 of Section 19, T22S, R39E in Inyo County, California and extends to
station 77+57.20 BLM (East) Geothermal Plant No. 2 switchyard in the S2 of
Section 20, T22S, R39E. The transmission line is located entirely within the
boundaries of the China Lake Naval Weapons Center.
This portion of the corridor is a strip of land 100 feet wide of
which 50 feet of this corridor is located left (Northerly) and 50 feet is
located right (Southerly) of centerline of the corridor.
The transmission centerline is described as follows:
Sections 19 and 20 of T22S, R39E
--------------------------------
Beginning at survey station 0+00, BLM (West) Geothermal Plant No. 1 switchyard,
which is located at S52 degrees W 4035 feet, more or less, from the NE corner of
Section 19, T22S, R39E; thence N83 degrees 00'00"E, a distance of 350.00 feet to
an angle point at station 3+50.00; thence N42 degrees 55'19"E a distance of
469.21 feet to an angle point at station 8+19.21; thence N84 degrees 34'06"E, a
distance of 1148.23 feet to an angle point at station 19+67.44; thence N72
degrees 42'43"E a distance of 1445.45 feet to an angle point at equation station
34+12.89 back and 34+12.04 ahead; thence S53 degrees 05'47"E a distance of
2075.45 feet to an angle point at station 54+87.49; thence S08 degrees 59'02"E a
distance of 1301.63 feet to an angle point at station 67+89.12; thence S42
degrees 29'52"E a distance of 468.25 feet to an angle point at station 72+57.37;
thence N47 degrees 49'10"E a distance of 359.83 feet to an angle point at
station 76+17.20; thence N76 degrees 15'49"E a distance of 140.00 feet to the A-
Frame structure at station 77+57.20. This point is located at BLM (East)
Geothermal Plant No. 2 switchyard, S32 degrees W 5,080 feet plus or minus from
the NE corner of Section 20, T22S, R39E in Inyo County, California, and is the
end of Parcel B Coso-Inyokern transmission line corridor.
Parcel C
- --------
Parcel C of the Coso-Inyokern 230 kV transmission line corridor
begins at station 0+00 at BLM (East) Geothermal Plant No. 2 switchyard in the S2
of Section 20, T22S, R39E in Inyo County, California and extends to station
70+58.51 Navy II Geothermal Plant switchyard in Section 17, T22S, R39E. The
transmission line is located entirely within the boundaries of the China Lake
Naval Weapons Center.
This portion of the corridor is a strip of land 100 feet wide of
which 50 feet of this corridor is located left (Westerly) and 50 feet is located
right (Easterly) of centerline of the corridor.
47
<PAGE>
The transmission centerline is described as follows:
Sections 17 and 20 of T22S, R39E
--------------------------------
Beginning at survey station 0+00, BLM (East) Geothermal Plant No. 2 switchyard,
which is located S32 degrees W 5040 feet, more or less, from the NE corner of
Section 20, T22S, R39E; thence N76 degrees 58'47" W, a distance of 76.36 feet to
an angle point at station 0+76.36; thence N06 degrees 46'21"W, a distance of
2483.22 feet to an angle point at station 25 + 59.52; thence N19 degrees
32'09"E, a distance of 2513.26 feet to an angle point at station 50 + 72.82;
thence N63 degrees 57'16" W, a distance of 1169.08 feet to an angle point at
station 62 + 41.90; thence N18 degrees 16'46"W, a distance of 394.50 feet to an
angle point at station 66 + 36.40; thence N37 degrees 00'00"E, a distance of
422.11 feet to the A-Frame structure at station 70+58.51. This point is located
at Navy II Geothermal Plant switchyard, S42 degrees W 4,580 feet plus or minus
from the NE corner of Section 17, T22S, R39E in Inyo County, California and is
the end of Parcel C Coso-Inyokern transmission line corridor.
48
<PAGE>
EXHIBIT D
ESCROW ACCOUNT DISTRIBUTION PROVISIONS
1. Amounts deposited in the Escrow Account with respect to a Preferred
Return Year shall be distributed promptly after it is determined whether the
Distribution Condition is satisfied with respect to that Preferred Return Year,
as follows:
(a) if the Distribution Condition was satisfied for the Preferred
Return Year:
(i) first, to CCH, ESCA and Navy II Group, as directed in
writing by an authorized representative thereof, until distributions pursuant to
this Section 1(a)(i) equal the lesser of (a) the Maximum Payment for the
Preferred Return Year, and (b) the amount or deposit in the Escrow Account;
(ii) the balance to the Managing Partner; or
(b) to the Managing Partner, if the Distribution Condition was not
satisfied for the Preferred Return Year.
2. Amounts deposited in the Escrow Account pursuant to Sections
5.2(a)(ii) of the CPD and CED Partnership Agreements and Sections 5.3(a)(ii) and
5.4(a)(ii) of the CFP Partnership Agreement shall be distributed within fifteen
days after deposit to CCH, ESCA and Navy II Group, as directed in writing by an
authorized representative thereof.
3. All amounts distributed pursuant to Section 1(a)(i) and Section 2 will
be applied (i) first, to reduce Preferred Return Interest, and (ii) second, to
reduce the Preferred Return.
4. For the purpose of Section 1, "Distribution Condition" means the
generation of Excess Revenues by at least one Project during the Preferred
Return Year.
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EXHIBIT 3.5
THIRD AMENDED AND RESTATED
GENERAL PARTNERSHIP AGREEMENT
OF
COSO POWER DEVELOPERS
This Third Amended and Restated General Partnership Agreement (the
"Agreement"), of Coso Power Developers (the "Partnership"), dated as of May 28,
1999, is between (a) Caithness Navy II Group, LLC, a Delaware limited liability
company (successor by merger with Caithness Navy II Group, L.P., a New Jersey
limited partnership) ("Navy II Group"), and (b) New CTC Company, LLC, a Delaware
limited liability company ("New CTC").
RECITALS
On December 6, 1979, CalEnergy Company, Inc., a Delaware corporation
(formerly known as California Energy Company, Inc.) ("CECI") entered into a
contract (the "Navy Contract") with the United States Navy (the "Navy") to
develop geothermal energy at the Naval Weapons Center, China Lake, California,
and to sell the resultant electricity to the Navy.
CECI and Caithness Geothermal 1980 Ltd., a Delaware limited partnership
(successor by merger with Caithness Geothermal 1980 Ltd., a New Jersey limited
partnership) ("CG-80"), caused the formation of the China Lake Joint Venture
("CLJV"), a California joint venture. CLJV acquired rights pursuant to the Navy
Contract to develop geothermal resources on the Naval Weapons Center.
CECI assigned its rights and obligations under the Navy Contract to CLJV on
December 17, 1980. The assignment was approved by the Navy on December 24,
1980.
CECI caused the formation of Coso Technology Corporation, a Delaware
corporation "CTC"). On December 30, 1988, Caithness CPD Group, L.P., a
California limited partnership ("CCPDG") and CTC caused the formation of the
Partnership to carry out the obligations and receive the benefits relating to
the Navy II Assigned Rights (as defined below), and to the Navy II Project.
CLJV assigned the rights to the Navy II Project to Coso Energy Developers
("CED"), a California general partnership, in December 1988. CED assigned the
Navy II Assigned Rights, through a series of assignments, distributions and
contributions, to the Partnership.
<PAGE>
On or around July 31, 1989, CCPDG assigned all of its right, title and
interest in the Partnership to Navy II Group and Navy II Group became a
substitute general partner of the Partnership.
Pursuant to that certain Agreement and Plan of Merger dated as of February
25, 1999, CTC was merged with and into New CTC, and New CTC became the
successor-in-interest to CTC.
Concurrently with this Agreement, the Partnership is acquiring, subject to
the approval of the United States Department of the Interior, Bureau of Land
Management ("BLM"), an undivided interest as a tenant-in-common in and to the
BLM Leases (as hereinafter defined) and has entered into the Co-Tenancy
Agreement (as hereinafter defined) in order to utilize the resources from said
lands for the Navy II Project.
The parties hereto desire to provide for the continued existence and
governance of the Partnership, and to set forth in detail their respective
rights and duties relating to the Partnership.
NOW, THEREFORE, in consideration of the mutual covenants, conditions and
agreements herein contained, the parties agree as follows:
ARTICLE I
DEFINITIONS
The capitalized words and phrases used in this Agreement shall, unless the
context otherwise requires, have the meanings specified in this Article I.
1.1 "Act" means the California Uniform Partnership Act, as amended from
time to time.
1.2 "Additional Capital Contributions" has the meaning defined in Section
4.2 of this Agreement.
1.3 "Agreement" or "Partnership Agreement" means this Partnership
Agreement, as amended from time to time. Words such as "herein," "hereof,"
"hereto" and "hereunder" refer to this Agreement as a whole, unless the context
otherwise requires.
1.4 "BLM Leases" means that certain (i) Geothermal Resources Lease, Serial
No. CA-11384, by and between the United States of America, acting through BLM,
and the LADWP, effective as of February 1, 1982, as amended; (ii) Geothermal
Resources Lease, Serial No. CA-11385, by and between the United States of
America, acting through the BLM,
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<PAGE>
and the LADWP, effective as of February 1, 1982, as amended; and, (iii)
Geothermal Resources Lease, Serial No. CA-11383, by and between the United
States of America, acting through BLM, and the LADWP, effective as of February
1, 1982, as amended.
1.5 "Book" when used to modify an item of income, gain, loss or deduction,
or any word in reference thereto, means the amount thereof taken into account
for capital accounting purposes under the principles of Section 1.8 and
Regulation Section 1.704-1(b)(2)(iv).
1.6 "Budget" means each of the budgets to be prepared by the Managing
Partner and approved by the Management Committee pursuant to Section 7.4.
1.7 "Business Day" means any day that is not a Saturday, Sunday or a day
on which banking institutions in the City of San Francisco, State of California,
are authorized or required to close by law, executive order or Regulation.
1.8 "Capital Account" with respect to each Partner means the capital
account of that Partner determined and maintained throughout the full term of
the Partnership in accordance with the rules set forth in Regulation Section
1.704-1(b)(2)(iv). The initial balance of each Partner's Capital Account is set
forth in the Partnership books and records. In the event the Management
Committee determines that it is prudent to modify the manner in which the
Capital Accounts are maintained, or any debits or credits thereto (including,
without limitation, debits or credits relating to liabilities which are secured
by contributed or distributed property, or assumed by the Partnership with
regard to such asset with the approval of the Partnership), are accounted for,
in order to comply with such Regulations or if unanticipated events otherwise
cause the Partners' Capital Accounts not to comply with such Regulations, the
Management Committee may make such modification, provided that it is not likely
to have a material effect on the amounts distributable to any Partner. Subject
to the three previous sentences:
(a) Each Partner's Capital Account shall be increased by (i) the
amount of money contributed by such Partner to the Partnership; (ii) the Fair
Market Value of property contributed by such Partner to the Partnership (net of
liabilities secured by such contributed property that the Partnership is
considered to assume or take subject to under Code Section 752); and (iii)
Partnership income and gain (or items thereof) allocated to such Partner; and
shall be decreased by (iv) the amount of money distributed to such Partner by
the Partnership; (v) the Fair Market Value of property distributed to such
Partner by the Partnership (net of liabilities secured by such distributed
property that such Partner is considered to assume or take subject to under Code
Section 752); (vi) Partnership loss or deductions (or item thereof) allocated to
such Partner; (vii) the Partner's share of expenditures of the Partnership
described in Code Section 705(a)(2)(B), including for this purpose losses which
are nondeductible under Code Section 267(a)(1) or Code Section 707(b); and
(viii) the Partner's share of amounts paid or incurred by the Partnership to
organize the Partnership or
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<PAGE>
to promote the sale of (or to sell) an interest in the Partnership (except to
the extent properly amortizable for tax purposes).
(b) For this purpose, "income" refers to all items of income
(including all items of gain and including income exempt from tax) as properly
determined for Book purposes, and "loss" refers to all items of loss (including
all items of deduction) as properly determined for Book purposes.
(c) An assumption of a Partner's unsecured liability by the
Partnership shall be treated as a distribution of money to the Partner and an
assumption of the Partnership's unsecured liability by a Partner shall be
treated as a cash contribution to the Partnership in accordance with Section 752
of the Code and the Regulations thereunder.
(d) Capital Accounts shall be adjusted appropriately on account of
investment tax credit and investment tax credit recapture in accordance with the
principles of Code Section 48(q) and Regulation Section 1.704-1(b).
(e) In the event that assets of the Partnership other than cash are
distributed to a Partner in kind, Capital Accounts shall be adjusted for the
hypothetical Book gain or Book loss that would have been realized by the
Partnership if the distributed assets had been sold for their Fair Market Value
in a cash sale (in order to reflect unrealized Book gain or Book loss).
(f) At the option of the Management Committee, in the event of a
contribution of money or other property (other than a de minimus amount) to the
Partnership by a new or existing Partner as consideration for an interest in the
Partnership, or in connection with a distribution of money or other property
(other than a de minimus amount) by the Partnership to a continuing Partner as
consideration for an interest in the Partnership, Capital Accounts shall be
adjusted for the hypothetical Book gain or Book loss that would have been
realized by the Partnership if all Partnership assets had been sold for their
Fair Market Value in a cash sale (in order to reflect unrealized Book gain or
Book loss).
(g) In the event of a distribution of money or other property (other
than a de minimus amount) by the Partnership to a retiring Partner as
consideration for its interest in the Partnership, Capital Accounts shall be
adjusted for the hypothetical Book gain or Book loss that would have been
realized by the Partnership if all Partnership assets had been sold for their
Fair Market Value in a cash sale (in order to reflect unrealized Book gain or
Book loss).
1.9 "Capital Event" means any of the following: (a) a sale, repayment,
exchange, transfer, assignment or other disposition of all or a portion of any
asset (but not including occasional sales in the ordinary course of business of
inventory, furniture, fixtures and equipment); (b) any financing or refinancing
of, or with respect to, an asset; (c) any condemnation or deeding in lieu of
condemnation of a Project asset; (d) any collection with respect to property,
hazard or casualty insurance (but not business interruption insurance) or
4
<PAGE>
any damage award; or (e) any other transaction the proceeds of which, in
accordance with generally accepted accounting principles, are considered to be
capital in nature.
1.10 "Capital Contribution" means the amount of money plus the Fair Market
Value of property contributed by a Partner to the Partnership.
1.11 "Cash Flow from Capital Events" shall mean the net proceeds from each
Capital Event which the Management Committee makes available for distribution
after the Management Committee has set aside the amounts deemed prudent by the
Management Committee to: (a) replace tangible property disposed of or destroyed
and (b) provide working capital for the Partnership.
1.12 "Cash Flow from Operations" means, with respect to any fiscal period
and determined on the basis of a closing or interim closing of the books as of
the end of such period: (a) all cash receipts received during such fiscal
period by the Partnership (other than Cash Flow from Capital Events and Capital
Contributions); plus (b) any amounts that were originally reserved from amounts
that would otherwise have been Cash Flow from Operations that are no longer
deemed by the Management Committee to be required as reserves; less (c) all cash
outlays during such fiscal period to pay expenses of the Partnership; less (d)
any amounts set aside as reserves, including reserves for capital improvements,
expenses or contingent liabilities; less (e) payments (and reserves for
payments) of debt service (and premiums or penalties thereon, if any) on
indebtedness of the Partnership.
1.13 "CED" means Coso Energy Developers, a California general partnership,
the general partners of which are New CHIP Company, LLC, a Delaware limited
liability company and Caithness Coso Holdings, LLC, a Delaware limited liability
company (successor by merger with Caithness Coso Holdings, L.P., a California
limited partnership).
1.14 "CFP" means Coso Finance Partnership, a California general
partnership.
1.15 "COC" means Coso Operating Company, LLC, a Delaware limited liability
company.
1.16 "Code" means the Internal Revenue Code of 1986, as amended from time
to time, and any succeeding law.
1.17 "Co-Tenancy Agreement" means that certain Co-Tenancy Agreement, dated
as of even date herewith, by and between, the Partnership, CED, and Coso Finance
Partners, a California general partnership.
1.18 "CTLP" means Coso Transmission Line Partners, a California general
partnership, the general partners of which are CED and the Partnership.
5
<PAGE>
1.19 "Distribution Date" means the 45th day following the end of each
calendar quarter, commencing with the second quarter of 1988, or the next
succeeding Business Day if such day is not a Business Day.
1.20 "Escrow Account" means an interest-bearing deposit account acceptable
to the partners of each Joint Venture and established in the name of the
Managing Partner with a bank acceptable to the Partners pursuant to an escrow or
other similar agreement which is acceptable to each such Partner and contains
distribution provisions in form attached as Exhibit C to this Agreement.
1.21 "Excess Revenues" means, with respect to a period and a Project, one-
half of the difference between (a) the revenue for the Project for the period,
minus (b) the revenue which would have been guaranteed if the Project had
operated continuously during the period at 85% of its nominal capacity
(calculated at an assumed capacity of 80 MW for the CPD Project and the CFP
Project and 70 MW for the CED Project).
1.22 "Fair Market Value" shall mean the fair market value of an asset, as
reasonably agreed to among the Partners in arm's length negotiations, net of
liabilities secured by such asset or assumed by the Partnership with regard to
such asset.
1.23 "FERC" means the Federal Energy Regulatory Commission and any
successor thereto.
1.24 "FPLE" means FPL Energy Operating Services, Inc., a Florida
corporation.
1.25 "Interest" means a partnership interest in the Partnership with the
rights, terms and preferences described in this Agreement.
1.26 "Joint Venture" means any or all of CED, the Partnership and CFP.
1.27 "Management Committee" means the Management Committee established
pursuant to Article VIII.
1.28 "Managing Partner" means New CTC.
1.29 "Maximum Payment" means an amount equal to the Preferred Return.
1.30 "Meeting" means a meeting of Partners or of the Management Committee
duly called in accordance with Article VIII hereof.
1.31 "Navy II Assigned Rights" means the following rights that were
assigned to the Partnership (subject to Section 4.1) in partial consideration of
the issuance of Interests to CTC and Navy II Group; provided, however, that with
respect to the Transmission Line, the
6
<PAGE>
Navy II Assigned Rights include only the Partnership's initial "Segment
Interests" in "Segments 1 and 2" (each as defined in the Amended and Restated
General Partnership Agreement of Coso Transmission Line Partners) of the
Transmission Line (i.e., a 53.3% undivided interest in Segment 1 and the related
----
rights and a 100% undivided interest in Segment 2 and the related rights):
(a) the Navy II Project Area Rights;
(b) the Navy II Power Sales Contract, the Turnkey Contract and the
TMG Guarantee;
(c) an assignment of all assignable Navy II Project Authorizations;
(d) all other rights CED may have of any kind to the Navy II Project
Area, the Navy Contract, or other rights to or concerning the Navy II Project.
1.32 "Navy II Power Sales Contract" means the Power Sales Contract
effective June 28, 1985 between Southern California Edison Company and CLJV as
amended.
1.33 "Navy II Project" means the construction and operation of geothermal
power plants on the Navy II Project Area, and the development and operation of
the Navy II Project Area Rights and, from and after the date of this Agreement
and subject to and in accordance with the terms and conditions of the Co-Tenancy
Agreement, the rights and interests under the BLM Leases.
1.34 "Navy II Project Area" means the area described in Exhibit A.
1.35 "Navy II Project Area Rights" means the rights, titles, interests,
estates, powers and privileges the Partnership has (by assignment from CLJV or
otherwise) pursuant to the Navy Contract with respect to the Navy II Project
Area, including rights to all wells, the plant site, the Transmission Line and
other facilities (and all improvements, equipment, fixtures and other items
appurtenant or accessorial to those wells and facilities), including rights of
access and egress to the Navy II Project Area, subject to the terms and
conditions of the Navy Contract, and, from and after the date of this Agreement
and subject to and in accordance with the terms and conditions of the Co-Tenancy
Agreement, the rights and interests under the BLM Leases.
1.36 "Navy II Project Authorizations" means all permits, authorizations,
rights of way and licenses necessary or appropriate to operate and maintain the
Navy II Project and the geothermal resources subject to the Navy II Project Area
Rights.
7
<PAGE>
1.37 "Navy Contract" means the Original Service Contract N62474-79-C-5382
entered into between CECI and the United States Navy dated December 6, 1979,
together with all subsequent modifications thereto.
1.38 "Net Profit" and "Net Loss" means the net "income" and net Aloss" as
those terms are used in Section 1.8(b).
1.39 "Operator" means such operator as is designated by the Managing
Partner pursuant to Article VII.
1.40 "Original Agreement" means the General Partnership Agreement of Coso
Power Developers, dated December 30, 1988, as amended prior to the date hereof.
1.41 "Partners" means the Managing Partner, Navy II Group, and all
substituted or additional Partners. Where no distinction is required by the
context in which the term is used herein, APartner" means any one of the
Partners.
1.42 "Partnership" means Coso Power Developers, a California general
partnership, as such Partnership may be constituted from time to time.
1.43 "Plant Operations" means the operation and maintenance of all facets
of the Navy II Project operation which do not constitute Resource Operations,
including operation of the Transmission Line, power transmission facilities and
substation interconnection facilities.
1.44 "Preferred Return" means (a) $7,500,000, plus (b) the amount of
Preferred Return Interest accrued during any previous Preferred Return Year that
was not paid from distributions from the Escrow Account for that Preferred
Return Year, less (c) the sum of all distributions from the Escrow Account
previously applied to reduce the Preferred Return. Notwithstanding the
foregoing, the Preferred Return was prepaid in full at a discount to the parties
entitled thereto on December 16, 1992; provided, however, that if for any
Preferred Return Year for which the Preferred Return would have been paid if
such prepayment had not been made the Distribution Condition is not satisfied,
then Navy II shall promptly pay to the Escrow Account an amount equal to its
proportionate share (based on the percentage share of the Preferred Return paid
to it) of $715,000, which is the amount of the Preferred Return allocable to
each Preferred Return Year after taking into account the discount in connection
with the prepayment, to be distributed pursuant to Exhibit C.
---------
1.45 "Preferred Return Interest" means (a) an amount equivalent to the
interest which would have accrued from March 19, 1991 through the date of
determination on the amount of Preferred Return, as adjusted to reflect
distributions for each previous Preferred Return Year, at a per annum rate of
10%, less (b) the sum of all distributions from the Escrow Account previously
applied to reduce Preferred Return Interest.
8
<PAGE>
1.46 "Preferred Return Year" means each of the periods beginning on July 1
and ending on the immediately subsequent June 30. The first Preferred Return
Year shall begin on July 1, 1991, and the last Preferred Return Year shall end
on the date on which the Preferred Return would have been reduced to zero if
there had been no prepayment.
1.47 "Projects" means the three geothermal power projects owned by the
Joint Ventures.
1.48 "Regulations" means the Treasury Regulations promulgated under the
Code, as such Regulation may be amended from time to time, including
corresponding provisions of any succeeding Regulations.
1.49 "Resource Operations" means the well drilling and well operation and
maintenance work for the Navy II Project Area, as well as the operation and
maintenance of the geothermal resource related to that Project Area, the surface
steam gathering system and brine disposal system, together with construction and
maintenance of buildings, roads and other surface structures on that Project
Area.
1.50 "Section," unless preceded by the words "Code" or "Regulation," means
a Section of this Agreement.
1.51 "TMG Guarantee" means (i) that certain Guaranty Agreement (Navy II
Project) dated as of January 25, 1989 from The Mission Group, a California
corporation to CED and (ii) that certain Consent to Assignment of Agreement
dated as of January 25, 1989 by The Mission Group.
1.52 "Transmission Line" means the power line constructed pursuant to a
construction contract entered into by CED, a preliminary description of the
right-of-way for which is included as Exhibit B hereof.
1.53 "Turn-key Contract" means (i) that certain Contract for the
Engineering and Construction of the Coso Geothermal Project (Navy II - Units 1,
2 and 3) dated January 25, 1989 between CED and Mission Power Engineering
Company, a California corporation, as the same may be amended from time to time,
including all Exhibits thereto and (ii) that certain Consent to Assignment of
Agreement dated as of January 25, 1989 by Mission Power Engineering Company.
9
<PAGE>
ARTICLE II
PARTNERSHIP AMENDMENT; IDENTIFICATION; AND TERM
2.1 Amendment. The parties hereto agree to amend and restate the
---------
Original Agreement. The Managing Partner shall do, make or cause to be made all
such filings, recording, publishing and other acts as may be necessary or
appropriate from time to time in connection therewith, and as required to
preserve the existence of the Partnership.
2.2 Name, Principal Executive Office, Registered Office and Registered
------------------------------------------------------------------
Agent for Service of Process. The name of the Partnership shall be Coso Power
- ----------------------------
Developers, or such other name or names as may be selected by the Management
Committee from time to time. The principal executive office of the Partnership
and the office at which shall be kept the records, if any, required by the Act
shall be 1114 Avenue of the Americas, 41st Floor, New York, NY 10036, unless
changed by the Managing Partner with prior written notice given to the Partners
of such change. The Partnership may also maintain such other offices at such
other places as the Managing Partner may deem advisable. The name of the
Partnership's agent for service of process is Corporation Service Company, 80
State Street, Albany, New York 12207 and Corporation Service Company, which
will do business in California as CSC-Lawyers Incorporating Services, 2730
Gateway Oak Drive, Sacramento, California 95833.
2.3 Term. The term of the Partnership commenced on December 30, 1988 and
----
shall continue so long as it has any geothermal property interests in the Navy
II Project Area Rights, or so long as it has any obligations outstanding to any
lender having provided construction or term financing to the Partnership, or any
assignee thereof, unless the Partnership is terminated earlier in accordance
with Article XIII; provided, however, that nothing contained herein shall be
-------- -------
deemed to give a Partner a right to withdraw from the Partnership.
ARTICLE III
PURPOSE AND NATURE OF BUSINESS; CERTAIN OBLIGATIONS
3.1 Purpose. The purpose of the Partnership and the business to be
-------
carried on by it, subject to the limitations contained elsewhere in this
Agreement, are:
(a) To hold the Navy II Assigned Rights (subject to the conditions of
this Agreement), to develop the same, and to develop, construct, own and operate
the Navy II Project;
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<PAGE>
(b) to raise sufficient capital through borrowings from banks or other
lenders to finance the construction of the Navy II Project, and to provide for
the development and the exploitation of the lands subject to the Navy II Project
Area Rights;
(c) to borrow money for any legitimate Partnership purpose and in
connection therewith to issue notes, bonds, debentures and other evidences of
indebtedness and to secure the same and hypothecate any, all or substantially
all of the assets of the Partnership by mortgage, deed of trust, pledge or other
lien in furtherance of the foregoing purposes of the Partnership;
(d) to enter into and perform contracts and agreements and to carry on
any other activities necessary to or desirable or incidental in connection with,
the accomplishment of the foregoing purposes of the Partnership.
(e) to engage in any kind of activity and to enter into and perform
obligations of any kind necessary to, or in connection with, or incidental to,
the accomplishment of the purposes and business of the Partnership, so long as
such activities and obligations may lawfully be engaged in or performed by a
partnership under the Act; and
(f) to be a general partner of CTLP.
Such purpose and business of the Partnership shall include the entering
into by the Partnership of the transactions described in that certain
preliminary Offering Circular of Caithness Coso Funding Corp. dated May 5, 1999
(as it may have been revised, the "Offering Circular"), including without
limitation the making by the Partnership of certain loans to and the pledging by
the Partnership of certain funds of the Partnership for payment of certain
obligations of affiliated partnerships, all to the extent provided for and
described in the Offering Circular and the definitive documents entered into in
accordance therewith.
ARTICLE IV
CAPITAL
4.1 Partners' Capital Contributions to the Partnership.
--------------------------------------------------
(a) The Partnership has assumed and taken the Navy II Assigned Rights
subject to, all liabilities secured by or incurred in connection with the Navy
II Assigned Rights at the time of the contribution or assumed by the Partnership
with regard to such assigned rights.
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<PAGE>
(b) The Partners agree that the fair market value of each Partner's
Capital Contribution as of the date of this Agreement is as indicated in the
books and records of the Partnership.
4.2 Additional Capital Contributions. Each Partner shall have the right,
--------------------------------
but not the obligation, to make additional capital contributions ("Additional
Capital Contributions") under the terms of this Section 4.2.
(a) A Partner may make an Additional Capital Contribution only if one
or both of the following conditions has occurred:
(i) the Management Committee has approved a Budget authorizing
Additional Capital Contributions; or
(ii) a Partner has notified the Management Committee in writing
that, in that Partner's best business judgment, the Partnership requires
additional equity capital for any bona fide reasonable business purpose relating
to drilling and construction necessary to bring on line for commercial
operations the power plant to provide electricity for the Navy II Power Sales
Contract (such notice to include a proposed required capital amount and
description of the uses and schedule of application of the funds and to be made
in a form and format established by the Management Committee and to indicate
that it constitutes a notice under this Section 4.2(a)(ii)), and the Management
Committee has not approved the proposal within ten (10) days of the notice.
(b) (i) If the conditions described in (a) above have occurred,
either Partner without first being required to obtain the approval of the other
Partner shall give written notice to the other Partner, which shall specify the
amount of Additional Capital Contributions required and the contribution date
("Contribution Date") upon which the Partners shall contribute the Additional
Capital Contributions to the capital of the Partnership. The additional Capital
Contributions shall be contributed to the capital of the Partnership by each of
the Partners in the ratio which each Partner's Capital Account bears to the
aggregate of all Partners' Navy II Capital Accounts (immediately prior to that
Additional Capital Contribution).
(ii) In the event that at any time either Partner shall fail to
contribute its share of the Additional Capital Contributions on the Contribution
Date (for purposes of this subsection (ii), a "Defaulting Partner"), as provided
in Section 4.2(b)(i), then, as to each such default, the other Partner (for
purposes of this subsection (ii), the "Contributing Partner") shall have the
right, but not the obligation, to make the contribution of Additional Capital
Contributions which the Defaulting Partner failed to make (but only after the
Contributing Partner made the full amount of its own Additional Capital
Contributions) on behalf of the Defaulting Partner by giving notice to the
Defaulting Partner within twenty (20) days after the Contribution Date (such
notice to specify that it constitutes a notice under this
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<PAGE>
Section 4.2(b)(ii)), in which event such sum shall become and be treated as a
loan ("Default Loan") by the Contributing Partner to the Defaulting Partner
bearing interest at the rate of two percentage points above the rate of interest
publicly announced by Chase Manhattan Bank N.A., in New York, from time to time
as its "Prime" or "Base" rate of interest, publicly announced by Chase Manhattan
Bank N.A., in New York, from time to time as its "Prime" or "Base" rate of
interest, and due and payable in full on the date which is six months after the
Contribution Date (the "Default Date"). The Defaulting Partner shall have no
obligation to repay the Default Loan, but in the event the Defaulting Partner
does not repay the Default Loan, plus all accrued but unpaid interest thereon,
in full by the Default Date, the respective Capital Accounts shall be adjusted
to reflect the Additional Capital Contributions, including all such unpaid
interest, as follows: the contributing Partner's Capital Account shall be
increased by the number of dollars by which the Contributing Partner's
Additional Capital Contribution exceeded the Defaulting Partner's Additional
Capital Contributions, and the percentages in Sections 5.1 and 5.2 shall be
adjusted according to the new relative Capital Accounts. In such event, the
Defaulting Partner's percentages shall be reduced accordingly and the Default
Loan, and all accrued but unpaid interest, shall be deemed paid in full.
4.3 Restrictions Relating to Capital; No Withdrawal. Except as otherwise
-----------------------------------------------
specifically provided in this Agreement or in the Act, no Partner shall have the
right to withdraw or reduce its Capital Contributions, to receive interest on
its Capital Contributions, to partition Partnership assets or to receive
property other than cash in return for its Capital Contributions.
4.4 Additional Partners. No additional Partners shall be admitted to the
-------------------
Partnership except with the consent of, and in accordance with the terms
(including the relative rights, duties and interest of such additional
Partners), conditions and procedures agreed to by all Partners; provided,
--------
however, that any Partner may, without the consent of any other Partner or the
- -------
Management Committee, subdivide its Interest, through formation of a
partnership, corporation or other arrangement that would hold that Partner's
Interest so long as that Partner remains the owner of a portion of the Interest.
5.5 Right of First Offer. Each Partner grants to the other Partner a
--------------------
right of first offer with respect to any desired or proposed sale or transfer,
whether originated by that Partner or a third party (a "Disposition") of all or
part of the Interest of the Partner proposing to make the Disposition (the
"Disposing Partner"), upon the terms and conditions of this Section 4.5.
(a) The right of first offer described in this Section 4.5 shall not
be effective unless the following conditions are satisfied:
(i) The Disposition shall involve the granting of a seat on the
Partnership's Management Committee, whether a present grant, a future right or
contingent opportunity of any kind to that seat; and
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(ii) The Disposition shall become effective, with respect to any
unit or plant to be constructed, during the development stage of the unit or
plant constructed to provide electricity for the Navy II Power Sales Contract,
up to and including the time the unit or plant has been completed and goes on
line for commercial operations.
(b) Any Disposing Partner desiring to make a Disposition of all or
part of its Interest under conditions satisfying subsection (a) above shall send
a notice to the other Partner (the "Non-Disposing Partner") of the intended
Disposition, including the name of the proposed purchaser, a description of the
portion of the interest to be sold or transferred and the terms of the
Disposition. For a period of 30 days after receipt of the notice, the Non-
Disposing Partner shall have the right to purchase the portion of the notice.
The purchase right shall be exercised by notifying the Disposing Partner in
writing of the decision to exercise that right. If the Non-Disposing Partner
exercised the right to purchase within 30 days of receipt of the notice, the
Non-Disposing Partner must complete the purchase within 60 days of the notice of
intent to purchase. Failure to give notice of intent to purchase or to
consummate the purchase within the time limits described above shall allow the
Disposing Partner to proceed with the intended Disposition on the terms
described in the original notice; provided, however, that if the Disposing
Partner amends any material term of the sale or transfer, or changes the nature
or amount of the Interest to be sold or transferred, the Non-Disposing Partner
shall again have the right, as described in this Section 4.5, to purchase the
offered Interest on the amended terms and conditions.
(c) If the Non-Disposing Partner exercises its right to purchase the
Interest to be disposed of, the Disposing Partner shall cooperate in all
reasonable ways and in good faith with the Non-Disposing Partner to consummate
the sale of the Interest within the time period described in (b) above.
(d) No purchase by a Partner of any portion of an Interest under this
Section 4.5 shall in any way cause the purchasing Partner to increase its number
of seats, or the Disposing Partner to reduce its number of seats, on the
Management Committee.
ARTICLE V
CURRENT DISTRIBUTIONS
5.1 Cash Flow from Operations. Subject to Article XIII (that is, other
-------------------------
than in liquidation of a Partner's Interest in the Partnership as provided in
Section 13.4(a)) and to Section 4.2, Cash Flow from Operations shall be applied
or distributed on each Distribution Date as follows:
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(a) until the Preferred Return has been reduced to zero (or funds are
on deposit in the Escrow Account sufficient to reduce the Preferred Return to
zero and the Distribution Condition will be satisfied for the Preferred Return
Year):
(i) to New CTC 50%;
(ii) to Navy II Group 50%;
provided, however, that all amounts distributable to New CTC pursuant to this
Section 5.1(a) on a Distribution Date shall be deposited into the Escrow Account
until (a) the Joint Ventures have deposited therein an amount, in the aggregate,
equal to the Maximum Payment for the Preferred Return year in which the
Distribution Date occurs, or (b) the Partnership has deposited therein an
amount, in the aggregate, equal to the Excess Revenues for the Partnership's
Project for the Preferred Return Year; and
(b) after the Preferred Return has been reduced to zero, in the manner
provided in Section 5.1(a), without regard to the proviso in Section 5.1(a).
5.2 Cash Flow from Capital Events. Subject to Article XIII (that is,
-----------------------------
other than in liquidation of a Partner's Interest in the Partnership as provided
in Section 13.4(a)) and to Section 4.2, Cash Flow from Capital Events shall be
applied or distributed on each Distribution Date as follows:
(a) before the Preferred Return has been reduced to zero:
(i) To deposit 50% in the Escrow Account; and
(ii) To distribute 50% to Navy II Group
(b) after the Preferred Return has been reduced to zero, 50% to New
CTC and 50% to Navy II Group.
ARTICLE VI
ALLOCATIONS
6.1 Allocation of Net Profit and Net Loss. For each fiscal year of the
-------------------------------------
Partnership, the Net Profit or Net Loss of the Partnership, and each item of
income or deduction entering into the computation thereof (exclusive of other
items of income, gain, loss or deduction that are otherwise allocated under this
Article VI), shall be allocated to and among the Partners in the same proportion
that Cash Flow from Operations is (or would have been had there been
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Cash Flow from Operations) distributed to them under the provisions of Section
5.1 hereof for such fiscal year.
6.2 Allocation of Net Gain and Net Loss from Capital Events. The net
-------------------------------------------------------
Book gain (Book gain in excess of Book loss) of the Partnership from Capital
Events, and the net Book loss (Book loss in excess of Book gain) of the
Partnership from Capital Events, shall be allocated, to and among the Partners
in the same manner that Cash Flow from Capital Events is distributed under the
provisions of Section 5.2.
6.3 Allocation of Intangible Drilling and Development Costs. The Book
-------------------------------------------------------
deduction for intangible drilling and development costs of the Partnership shall
be allocated to and among the Partners as follows:
(i) Intangible drilling and development costs with respect to the
Navy II Project paid from Additional Capital Contributions (which for the
purposes of this subsection shall be deemed to include any Default Loan under
Section 4.2 which has not been paid in full) shall be allocated 98% to the
Partner from whom the Additional Capital Contributions (or the Default Loan) for
the deductible items were received, and 2% to the Partners in the manner
described in Section 5.2.
(ii) Intangible drilling and development costs for the Navy II Project
paid from funds borrowed by the Partnership shall be allocated among the
Partners in the same manner that Cash Flow from Capital Events is distributed
under the provisions of Section 5.2.
6.4 Allocations for Tax Purposes.
----------------------------
(a) All items of Partnership income, gain, loss and deduction for
federal and state income tax purposes shall be allocated to and among the
Partners in the same manner that the corresponding Book items of the Partnership
are allocated in Sections 6.1 through 6.3, except as otherwise provided in
Regulation Section 1.704-1(b)(4)(i) and except that solely for Federal, local
and state income and franchise tax purposes and not for Book or Capital Account
purposes, income, gain, loss and deduction with respect to property properly
carried on the Partnership's books at a value other than its tax basis shall be
allocated, (i) in the case of property contributed in kind, in accordance with
the requirements of Code Section 704(c) and such Regulations as may be
promulgated thereunder from time to time, and (ii) in the case of other
property, in accordance with the principles provided in Regulations under Code
Section 704(b).
(b) In the event that the Partnership has taxable income that is
characterized as ordinary income by reason of the recapture provisions of the
Code, each Partner's allocation of taxable gain from the sale or exchange of
Partnership assets (to the extent possible) shall include a proportionate share
of the recapture income equal to the Partner's (and his predecessors in
interest's) share of prior cumulative depreciation, cost recovery or other
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deductions with respect to the assets which gave rise to the recapture income
(but not to exceed the amount of gain allocated to each Partner).
6.5 Allocation in Event of Transfer of Partnership Interest during the
------------------------------------------------------------------
Year. The Capital Account of any Partner shall carry over to the transferee of
- ----
any Partner to the extent it relates to the transferred interest. Except to the
extent otherwise required by the Code and any Regulations thereunder, if a
Partnership interest or part thereof is transferred, the portion of each such
item allocable to such Partnership interest shall be allocated between the
transferor and transferee in proportion to the number of days in such fiscal
year the Partnership interest is held by said transferor and transferee (as
determined in accordance with Section 10.1), except that, if they so agree
between themselves and so notify the Managing Partner in writing within 30 days
of the transfer, extraordinary items, including capital gains and losses, may be
allocated to the person who held the Partnership interest on the date such item
was realized by the Partnership.
6.6 Regulatory and Curative Allocations.
-----------------------------------
(a) Notwithstanding the foregoing provisions of this Article VI, the
Partnership shall allocate items of book income and gain in a manner that
constitutes a "minimum gain chargeback" as described in Section 1.704-2 of the
Treasury Regulations and the term "minimum gain" shall have the meaning assigned
to it therein. Determinations of each Partner's share of minimum gain shall be
made in accordance with Section 1.704-2 of the Treasury Regulations. In
addition, "partner nonrecourse deductions" shall be allocated to the Partners
bearing the risk of loss with respect to such deductions in accordance with
Section 1.704-2 of the Treasury Regulations.
(b) The Partners acknowledge and ratify the following modifications to
the provisions of this Article VI that were adopted pursuant to discussions
among the Partners and the Partnership accountants:
(i) For purposes of allocating income with respect to each year,
distributions are to be taken into account on the day in which they occur, and
the effective profit and loss percentages shall be determined as of each date
such distributions occur;
(ii) The following items are allocated in the ratios that apply
to Capital Events cash flow: depreciation, write-offs of plant and well capital
costs, fees paid to Southern California Edison related to transmission lines,
and alternative minimum tax adjustments and preferences associated with
property, plant and equipment; and
(iii) The initial capital contributions of the Partners are
determined by reference to the generally accepted accounting principle financial
statement figures for such capital contributions.
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(c) As stated in Treasury Regulations Section 1.704-1(b)(4)(i), when
any property of the Partnership is reflected in the Capital Accounts of the
Partners and on the books of the Partnership at a book value that differs from
the adjusted tax basis of such property, then certain book items with respect to
such property will differ from certain tax items with respect to that property.
Since the Capital Accounts of the Partners are required to be adjusted solely
for allocation of the book items, the Partners' shares of the corresponding tax
items are not independently reflected by adjustments to the Capital Accounts.
These tax items must be shared among the Partners in a manner that takes account
of the variation between the adjusted tax basis of the applicable property and
its book value pursuant to or in the same manner as variations between the
adjusted tax basis and fair market value of property contributed to the
Partnership are taken into account in determining the Partners' share of tax
items under Code Section 704(c). In making allocations of tax items of the
Partnership, the Partnership shall comply with the foregoing principles.
(d) The Partners intend that the allocation of items of income, gain,
loss, deduction and credit pursuant to this Agreement result in Capital Account
balances that achieve the economic sharing provisions reflected in Article V,
as amended. Notwithstanding any other provisions contained herein, allocations
of income, gain, loss and deductions shall be applied and amended by the
Managing Partner as necessary to produce such result, including special
allocations of gross income and gross deductions and amendment of prior tax
returns. This Section 6.6(d) shall control notwithstanding any reallocation of
income, loss or items thereof by the Internal Revenue Service or other taxing
authority.
ARTICLE VII
RIGHTS, DUTIES, LIABILITIES AND
COMPENSATION OF THE MANAGING PARTNER
7.1 General.
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(a) Except as otherwise provided in this Agreement, the Managing
Partner shall be responsible for the conduct of the business of the Partnership
and for Project operations. The Managing Partner shall devote to the business
affairs of the Partnership such time and effort as the Managing Partner may from
time to time deem necessary. Pursuant to that certain Amended and Restated
Operations and Maintenance Agreement, made and entered into by the Partnership,
COC and FPLE, dated February 25, 1999, and that certain Amended and Restated
Field Operations Agreement, executed by COC and the Partnership, dated February
25, 1999 (FPLE and COC are individually and collectively referred to herein as
"Operator"), as either may be amended, COC shall act as Operator, provided,
however, that certain field and maintenance operations shall be performed by
FPLE.
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(b) The Managing Partner and the Operator shall be subject to all
directives of the Management Committee with respect to the performance of their
respective duties hereunder, and shall be liable to the Partnership for all
damages, losses and expenses incurred by the Partnership as a result of
noncompliance with such directives.
7.2 General Rights and Powers of Managing Partner. Except as otherwise
---------------------------------------------
provided herein, including the provisions of Article VIII:
(a) The management and control of the day-to-day business and affairs
of the Partnership shall rest with the Managing Partner, which shall have such
rights and powers as are necessary, advisable or convenient to the discharge of
its duties under this Agreement and to the management of the business affairs of
the Partnership in furtherance of the purposes of the Partnership as set forth
in Article III.
(b) In furtherance of the purposes of the Partnership as set forth in
Article III of this Agreement, the Managing Partner is hereby granted the right,
power and authority to do on behalf of the Partnership all things which, in its
reasonable judgment, are necessary, proper or desirable to carry out its duties
and responsibilities hereunder, including, but not limited to, the following:
from time to time to incur all reasonable expenditures pursuant to the Budget;
to employ and dismiss from employment any and all employees, agents,
contractors, brokers, attorneys and accountants except for the partnership's
auditor; to create, by grant or otherwise, easements and servitudes; to borrow
money up to an aggregate principal amount of $100,000 at any time outstanding;
and to execute, acknowledge and deliver any and all contracts, agreements or
other instruments to effectuate any and all of the foregoing. Subject to the
direction of the Management Committee, the Managing Partner shall be responsible
for the following:
(i) maintain and protect the assets of the Partnership and the
interests of the Partners;
(ii) obtain such consultants, technicians, agents, and
contractors as it deems may be required for Project operations;
(iii) make all reports and disburse funds in accordance with the
Budget for all payments required under this Agreement with respect to Project
operations and under all agreements, permits, authorizations, and other rights
relating thereto;
(iv) submit the Budget, cost projections and any other budgets
for Project operations to the Management Committee;
(v) keep full and accurate records and accounts of the
transactions entered into by it on behalf of the Partnership;
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(vi) do all such acts and things and conduct all such steps as
may reasonably be necessary or advisable in its judgment for the efficient and
economical conduct of Project operations; and
(vii) secure adequate and reasonable insurance (to the extent
possible and with the Partners and Partnership as named insureds) covering those
insurable risks with respect to the Partnership and Partnership operations that
can be insured at reasonable costs, including risk of personal injuries to or
deaths of employees or others, risks of fire, and all other risks ordinarily
insured against in similar operations, and adjust losses and claims pertaining
to or arising out of such insurance.
7.3 Expenses. The Partnership shall reimburse the following expenses of
--------
the Partnership incurred by either of the Partners limited to the amounts set
forth in the applicable Budget approved in accordance with Section 7.4:
(a) all organizational fees and expenses of the Partnership and of the
Partners;
(b) the actual costs of goods and materials used by or for the
Partnership by the Managing Partner, any subcontractors or the Partnership;
(c) all employee time and costs and related overhead of the Managing
Partner attributable to the business of the Partnership;
(d) all operational expenses of the Partnership that may be paid by
the Managing Partner pursuant to the terms hereof, including, without
limitation, the following: obligations related to Navy II Assigned Rights; all
costs of borrowed money paid to lenders; taxes and assessments on Partnership
assets and other taxes applicable to the Partnership; legal, accounting,
appraisal, audit and brokerage fees; fees and expenses paid to independent
consultants or insurance brokers; and
(e) all accounting, documentation, professional and reporting expenses
of the Partnership paid or to be paid to any person, including, without
limitation, the following: preparation and documentation of Partnership
accountings and audits; preparation and documentation of Partnership state and
federal tax returns; expenses of revising, amending, converting, modifying, or
terminating this Agreement or the Partnership; costs incurred in connection with
any litigation in which the Partnership is involved as well as any examination,
investigation or other proceedings conducted by any regulatory agency with
respect to the Partnership, including legal and accounting fees incurred in
connection therewith; costs of any computer equipment or services used for or by
the Partnership; and the costs of preparation and dissemination of informational
material and documentation relating to a potential sale by the Partnership of
Partnership Interests to third parties or relating to a potential acquisition,
sale, financing or refinancing of Partnership assets.
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7.4 Budget; Mechanism for Reimbursement.
-----------------------------------
(a) The Managing Partner shall prepare the Budget for the Partnership,
which shall include a capital expenditure budget and a budget for Partnership
operations for each quarter, which is to be presented to the Management
Committee for approval no later than 45 days prior to the beginning of the
applicable quarter. Once the Budget has been approved by the Management
Committee, the Managing Partner may pay all Partnership expenses, reimburse
itself for expenditures permitted by Section 7.3, and otherwise apply all
available Partnership funds in accordance with the approved Budget.
(b) Subject to the approval of the Management Committee, the
reasonable costs incurred by the Partners in connection with matters to be
considered by the Management Committee as well as any other activities of the
Partners assigned to such Partners by the Management Committee shall be
reimbursed by the Partnership in accordance with the amounts set forth in the
applicable Budget approved in accordance with Section 7.4(a).
7.5 Third-Party Reliance. Any person dealing with the Partnership as to
--------------------
any matter with respect to which the Managing Partner is granted authority
hereunder may rely solely on written advice from the Managing Partner as to any
matter relating to this Agreement, as to compliance herewith and as to the
authority of the Managing Partner to act on behalf of the Partnership, and as
between the Partnership or the Managing Partner, on the one hand, and such other
person, on the other hand, the facts stated in such written advice from the
Managing Partner will be conclusive and binding on the Partnership and the
Managing Partner.
7.6 Justification of Expenses. In connection with the reimbursement or
-------------------------
payment by the Partnership of any expenses under this Agreement to any Partner,
each Partner shall have the right to receive from the Partner claiming
reimbursement or payments such supporting documentation as may be reasonably
requested to justify such reimbursement or payments.
ARTICLE VIII
MANAGEMENT OF PARTNERSHIP
8.1 Management Committee. Subject to the requirements of the Act or
--------------------
other applicable law, the business operations of the Partnership shall be
overseen by a Management Committee, consisting of two delegates appointed by New
CTC and two delegates appointed by Navy II Group. New CTC and Navy II Group
shall each be fully empowered to substitute for its own delegates and to appoint
alternates. The decision of the Management Committee shall be required for all
actions set forth at Section 8.4.
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8.2 Meetings. The Partnership shall hold Meetings to transact all
--------
Partnership business for which a meeting or a vote of the Partners is required
by the Act. Each Partner shall send two delegates to each Meeting. Each
Partner may substitute or change delegates at will, and shall notify the other
Partner of the names of such delegates prior to each Meeting.
8.3 Procedures. Management Committee Meetings and Partnership Meetings
----------
shall occur and be conducted pursuant to the following procedures:
(a) The Partnership and the Management Committee shall hold a Meeting
on the second Tuesday of January, April, July and October of each year and on
such other dates as shall be called by a Partner on written notice of not less
than fifteen (15) business days given by the calling party to all Partners,
which notice shall be accompanied by an agenda and supporting documentation
describing, in reasonable detail, the issues to be presented to the Management
Committee for voting. Meetings shall be held at the Managing Partner's office
and begin at 10:00 A.M. unless another time or place is agreed to.
(b) A quorum of three delegates (including alternates to delegates not
present) must be present to convene a Meeting and/or vote on Partnership or
Management Committee matters.
(c) All votes on Partnership or Management Committee action shall
require a favorable vote of at least a majority of the delegates comprising the
quorum present at the Meeting; provided, however, that said favorable vote must
be composed of at least one favorable vote by a delegate representing New CTC
and one favorable vote by a delegate representing Navy II Group.
(d) Action by the Partnership and the Management Committee may be
taken at any time without a meeting upon the written consent of at least three
delegates. For the purposes of this provision, written consent shall be deemed
given by a delegate if said delegate does not make an objection to the action
proposed in the form of written consent sent to the delegates within 15 days
after the actual receipt of such form of written consent by such delegate.
(e) The Partnership and the Management Committee may also take action
by vote of at least three delegates given by telephone which vote shall be
subsequently confirmed in writing to all delegates. The notice provision in
Section 8.3(a) shall apply also to such vote by telephone, provided, however,
that vote may be taken without notice if, in the reasonable opinion of the three
delegates so voting, there exists an emergency situation precluding such advance
notice, and that all reasonable efforts have been made to notify all Partners of
the emergency and the vote.
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(f) Minutes shall be prepared for all Meetings, and shall be approved
by the Partners or the Management Committee, as applicable, prior to being
entered into the permanent minute book maintained by the Managing Partner for
the Partnership.
8.4 Limitations on Authority of Managing Partner. The Managing Partner
--------------------------------------------
shall have no authority to do any act prohibited by law, nor shall the Managing
Partner, without the consent of the Management Committee, have any authority to:
(a) permit any creditor who makes a nonrecourse loan to the
Partnership to take, as a condition of making such loan, any direct or indirect
interest in the profits, capital, assets or property of the Partnership other
than as a secured creditor;
(b) sell or lease the Partnership's rights in commercial geothermal
wells, power plants and other substantial assets owned by the Partnership;
(c) make or amend contracts for the sale of electricity;
(d) terminate, liquidate and wind up the Partnership, except upon the
occurrence of an event which, under the Act, dissolves or terminates the
Partnership;
(e) approve and establish procedures and ongoing review of all budgets
and the budget process, including each Budget;
(f) change the Partnership's auditor;
(g) create, incur or assume any indebtedness for borrowed money other
than in the ordinary course of Partnership business;
(h) obtain refinancing or replacements of any mortgages or other
security instruments related in any way to any Partnership property, or repay in
whole or in part, refinance, recast, modify, consolidate or extend any of the
terms of any indebtedness owed by the Partnership or affecting all or any
portion of any Partnership property;
(i) modify, amend or waive any provision of any material agreement to
which the Partnership is a party;
(j) create, incur or assume any indebtedness in aggregate principal
amount at any time outstanding greater than $100,000;
(k) acquire, amend or terminate any geothermal leases;
(l) engage and discharge outside consultants, construction
contractors, engineers or similar entities or professionals, including contracts
with third-party Project
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operators in connection with work to be performed by or for the benefit of the
Partnership in instances where the estimated or incurred cost of said work
exceeds $1,000,000; excluding, however, contracts for drilling of wells and all
related supplies and equipment, provided the estimated costs of such contracts
do not exceed the amounts budgeted for such items in an approved Budget; further
provided that any contract between the Partnership and the Operator, the
Managing Partner or any of their affiliates must have the approval of the
Management Committee;
(m) all other functions for which Partnership approval is required by
applicable law or for which Management Committee approval is required by this
Agreement; or
(n) (i) do any act in contravention of this Agreement or not in
furtherance of the purposes of the Partnership set forth in Article III; (ii) do
any act which would make it impossible to carry on the ordinary business of the
Partnership; (iii) confess a judgment against the Partnership; (iv) possess
Partnership property or assign rights in specific Partnership property for any
purpose other than a Partnership purpose; (v) change or reorganize the
Partnership into any other legal form; or (vi) admit a person as a Partner,
except as provided in this Agreement.
Notwithstanding anything to the contrary set forth herein, the Managing Partner
shall have the authority, without the approval of the Management Committee, to
administer the definitive documents entered into by the Partnership in
accordance with and as generally described in the Offering Circular, including
any amendments, waivers, extensions, indulgences, minor adjustments, or other
loan administration matters with respect to such documents (other than
amendments materially affecting the Partnership or any Partner).
ARTICLE IX
REPRESENTATIONS AND COVENANTS OF PARTNERS
9.1 Representation of Partners. Each Partner represents to each other
--------------------------
Partner that it is an entity duly organized and validly existing under the laws
of its jurisdiction, and qualified to do business in the State of California,
that all action required by such Partner to authorize that Partner to enter into
this Agreement has been taken, and that this Agreement is a binding agreement of
that Partner, enforceable in accordance with its terms.
9.2 Covenants of Partners. Each Partner covenants that it will not
---------------------
engage in any business or in any other activities other than performing its
obligations under this Agreement to the extent such business or other activities
are limited by agreements between the Partnership and lenders providing
financing to the Partnership.
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ARTICLE X
ASSIGNMENTS OR TRANSFERS OF INTERESTS
10.1 Assignments. Subject to compliance with applicable federal and state
-----------
securities laws, and subject to Sections 4.4 and 4.5, a Partner may transfer all
or a portion of his Interest in the Partnership, by an executed and acknowledged
written instrument, only with the consent of the Management Committee. Subject
to compliance with applicable federal and state securities laws, assignments
will be recognized by the Partnership only effective the last day of the
calendar month following the receipt by the Partnership of written notice of the
assignment. The Partnership may charge the assigning or transferring Partner
and any Partner requesting a change of name, type of ownership, etc., a fee not
to exceed the expenses, including actual legal expenses, incurred in effecting
the assignment or transfer of his interest in the Partnership or other change in
the records of the Partnership.
10.2 Substituted Partners. No assignee of the whole or any portion of a
--------------------
Partners' Interest in the Partnership shall have the right to become a
substituted Partner in the place of his assignor unless all of the following
conditions are satisfied:
(a) the fully executed and acknowledged written instrument of
assignment that has been filed with the Partnership sets forth the intention of
the assignor that the assignee become a substituted Partner in his place;
(b) the assignor and assignee execute and acknowledge such other
instruments as the Management Committee may deem necessary or desirable to
effect such admission, including the written acceptance and adoption by the
assignee of the provisions of this Agreement and his execution, acknowledgment
and delivery to the Management Committee of a Power of Attorney, the form and
content of which shall be provided by the Management Committee;
(c) any transfer fee and legal expenses, if any, referred to in
paragraph (a) above required to be paid shall have been paid;
(d) the transfer shall not be in violation of any applicable federal
or state securities laws, including the Securities Act of 1933, as amended, nor
shall it cause the termination of the Partnership under Section 708(b) of the
Code, it being understood and agreed that the Management Committee may require
as a condition to such transfer that the Partnership be furnished with an
appropriate opinion of counsel to the foregoing effect, which counsel and
opinion shall be satisfactory to the Management Committee; and
(e) the Management Committee has consented to the assignment (which
consent may be granted or withheld at the sole discretion of the Management
Committee).
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10.3 Management Committee Option. The Management Committee may elect to
---------------------------
treat an assignee who has not become a substituted Partner as a substituted
Partner in the place of his assignor should it deem, in its sole discretion,
that such treatment is in the best interest of the Partnership for any of its
purposes or for any of the purposes of this Agreement.
10.4 Amendment of Agreement. The Managing Partner will be required to
----------------------
prepare an amendment to this Agreement for signature by the Partners to reflect
the substitution of Partners. Until this Agreement is amended, an assignee
shall not become a substituted Partner.
10.5 Insolvency. Upon the bankruptcy, insolvency, dissolution, or other
----------
cessation to exist as a legal entity of a Partner not an individual, the
authorized representative of such entity shall have all the rights of a Partner
for the purpose of effecting the orderly winding up and disposition of the
business of such entity and such power as such entity possessed to constitute a
successor as an assignee of its interest in the Partnership and to join with
such assignee in making application to substitute such assignee as a Partner.
10.6 Special Restrictions Relating to Non-U.S. Persons. Each transferee of
-------------------------------------------------
an Interest shall certify whether or not such transferee is a U.S. person. Each
Partner shall notify the Managing Partner if it becomes a non-U.S. person within
30 days of such change. Prior to a disposition of a "United States Real
Property Interest," as defined in Code Section 897, or a distribution pursuant
to a disposition of a "United States Real Property Interest," each Partner
shall, if requested to do so by the Managing Partner, certify as to its U.S.
person status.
10.7 Amendments in Respect to Transfers; Admission of Partners. The
---------------------------------------------------------
Managing Partner, at the discretion of the Management Committee, shall promptly
amend any Partnership document listing the Partners from time to time to reflect
the admission, substitution or withdrawal of Partners. No such admission,
substitution or withdrawal shall be effective until all appropriate Partnership
documents are so amended.
ARTICLE XI
LOANS TO THE PARTNERSHIP
11.1 Authority to Borrow. Subject to the approval of the Management
-------------------
Committee and to the limitations elsewhere provided in this Agreement, the
Partnership may from time to time borrow such amounts from such persons
(including the Managing Partner or any other Partner and its affiliates) on such
security and payable on such terms as the Managing Partner may determine.
11.2 Loans From Partners. If a Partner shall, with the prior consent of
-------------------
the Management Committee, make any loan or loans to the Partnership or advance
money on its
26
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behalf, the amount of any such loan or advance shall not increase the Capital
Account of the lending Partner or entitle such lending Partner to any increase
in his share of the distributions of the Partnership or result in his having any
greater share of Partnership allocations of Net Profit and Net Loss. The amount
of any such loan or advance shall be a debt due from the Partnership to such
lending Partner, repayable upon such terms and conditions and bearing interest
at such rates as shall be mutually agreed upon by the lending Partner and the
Management Committee, and such loan or advance may, subject to approval of the
Management Committee, be secured by a mortgage, deed of trust, pledge, security
interest or other lien in or on any, all or substantially all of the properties
and other assets of the Partnership.
ARTICLE XII
BOOKS, RECORDS AND REPORTS
12.1 Books. The Partnership, at its expense, shall maintain books and
-----
records for the Partnership at the Managing Partner's designated office, and all
Partners shall have the right to inspect and examine such books and records, and
to copy them (at their own expense) during regular business hours.
12.2 Reports. The Partnership shall cause to be prepared and delivered
-------
to the Partners, at its expense, the following reports (all unaudited reports to
be certified by the Chief Financial Officer of the Managing Partner):
(a) Within 60 days after the end of the first three quarterly periods
of the Partnership's fiscal year, a quarterly report containing the following:
(i) a balance sheet, which may be unaudited;
(ii) a statement of income for the three-month period then
ended, and for the year to date at such quarter end, which may be unaudited;
(iii) a statement of changes in cash flow for the three-month
period then ended, and for the year to date at such quarter end, which may be
unaudited;
(iv) other pertinent information regarding the Partnership and
its activities during the three-month period covered by the report; and
(v) a statement setting forth in reasonable detail the services
rendered by the Managing Partner to the Partnership and the amounts charged for
those services.
27
<PAGE>
(b) Within 75 days after the end of each fiscal year of the
Partnership, all information concerning the Partnership reasonably necessary for
the preparation of the Partners' federal and state income tax returns.
(c) Within 90 days after the end of each fiscal year of the
Partnership, an annual report containing (i) a balance sheet as of the end of
its fiscal year and statements of income, Partners' equity and changes in
financial position, for the year then ended, all of which shall be prepared in
accordance with generally accepted accounting principles consistently applied
and accompanied by an auditor's report containing to the extent available an
unqualified opinion of an independent certified public accountant; and (ii) a
report of the activities of the Partnership during the period covered by the
report.
(d) Copies of any documents delivered to any institution providing
financing to the Partnership pursuant to the requirements of any Partnership
loan documents.
12.3 Accounting and Tax Decisions. Except as otherwise provided in
----------------------------
this Agreement, all decisions as to accounting and tax matters shall be made by
the Managing Partner and as directed by the Management Committee.
12.4 Income Tax Election and Proceedings.
-----------------------------------
(a) The Management Committee shall direct the Managing Partner to make
such elections under the tax laws of the United States, the several States and
other relevant jurisdictions as to the treatment of the Partnership's items of
income, gain, loss, deduction and credit and as to all other relevant matters as
it reasonably believes necessary, appropriate or desirable.
(b) In the event the Partnership is subject to administrative or
judicial proceedings for the assessment and collection of deficiencies for
federal, state or local taxes or for the refund of overpayments of federal,
state or local taxes arising out of a Partner's distributive share of the tax
items of the Partnership, the Managing Partner shall act as, and shall have the
power and duties assigned to, the "tax matters partner" under Code Sections
6221-6232 and the Regulations thereunder. The Partners agree to perform all
acts necessary under Code Section 6231 and the Regulations thereunder to
designate the Managing Partner as the "tax matters partner."
(c) No Partner shall, on such Partner's federal or state income tax
return, treat any "partnership item" (as defined in Code Section 6231(a)(3) and
the Regulations thereunder) in a manner which is inconsistent with the treatment
of such "partnership item" on the Partnership's return without first submitting
its proposed treatment to the other Partner for its advance review.
28
<PAGE>
12.5 Bank Accounts. The Managing Partner may designate from time to time
-------------
those persons authorized to execute checks and other items on the Partnership
bank accounts. The funds of the Partnership shall not be commingled with the
funds of any other person. The Managing Partner shall have fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing Partner's possession or control, and
it shall not employ, or take actions to permit another to employ, such funds or
assets in any manner except as provided in this Agreement.
ARTICLE XIII
DISSOLUTION AND TERMINATION OF THE PARTNERSHIP
AND THE LIQUIDATION OF A PARTNER'S
INTEREST IN THE PARTNERSHIP
13.1 Dissolution. Only the happening of any one of the following events
-----------
shall dissolve the Partnership:
(a) the expiration of the term of the Partnership;
(b) the expiration of 60 days after the Partnership's election to
dissolve the Partnership (provided that no Partner shall, without such approvals
as may be required from lenders providing financing to the Partnership in
accordance with the relevant loan or financing agreements, seek the dissolution
of the Partnership during the term of any such agreements);
(c) the entry of a decree of judicial dissolution of the Partnership
pursuant to the Act; or
(d) the occurrence of any event that would cause the dissolution of
the Partnership under the Act or that would make it unlawful for the business of
the Partnership to be continued.
13.2 Distributions in Liquidation of the Partnership and in Liquidation
------------------------------------------------------------------
of a Partner's Interest in the Partnership.
- ------------------------------------------
(a) In the event of a distribution in connection with the liquidation
of the Partnership, the occurrence of which is described in Section 13.4(b), the
Partnership shall apply and distribute the proceeds from the liquidation of the
assets of the Partnership and collection of the receivables of the Partnership,
together with assets distributed in kind, to the extent sufficient therefor, in
the following order of priority:
29
<PAGE>
(i) first, to the payment and discharge of all liabilities,
obligations and debts of the Partnership and the expenses of liquidation, paid
in the order then required by California law;
(ii) second, to the creation and setting up of any reserves which the
Management Committee may deem necessary, appropriate or desirable for any
future, contingent or unforeseen liabilities, obligations or debts of the
Partnership which are not yet payable or have not yet been paid. The
Partnership may pay, but is not obligated to pay, such reserves to an
independent escrow holder designated by the Management Committee, to be held by
it for the purpose of disbursing such reserves in payment of any of the
aforementioned liabilities, obligations and debts and, at the expiration of such
period as the Management Committee shall deem necessary, advisable or desirable,
to distribute the balance thereafter remaining in the manner hereinafter
provided;
(iii) third, to the payment and discharge of all of the liabilities,
obligations and debts of the Partnership owing to Partners, but if the amount
available for payment is insufficient, then pro rata in accordance with the
amount of those liabilities, obligations and debts; and
(iv) fourth, to the Partners with positive Capital Accounts, in
accordance with their respective Capital Account after taking into account all
Capital Account adjustments for the Partnership taxable year during which such
liquidation occurs (other than those made pursuant to this Section 13.2, or
Section 13.3).
(b) Except as otherwise provided in Regulation Section 1.704-
1(b)(2)(ii)(b), a distribution to a Partner in liquidation of such Partner's
interest in the Partnership (as described in Section 13.4(c)), but other than in
liquidation of the Partnership (the occurrence of which is described in Section
13.4(b)), shall be in an amount equal to each Partner's Capital Account after
taking into account all Capital Account adjustments for the Partnership taxable
year during which such liquidation occurs (other than those made pursuant to
this Section 13.2 or Section 13.3).
(c) For purposes of this Section 13.2, the Partnership taxable year
shall be determined without regard to Code Section 706(c)(2)(A).
13.3 Deficit Capital Account. Notwithstanding any other provision of
-----------------------
this Agreement to the contrary, upon liquidation of a Partner's interest in the
Partnership (whether or not in connection with the liquidation of the
Partnership), after all Capital Account adjustments for the taxable year during
which such liquidation occurs (other than those occurring as a result of any
contributions made pursuant to this Section 13.3), if such Partner has a
negative balance in its Capital Account, such Partner shall be obligated to pay
to the Partnership on or before the end of the taxable year in which such
liquidation occurs (or, if
30
<PAGE>
later, within ninety (90) days after the date of such liquidation) an amount in
cash equal to the difference between its negative Capital Account and zero.
13.4 Liquidation of the Partnership and Liquidation of a Partner's
-------------------------------------------------------------
Interest in the Partnership.
- ---------------------------
(a) For purposes of Sections 1.8, 5.1, 5.2 and 13.3, a liquidation of
a Partner's Interest in the Partnership occurs upon the earlier of (i) the date
upon which there is a liquidation of the Partnership or (ii) the date upon which
there is a liquidation of the Partner's Interest in the Partnership.
(b) For purposes of Section 13.4(a) and Sections 13.2(a) and 13.3, the
liquidation of the Partnership occurs upon the earlier of (i) the date upon
which the Partnership is terminated under Code Section 708(b)(1), or (ii) the
date upon which the Partnership ceases to be a going concern (even though it may
continue in existence for the purpose of winding up its affairs, paying its
debts, and distributing any remaining balance to its Partners).
(c) For purposes of Sections 13.4(a) and 13.2(b), the liquidation of a
Partner's Interest in the Partnership means the termination of a Partner's
entire Interest in the Partnership by means of a distribution, or a series of
distributions, to the Partner by the Partnership. A series of distributions
will come within the meaning of this term whether they are made in one year or
in more than one year. Where a Partner's Interest is to be liquidated by a
series of distributions, the Interest will not be considered as liquidated until
the final distribution has been made.
(d) The liquidation of a Partner's Interest in the Partnership, the
occurrence of which is described in Section 13.4(a), will not be delayed after
the Partnership's primary business activities have been terminated for a
principal purpose of deferring any distribution pursuant to Section 13.2(a)(iv),
or deferring a Partner's obligation under Section 13.3.
13.5 Time of Liquidation. Subject to Section 13.4(d) a reasonable time
-------------------
shall be allowed for the orderly liquidation of the assets of the Partnership
and the discharge of liabilities to creditors so as to enable the Partnership to
minimize to the extent it deems practicable, advisable or desirable the normal
losses attendant upon a liquidation.
13.6 Liquidation Statement. Each of the Partners shall be furnished
---------------------
with a statement prepared by the Partnership, which shall set forth the assets
and liabilities of the Partnership as of the date of complete liquidation. Upon
the Partnership complying with the foregoing distribution plan, the Partners
shall cease to be such and the Managing Partner may execute, acknowledge and
cause to be filed and recorded a certificate of cancellation of the Partnership
or other appropriate documents evidencing its dissolution and winding up.
31
<PAGE>
ARTICLE XIV
LIMITATION OF LIABILITY OF MANAGING PARTNER
AND INDEMNIFICATION OF THE MANAGING PARTNER AND OTHERS
14.1 Limitation on Liability of Managing Partner. None of (i) the
-------------------------------------------
Managing Partner in its capacity as such, or (ii) its officers, directors,
shareholders, employees or agents will be liable to the Partnership or the
Partners for any expense, loss or liability suffered by the Partnership or the
Partners in connection with the Partnership or its activities; provided that, in
the event such expense, loss or liability arose out of any action or inaction of
a Managing Partner or its affiliates or such other persons, as the case may be,
the foregoing shall only apply if (i) such course of conduct did not constitute
gross negligence, acts of bad faith or willful misconduct, and (ii) the Managing
Partner, its affiliates or such other persons, as the case may be, had
previously determined in good faith that such course of conduct was in the best
interests of the Partnership.
14.2 Indemnification of the Managing Partner.
---------------------------------------
(a) The Partnership shall indemnify and hold harmless the Managing
Partner, and its officers, directors, shareholders, employees and agents
(individually, an "Indemnitee") from and against any and all losses, claims,
demands, costs, damages, liabilities, joint and several, expenses of any nature
(including attorneys' fees and disbursements), judgments, fines, settlements and
other amounts arising from any and all claims, demands, actions, suits or
proceedings, civil, criminal, administrative or investigative, in which the
Indemnitee may be involved, or threatened to be involved, as a party or
otherwise arising out of or incidental to the business of the Partnership,
including without limitation liabilities under the federal and state securities
laws, regardless of whether the Indemnitee continues to be the Managing Partner,
or an officer, director, shareholder, employee or agent of the Managing Partner
at the time any such liability or expense is paid, if the Indemnitee's conduct
did not constitute actual fraud, willful misconduct or gross negligence and if
the Indemnitee acted in a manner it reasonably believed to be in the best
interests of the Partnership. The termination of any action, suit or proceeding
by settlement or upon a plea of nolo contendre, or its equivalent, shall not, in
and of itself, create a presumption or otherwise constitute evidence that the
Indemnitee acted in a manner contrary to that specified above.
(b) Reasonable expenses incurred by an Indemnitee in defending any
claim, demand, action, suit or proceeding subject to this Section 14.2 shall,
from time to time, be advanced by the Partnership prior to the final disposition
of such claim, demand, action, suit or proceeding upon receipt by the
Partnership of an undertaking by or on behalf of the Indemnitee to repay such
amount if it shall be determined that such person is not entitled to be
indemnified as authorized in this Section 14.2.
32
<PAGE>
(c) The indemnification provided by this Section 14.2 shall be in
addition to any other rights to which those indemnified may be entitled under
any agreement, vote of the Partners, as a matter of law or equity or otherwise,
both as to action in the Indemnitee's capacity as Managing Partner, as an
affiliate or as an officer, director, employee or agent of a Managing Partner or
an affiliate and as to any action in another capacity, and shall continue as to
an Indemnitee who has ceased to serve in such capacity and shall inure to the
benefit of the heirs, successors, assigns and administrators of the Indemnitee.
(d) The Partnership may purchase and maintain insurance, at the
Partnership's expense on behalf of the Managing Partner and such other persons
as the Management Committee shall determine, against any liability that may be
asserted against or expense that may be incurred by such person in connection
with the activities of the Partnership and/or the Managing Partner's acts or
omissions as Managing Partner of the Partnership regardless of whether the
Partnership would have the power to indemnify such person against such liability
under the provisions of this Agreement.
(e) Any indemnification hereunder shall be satisfied solely out of the
assets of the Partnership. No Partner shall be subject to personal liability by
reason of these indemnification provisions.
(f) An Indemnitee shall not be denied indemnification in whole or in
part under this Section 14.2 by reason of the fact that the Indemnitee had an
interest in the transaction with respect to which the indemnification applies if
the transaction was otherwise permitted by the terms of this Agreement.
(g) The provisions of this Section 14.2 are for the benefit of the
Indemnitees, their heirs and personal representatives, and shall not be deemed
to create any rights for the benefit of any other person.
14.3 Management Committee Indemnification. The Partnership shall
------------------------------------
indemnify and save harmless the delegates to the Management Committee, including
the alternates, against all actions, claims, demands, costs and liabilities
arising out of the acts (or failure to act) of any such person in good faith
within the scope of their authority in the course of the Partnership's business,
and such persons shall not be liable for any obligations, liabilities or
commitments incurred by or on behalf of the Partnership as a result of any such
acts or failure to act, provided that the foregoing shall not entitle a member
to indemnification for gross negligence or willful misconduct.
14.4 Survival of Rights. The rights of the Managing Partner, and its
------------------
respective officers, directors, shareholders, employees or agents under this
Article XIV shall survive the termination of the Managing Partner's status as a
Partner of the Partnership.
33
<PAGE>
ARTICLE XV
GENERAL PROVISIONS
15.1 Arbitration. Any controversy or claim arising out of or relating to
-----------
this Agreement, or the breach thereof, which cannot be settled by agreement of
the Partners, shall be settled by arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association and judgment upon the
award rendered thereunder may be entered in any court having jurisdiction
thereof.
15.2 Notices.
-------
(a) Except as otherwise provided herein, any notice, distribution,
offer, report or other communication that is to be given to any Partner in
connection with the Partnership or this Agreement shall be in writing and shall
be sent in person by first-class mail, by telecopy, or by nationally recognized
overnight courier services to the address set forth below or to such other
address as a Partner may notify the Management Committee in writing, and shall
be deemed delivered upon receipt.
NEW CTC: NEW CTC Company, LLC
c/o Caithness Power, L.L.C.
1114 Avenue of the Americas
New York, New York 10036-7790
Attention: General Counsel
Telefacsimile: (212) 921-9239
CCH: Caithness Navy II Group, LLC
c/o Caithness Power, L.L.C.
1114 Avenue of the Americas
New York, New York 10036-7790
Attention: General Counsel
Telefacsimile: (212) 921-9239
(b) Copies of any notices provided to any Partner in connection with
any loan documents or other financing documents (or any documents relating
thereto) shall be forwarded to each other Partner promptly upon receipt.
(c) Copies of any notices provided to any Partner in connection with
any documents relating to the Partnership's rights in the Project, or loan
documents or other financing documents (or any documents relating thereto) shall
be forwarded to each other Partner promptly upon receipt.
34
<PAGE>
15.3 Survival of Rights. This Agreement shall be binding upon, and, as to
------------------
permitted or accepted successors, transferees and assigns, inure to the benefit
of the Partners and the Partnership and their respective heirs, legatees, legal
representatives, successors, transferees and assigns, in all cases whether by
the laws of descent and distribution, merger, reverse merger, consolidation,
sale of assets, other sale, operation of law or otherwise.
15.4 Construction. The language in all parts of this Agreement shall be
------------
in all cases construed simply according to its fair meaning and not strictly for
or against the Partners or the Managing Partner.
15.5 Section Headings. The captions of the Articles or Sections in this
----------------
Agreement are for convenience only and in no way define, limit, extend or
describe the scope or intent of any of the provisions hereof, shall not be
deemed part of this Agreement and shall not be used in construing or
interpreting this Agreement.
15.6 Agreement in Counterparts. This Agreement and any amendments hereto
-------------------------
may be executed in multiple counterparts, each of which shall be deemed an
original agreement and all of which shall constitute one and the same agreement,
notwithstanding the fact that all parties are not signatories to the original or
the same counterpart. For purposes of recording this instrument, if required,
multiple signature pages and acknowledgment pages may be attached to each
counterpart; the signature pages and the acknowledgment pages pertaining thereto
may be detached from the counterpart, when executed, and attached to another
counterpart, which other counterpart may thereafter be recorded.
15.7 Governing Law. This Agreement shall be construed according to the
-------------
internal laws, but not the laws pertaining to choice or conflict of laws, of the
State of California.
15.8 Additional Documents. Each Partner, upon the request of the
--------------------
Management Committee, agrees to perform all further acts and execute,
acknowledge and deliver all further documents which may be reasonably necessary,
appropriate or desirable to carry out the provisions of this Agreement,
including but not limited to acknowledging before a notary public any signature
heretofore or hereafter made by a Partner.
15.9 Severability. Should any portion or provision of this Agreement be
------------
declared illegal, invalid or unenforceable in any jurisdiction, then such
portion or provision shall be deemed to be severable from this Agreement as to
such jurisdiction (but, to the extent permitted by law, not elsewhere) and in
any event such illegality, invalidity or unenforceability shall not affect the
remainder hereof.
15.10 Pronouns and Plurals. Whenever the context may require, any pronoun
--------------------
used in this Agreement shall include the corresponding masculine, feminine or
neuter forms, and the singular form of nouns, pronouns and verbs shall include
the plural and vice versa.
35
<PAGE>
15.11 Third-Party Beneficiaries. There are no third-party beneficiaries
-------------------------
of this Agreement.
15.12 Partition. The Partners agree that any assets the Partnership may
---------
at any time have may not be suitable for partition. Each Partner hereby
irrevocably waives any and all rights that he may have to maintain any action
for partition of any assets the Partnership may at any time have.
15.13 Security Interest and Right of Set-Off. As security for any
--------------------------------------
withholding tax or other liability or obligation to which the Partnership may be
subject as a result of any act or status of any Partner or to which the
Partnership becomes subject with respect to the Interests of any Partner, the
Partnership shall have (and each Partner hereby grants to the Partnership) a
security interest in all Cash Flow from Operations or Cash Flow from Capital
Events distributable to such Partner to the extent of the amount of such
withholding tax or other liability or obligation. The Partnership shall have a
right to setoff against any such cash distributable in the amount of such
withholding tax or other liability or obligation.
15.14 Entire Agreement. This Agreement delivered by the Partners
----------------
constitutes the entire agreement of the Partners with respect to, and supersedes
all prior written and prior and contemporaneous oral agreements, understandings
and negotiations with respect to the subject matter hereof.
15.15 Waiver. No failure by any party to insist upon the strict
------
performance of any covenant, duty, agreement or condition of this Agreement or
to exercise any right or remedy consequent upon a breach thereof shall
constitute a waiver of any such breach or any other covenant, duty, agreement or
condition.
15.16 Attorneys' Fees. In the event of any litigation or arbitration
---------------
between the parties hereto with respect to the subject matter hereof, the
unsuccessful party to such litigation or arbitration shall pay to the successful
party all costs and expenses, including, without limitation, reasonable
attorneys' fees and expenses, incurred therein by the successful party, all of
which shall be included in and as a part of the judgment or decision rendered in
such litigation or arbitration.
36
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of
the date first set forth above.
COSO POWER DEVELOPERS,
a California general partnership
By: New CTC Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ Christopher T. McCallion
--------------------------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness Navy II Group, LLC,
a Delaware limited liability company
its General Partner
By: Caithness Geothermal 1980 Ltd., L.P.,
a Delaware limited partnership
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
--------------------------------------------
Christopher T. McCallion
Executive Vice President
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
--------------------------------------------
Christopher T. McCallion
Executive Vice President
37
<PAGE>
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ Christopher T. McCallion
--------------------------------------------
Christopher T. McCallion
Executive Vice President
By: Dominion Energy, Inc.,
a Virginia corporation,
its Member
By: /s/ James W. Braswell
-----------------------------------------------
Name: James W. Braswell
Its: Vice President
38
<PAGE>
EXHIBIT A
NAVY II PROJECT AREA
--------------------
All of Section 16, all of Section 17, and the East half of Section 18, all
located in Township 22 South, Range 39 East, Mount Diablo Base and Meridan, in
the County of Inyo, State of California.
A-1
<PAGE>
EXHIBIT B
TRANSMISSION LINE DESCRIPTION
-----------------------------
Parcel A
- --------
Parcel A of the Coso-Inyokern transmission line corridor begins at
survey station 0+00 at the Inyokern substation in the SE3, SE3 of Section 20,
T26S, R39E, in Kern County, California and goes Northerly approximately 27 miles
ending at survey station 1380+00 NWC/BLM Geothermal Plant No. 1 Switchyard in
SE3, NW3 of Section 19, T22S, R39E in Inyo County, California. The transmission
line is located entirely within the boundaries of the China Lake Naval Weapons
Center.
The corridor for the transmission line is the eastern portion of a
common corridor which is a strip of land 200 feet wide of which 65 feet of this
corridor is located to the left (Westerly) of the 115 kV transmission line
centerline and 135 feet is located to the right (Easterly) of the 115 kV
transmission line centerline from station 0+00 to station 731+59.27. From
station 731+59.27 to station 1245+11.06, the corridor is a strip of land 250
feet wide of which 100 feet is located to the left (Westerly) and 150 feet is
located to the right (Easterly) of the 115 kV transmission line centerline.
From station 1245+11.06 to station 1291+52.54, the corridor is a strip of land
300 feet wide of which 100 feet of this corridor is located to the left
(Westerly) and 200 feet is located to the right (Easterly) of the 115 kV
transmission line centerline. From station 1291+52.54 to Station 1380+00 the
corridor is a strip of land 250 feet wide of which 100 feet is located to the
left (Westerly) and 150 feet is located to the right (Easterly) of the 115 kV
transmission line centerline.
The transmission corridor centerline is described as follows:
Sections 20, 7, 8, 5, and 6 of T26S, R39E
-----------------------------------------
Beginning at survey station 0+00, which is located on the North boundary fence
line of the Inyokern substation and is 400 feet West, more or less, and 320 feet
North, more or less, of the SE Corner of Section 20, T26S, R39E. Thence, from
station 0+00, N21 degrees 11'57"W a distance of 255.00 feet to an angle point at
station 2+55.00; thence N17 degrees 40'18"W a distance of 21,637 feet, more or
less, to the Leliter Road crossing at station 218+92 which is a point on the
North boundary of Section 6, T26S, R39E and 1410 feet West, more or less, of the
NE Corner of Section 6, T26S, R39E.
B-1
<PAGE>
Sections 31, 30 and 19 of T25S, R39E
------------------------------------
Thence, from station 218+92, N17 degrees 40'18"W a distance of 13,228 to station
351+20 which is a point on the West boundary of Section 19, T25S, R39E and is
1960 feet North, more or less, of the SW Corner of Section 19, T25S, R39E.
Sections 24, 13, 12, 1 and 2 of T25S, R38E
------------------------------------------
Thence, from station 351+20, N17 degrees 40'18"W a distance of 20,165 feet, to
survey station 552+85 which is a point on the Kern and Inyo County Line and on
the North boundary of Section 2, T25S, R38E and is 540 feet West, more or less,
of the NE Corner of Section 2, T25S, R38E.
Sections 35, 34, 27, 22, 15, 10 and 3 of T24S, R38E
---------------------------------------------------
Thence, from station 552+85, N17 degrees 40'18"W a distance of 980.65 feet to an
angle point at station 562+65.65; thence, N00 degrees 32'59"E a distance of
1849.86 feet to an angle point at station 581+15.51; thence N18 degrees 55'43"W
a distance of 8200.72 feet to an angle point at station 663+16.23; thence N17
degrees 49'44"W a distance of 6844.77 feet to an angle point at station
731+59.27; thence, N09 degrees 26'36"E a distance of 13,279.45 feet to an angle
point at equation station 864+40.45 Back and 873+76 Ahead; thence N07 degrees
43'29"E a distance of 1460 feet to survey station 888+39.76 which is a point on
the North boundary of Section 3, T24S, R38E and is 1680 feet West, more or less,
of the NE Corner of Section 3, T24S, R38E.
Sections 34, 27, 26, 23, 24, 13, 12 and 1 of T23S, R38E
-------------------------------------------------------
Thence, from station 888+39.76, N07 degrees 43'29"E a distance of 5111.45 feet
to an angle point at station 939+51.21; thence N31 degrees 43'12"E a distance of
9820.50 feet to an angle point at station 1037+71.71; thence N31 degrees 14'47"E
a distance of 10,758.97 feet to an angle point at station 1145+30.68; thence N10
degrees 29'29"W a distance of 8780.38 feet to survey station 1233+11.06 which is
a point on the North boundary of Section 1, T23S, R38E and is 1600 feet West,
more or less, of the NE Corner of Section 1, T23S, R38E.
Section 36 of T22S, R38E
------------------------
Thence, from station 1233+11.06, N10 degrees 29'29"W a distance of 1200.00 feet
to an angle point at station 1245+11.06; thence N43 degrees 08'19"E a distance
of 2718.94 feet to survey station 1272+30 which is a point on the East boundary
of Section 36, T22S, R38E and is 2180 feet South, more or less, of the NE Corner
of Section 36, T22S, R38E.
B-2
<PAGE>
Sections 31, 30 and 19 of T22S, R39E
------------------------------------
Thence, from station 1272+30, N43 degrees 08'19"E a distance of 1922.34 feet to
an angle point at station 1291+52.34; thence N06 degrees 45'07"E a distance of
8634.99 feet to the end of Parcel A of the Coso-Inyokern transmission line
corridor at survey station 1380+00. This point is located at the NWC-BLM
Geothermal Plant No. 1 switchyard in the SE3, NW3 of Section 19, T22S, R39E in
Inyo County, California.
Parcel B
- --------
Parcel B of the Coso-Inyokern 230 kV transmission line corridor begins
at station 0+00 at BLM (West) Geothermal Plant No. 1 switchyard in the SE 3, NW
3 of Section 19, T22S, R39E in Inyo County, California and extends to station
77+57.20 BLM (East) Geothermal Plant No. 2 switchyard in the S2 of Section 20,
T22S, R39E. The transmission line is located entirely within the boundaries of
the China Lake Naval Weapons Center.
This portion of the corridor is a strip of land 100 feet wide of which
50 feet of this corridor is located left (Northerly) and 50 feet is located
right (Southerly) of centerline of the corridor.
The transmission centerline is described as follows:
Sections 19 and 20 of T22S, R39E
--------------------------------
Beginning at survey station 0+00, BLM (West) Geothermal Plant No. 1 switchyard,
which is located at S52 degrees W 4035 feet, more or less, from the NE corner of
Section 19, T22S, R39E; thence N83 degrees 00'00"E, a distance of 350.00 feet to
an angle point at station 3+50.00; thence N42 degrees 55'19"E a distance of
469.21 feet to an angle point at station 8+19.21; thence N84 degrees 34'06"E, a
distance of 1148.23 feet to an angle point at station 19+67.44; thence N72
degrees 42'43"E a distance of 1445.45 feet to an angle point at equation station
34+12.89 back and 34+12.04 ahead; thence S53 degrees 05'47"E a distance of
2075.45 feet to an angle point at station 54+87.49; thence S08 degrees 59'02"E a
distance of 1301.63 feet to an angle point at station 67+89.12; thence S42
degrees 29'52"E a distance of 468.25 feet to an angle point at station 72+57.37;
thence N47 degrees 49'10"E a distance of 359.83 feet to an angle point at
station 76+17.20; thence N76 degrees 15'49"E a distance of 140.00 feet to the A-
Frame structure at station 77+57.20. This point is located at BLM (East)
Geothermal Plant No. 2 switchyard, S32 degrees W 5,080 feet plus or minus from
the NE corner of Section 20, T22S, R39E in Inyo County, California, and is the
end of Parcel B Coso-Inyokern transmission line corridor.
B-3
<PAGE>
Parcel C
- --------
Parcel C of the Coso-Inyokern 230 kV transmission line corridor begins
at station 0+00 at BLM (East) Geothermal Plant No. 2 switchyard in the S2 of
Section 20, T22S, R39E in Inyo County, California and extends to station
70+58.51 Navy II Geothermal Plant switchyard in Section 17, T22S, R39E. The
transmission line is located entirely within the boundaries of the China Lake
Naval Weapons Center.
This portion of the corridor is a strip of land 100 feet wide of which
50 feet of this corridor is located left (Westerly) and 50 feet is located right
(Easterly) of centerline of the corridor.
The transmission centerline is described as follows:
Sections 17 and 20 of T22S, R39E
--------------------------------
Beginning at survey station 0+00, BLM (East) Geothermal Plant No. 2 switchyard,
which is located S32 degrees W 5040 feet, more or less, from the NE corner of
Section 20, T22S, R39E; thence N76 degrees 58'47" W, a distance of 76.36 feet to
an angle point at station 0+76.36; thence N06 degrees 46'21"W, a distance of
2483.22 feet to an angle point at station 25 + 59.52; thence N19 degrees
32'09"E, a distance of 2513.26 feet to an angle point at station 50 + 72.82;
thence N63 degrees 57'16" W, a distance of 1169.08 feet to an angle point at
station 62 + 41.90; thence N18 degrees 16'46"W, a distance of 394.50 feet to an
angle point at station 66 + 36.40; thence N37 degrees 00'00"E, a distance of
422.11 feet to the A-Frame structure at station 70+58.51. This point is located
at Navy II Geothermal Plant switchyard, S42 degrees W 4,580 feet plus or minus
from the NE corner of Section 17, T22S, R39E in Inyo County, California and is
the end of Parcel C Coso-Inyokern transmission line corridor.
B-4
<PAGE>
EXHIBIT C
ESCROW ACCOUNT DISTRIBUTION PROVISIONS
--------------------------------------
1. Amounts deposited in the Escrow Account with respect to a Preferred
Return Year shall be distributed promptly after it is determined whether the
Distribution Condition is satisfied with respect to that Preferred Return Year,
as follows:
(a) if the Distribution Condition was satisfied for the Preferred
Return Year:
(i) first, to CCH, ESCA and Navy II Group, as directed in
writing by an authorized representative thereof, until distributions pursuant to
this Section 1(a)(i) equal the lesser of (a) the Maximum Payment for the
Preferred Return Year, and (b) the amount or deposit in the Escrow Account;
(ii) the balance to the Managing Partner; or
(b) to the Managing Partner, if the Distribution Condition was not
satisfied for the Preferred Return Year.
2. Amounts deposited in the Escrow Account pursuant to Sections
5.2(a)(ii) of the CPD and CED Partnership Agreements and Sections 5.3(a)(ii) and
5.4(a)(ii) of the CFP Partnership Agreement shall be distributed within fifteen
days after deposit to CCH, ESCA and Navy II Group, as directed in writing by an
authorized representative thereof.
3. All amounts distributed pursuant to Section 1(a)(i) and Section 2 will
be applied (i) first, to reduce Preferred Return Interest, and (ii) second, to
reduce the Preferred Return.
4. For the purpose of Section 1, ADistribution Condition" means the
generation of Excess Revenues by at least one Project during the Preferred
Return Year.
C-1
<PAGE>
EXHIBIT 3.6
AMENDMENT AGREEMENT
-------------------
(CFP)
This AMENDMENT AGREEMENT ("Agreement") is entered into and is effective as
of this 28 day of May, 1999, by and among COSO FINANCE PARTNERS, a California
general partnership ("CFP"), CAITHNESS ACQUISITION COMPANY, LLC, a Delaware
limited liability company ("CAC"), NEW CLOC COMPANY, LLC ("New CLOC"), a
Delaware limited liability company, ESCA, LLC, a Delaware limited liability
company ("ESCA") and COSO OPERATING COMPANY LLC ("COC"), a Delaware limited
liability company.
RECITALS
--------
WHEREAS, CFP is a California general partnership that is the owner of a
geothermal power facility located in Inyo County, California, commonly known as
the Navy I Project (the "Project");
WHEREAS, CFP was, prior to February 25, 1999, co-owned by ESCA Limited
Partnership (predecessor to ESCA), an affiliate of Caithness Energy, L.L.C., a
Delaware limited liability company ("Caithness Energy") and China Lake Operating
Company ("CLOC"), a former affiliate of CalEnergy Company, Inc., a Delaware
corporation ("CalEnergy"). CFP was constituted under the General Partnership
Agreement of CFP, as amended (the "Partnership Agreement") and was managed by
COC, previously a wholly owned subsidiary of CalEnergy, as assignee of
CalEnergy, pursuant to two Operations and Maintenance Agreements (the "O&M
Agreements");
WHEREAS, CLOC previously served as the Managing General Partner and COC
previously served as the Operator of the Project, in consideration for which
CLOC and COC received a management fee (the "Management Fee") and operator fees
(the "Operator Fees") in accordance with the Partnership Agreement and O&M
Agreements. CLOC also received a fee in consideration for its participation as
a member of the Management Committee of CFP (the "Committee Fee");
WHEREAS, on February 25, 1999, CLOC was merged with and into New CLOC, a
wholly owned subsidiary of CAC itself a wholly owned subsidiary of Caithness
Energy. In addition, CAC acquired COC;
WHEREAS, New CLOC, as successor to CLOC, now serves as the Managing General
Partner of CFP;
WHEREAS, COC, now a wholly owned subsidiary of CAC, in conjunction with FPL
Energy Operating Services, Inc., now serves as the Operator of the Project;
WHEREAS, CAC, as sole parent of New CLOC and COC, has agreed to a large
reduction in the amount of the Management Fee and has negotiated a reduction in
Operator Fees
<PAGE>
from those fees previously in effect. Furthermore, New CLOC has agreed to
eliminate the Committee Fee. These reductions in fees are in the best interests
of CFP and will have the effect of bringing the amount the Management Fee and
Operating Fees more in line with the actual cost of running the Project.
WHEREAS, CAC, as parent of New CLOC and COC, has also agreed that the right
to receive the Management Fee and Operator Fees payable to COC shall be
subordinate to debt service payments. This will reverse the prior arrangement,
pursuant to which debt service payments were subordinate to CLOC and COC's
rights to receive the Management Fee and Operator Fees. This will constitute a
substantial benefit to CFP as it will increase the amount of cash available for
debt service;
WHEREAS, in consideration for CAC's agreement to cause its subsidiaries to
amend the Partnership Agreement and O&M Agreements with COC to reflect the
restructuring of these fees and to negotiate lower operating fees with FPL
Operating Services, Inc., ESCA has agreed to pay to CAC a one-time fee that will
represent its share of the net present value of the savings that will result
from the restructuring of the fee payments over the next ten years.
NOW, THEREFORE, in consideration of the foregoing Recitals, which are by
this reference incorporated herein, and for other good and valuable
consideration, the receipt of which is hereby acknowledged, the parties hereto
agree as follows:
AGREEMENT
1. Reduction and Subordination of Fees. CAC, as parent of New CLOC and
-----------------------------------
COC, hereby agrees to cause New CLOC and COC to execute and deliver an amended
Partnership Agreement and O&M Agreement reflecting a reduction in the amount of
the Management Fee payable to ESCA and Operator Fees payable to COC and
elimination of the Committee Fee payable to New CLOC.
2. Subordination of Fees. CAC also agree that it will cause COC to
---------------------
execute an agreement pursuant to which its right to receive Operator Fees shall
be subordinate to debt service payments on account of the new senior secured
debt.
3. Fee Buy Down Amount. The net present value of aggregate amount of the
-------------------
savings over the next ten years to CFP resulting from CAC's agreement to cause
New CLOC and COC to execute and deliver an amended Partnership Agreement and O&M
Agreement is approximately $17,214,000 (the "Fee Buy Down Amount").
4. Payment by ESCA. Upon execution of the amended Partnership Agreement
---------------
and new O&M Agreement described in Section 1 and solely from funds received by
ESCA from distributions in connection with the refinancing of the senior debt of
CFP, ESCA shall pay to
2
<PAGE>
CAC, as designee of New CLOC and COC, in consideration for CAC's acceptance of
the provisions herein, the sum of $9,226,000, which represents ESCA's share of
the Fee Buy Down Amount equal to ESCA, LLC's proportionate ownership of CFP.
5. Further Assurances. The parties hereto agree that, at any times and
------------------
from time to time, upon the written request of the other, such party will
promptly and duly execute and deliver any and all such further instruments and
documents and take such further action as the other party may reasonably request
in order to obtain the full benefit of the this Agreement.
6. Severability. Any provision of this Agreement which is prohibited,
------------
unenforceable or not authorized in any jurisdiction shall, as to such
jurisdiction, be ineffective to the extent of such prohibition, unenforceability
or non-authorization, without invalidating the remaining provisions hereof or
affecting the validity, enforceability or legality of such provision in any
other jurisdiction.
7. Successors and Assigns. Whenever in this Agreement any of the parties
----------------------
hereto is named or referred to, successors and assigns of such party shall be
deemed to be included and all covenants, promises and agreements in this
Agreement by and on behalf of the respective parties hereto shall be binding
upon and inure to the benefit of the respective successors and permitted assigns
of such parties, whether so expressed or not.
8. Governing Law. This Agreement shall be governed by, interpreted
-------------
under, and construed and enforced in accordance with the laws of the State of
California.
9. Amendments and Waivers. This Agreement may be amended only by a
----------------------
writing signed by the parties hereto. No amendment or waiver of any provision
of this Agreement nor consent by any party or any departure by any other party
herefrom shall in any event be effective unless the same shall be in writing and
signed by the party to be charged thereby. Any such waiver or consent shall be
effective only in the specific instance and for the specific purpose for which
given. No failure on the part of any party hereto to exercise, and no delay in
exercising, any right hereunder shall operate as a waiver thereof (except as
expressly provided herein) nor shall any single or partial exercise or any right
hereunder preclude any other or further exercise thereof or the exercise of any
other right.
10. Headings. The section headings in this Agreement are included herein
--------
for convenience of reference only and shall not constitute a part of this
Agreement for any other purpose.
11. Counterparts. This Agreement may be executed in any number of
------------
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
3
<PAGE>
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
Effective Date.
CAITHNESS ACQUISITION COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
NEW CLOC COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
COSO OPERATING COMPANY LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
ESCA, LLC,
a Delaware limited liability company
By: Caithness Geothermal 1980 Ltd., L.P.,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
4
<PAGE>
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: ESI Geothermal, Inc.,
a Florida corporation,
its Member
By: /s/ Kenneth P. Hoffman
----------------------------------------------
Name: Kenneth P. Hoffman
-------------------------------------------
Title: Vice President
------------------------------------------
5
<PAGE>
COSO FINANCE PARTNERS,
a California general partnership
By: New CLOC Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: ESCA, LLC,
a Delaware limited liability company,
its General Partner
By: Caithness Geothermal 1980 Ltd., L.P.,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ James D. Bishop, Jr.
----------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: ESI Geothermal, Inc.,
a Florida corporation,
its Member
By: /s/ Kenneth P. Hoffman
----------------------------------------------
Name: Kenneth P. Hoffman
Title: Vice President
6
<PAGE>
Exhibit 3.7
AMENDMENT AGREEMENT
-------------------
(CED)
This AMENDMENT AGREEMENT ("Agreement") is entered into and is effective as
of this 28 day of May, 1999, by and among COSO ENERGY DEVELOPERS, a California
general partnership ("CED"), CAITHNESS ACQUISITION COMPANY, LLC, a Delaware
limited liability company ("CAC"), NEW CHIP COMPANY, LLC ("New CHIP"), a
Delaware limited liability company, CAITHNESS COSO HOLDINGS, LLC, a Delaware
limited liability company ("CCH") and COSO OPERATING COMPANY LLC ("COC"), a
Delaware limited liability company.
RECITALS
--------
WHEREAS, CED is a California general partnership that is the owner of a
geothermal power facility located in Inyo County, California, commonly known as
the BLM (the "Project");
WHEREAS, CED was, prior to February 25, 1999, co-owned by Caithness Coso
Holdings, L.P. (predecessor to CCH), an affiliate of Caithness Energy, L.L.C., a
Delaware limited liability company ("Caithness Energy") and Coso Hotsprings
Intermountain Power ("CHIP"), a former affiliate of CalEnergy Company, Inc., a
Delaware corporation ("CalEnergy"). CED was constituted under the General
Partnership Agreement of CED, as amended (the "Partnership Agreement") and was
managed by COC, previously a wholly owned subsidiary of CalEnergy, as assignee
of CalEnergy, pursuant to two Operations and Maintenance Agreements (the "O&M
Agreements");
WHEREAS, CHIP previously served as the Managing General Partner and COC
previously served as the Operator of the Project, in consideration for which
CHIP and COC received a management fee (the "Management Fee") and operator fees
(the "Operator Fees") in accordance with the Partnership Agreement and O&M
Agreements. CHIP also received a fee in consideration for its participation as
a member of the Management Committee of CED (the "Committee Fee");
WHEREAS, on February 25, 1999, CHIP was merged with and into New CHIP, a
wholly owned subsidiary of CAC itself a wholly owned subsidiary of Caithness
Energy. In addition, CAC acquired COC;
WHEREAS, New CHIP, as successor to CHIP, now serves as the Managing General
Partner of CED;
WHEREAS, COC, now a wholly owned subsidiary of CAC, in conjunction with FPL
Energy Operating Services, Inc., now serves as the Operator of the Project;
<PAGE>
WHEREAS, CAC, as sole parent of New CHIP and COC, has agreed to a large
reduction in the amount of the Management Fee and has negotiated a reduction in
Operator Fees from those fees previously in effect. Furthermore, New CHIP has
agreed to eliminate the Committee Fee. These reductions in fees are in the best
interests of CED and will have the effect of bringing the amount the Management
Fee and Operating Fees more in line with the actual cost of running the Project.
WHEREAS, CAC, as parent of New CHIP and COC, has also agreed that the right
to receive the Management Fee and Operator Fees payable to COC shall be
subordinate to debt service payments. This will reverse the prior arrangement,
pursuant to which debt service payments were subordinate to CHIP and COC's
rights to receive the Management Fee and Operator Fees. This will constitute a
substantial benefit to CED as it will increase the amount of cash available for
debt service;
WHEREAS, in consideration for CAC's agreement to cause its subsidiaries to
amend the Partnership Agreement and O&M Agreements to reflect the restructuring
of these fees and to negotiate lower operating fees with FPL Energy Operating
Services, Inc., CCH has agreed to pay to CAC a one-time fee that will represent
its share of the net present value of the savings that will result from the
restructuring of the fee payments over the next ten years.
NOW, THEREFORE, in consideration of the foregoing Recitals, which are by
this reference incorporated herein, and for other good and valuable
consideration, the receipt of which is hereby acknowledged, the parties hereto
agree as follows:
AGREEMENT
1. Reduction and Subordination of Fees. CAC, as parent of New CHIP and
-----------------------------------
COC, hereby agrees to cause New CHIP and COC to execute and deliver an amended
Partnership Agreement and O&M Agreement reflecting a reduction in the amount of
the Management Fee payable to CCH and Operator Fees payable to COC and
elimination of the Committee Fee payable to New CHIP.
2. Subordination of Fees. CAC also agree that it will cause COC to
---------------------
execute an agreement pursuant to which its right to receive Management Fees
shall be subordinate to debt service payments on account of the new senior
secured debt.
3. Fee Buy Down Amount. The net present value of aggregate amount of the
-------------------
savings over the next ten years to CED resulting from CAC's agreement to cause
New CHIP and COC to execute and deliver an amended Partnership Agreement and O&M
Agreement is approximately $17,214,000 (the "Fee Buy Down Amount").
2
<PAGE>
4. Payment by CCH, LLC. Upon execution of the amended Partnership
-------------------
Agreement and new O&M Agreement described in Section 1 and solely from funds
received by CCH from distributions in connection with the refinancing of the
senior debt of CED, CCH shall pay to CAC, as designee of New CHIP and COC, in
consideration for CAC's acceptance of the provisions herein, the sum of
$8,951,000, which represents CCH's share of the Fee Buy Down Amount equal to
CCH's proportionate ownership of CED.
5. Further Assurances. The parties hereto agree that, at any times and
------------------
from time to time, upon the written request of the other, such party will
promptly and duly execute and deliver any and all such further instruments and
documents and take such further action as the other party may reasonably request
in order to obtain the full benefit of the this Agreement.
6. Severability. Any provision of this Agreement which is prohibited,
------------
unenforceable or not authorized in any jurisdiction shall, as to such
jurisdiction, be ineffective to the extent of such prohibition, unenforceability
or non-authorization, without invalidating the remaining provisions hereof or
affecting the validity, enforceability or legality of such provision in any
other jurisdiction.
7. Successors and Assigns. Whenever in this Agreement any of the parties
----------------------
hereto is named or referred to, successors and assigns of such party shall be
deemed to be included and all covenants, promises and agreements in this
Agreement by and on behalf of the respective parties hereto shall be binding
upon and inure to the benefit of the respective successors and permitted assigns
of such parties, whether so expressed or not.
8. Governing Law. This Agreement shall be governed by, interpreted
-------------
under, and construed and enforced in accordance with the laws of the State of
California.
9. Amendments and Waivers. This Agreement may be amended only by a
----------------------
writing signed by the parties hereto. No amendment or waiver of any provision
of this Agreement nor consent by any party or any departure by any other party
herefrom shall in any event be effective unless the same shall be in writing and
signed by the party to be charged thereby. Any such waiver or consent shall be
effective only in the specific instance and for the specific purpose for which
given. No failure on the part of any party hereto to exercise, and no delay in
exercising, any right hereunder shall operate as a waiver thereof (except as
expressly provided herein) nor shall any single or partial exercise or any right
hereunder preclude any other or further exercise thereof or the exercise of any
other right.
10. Headings. The section headings in this Agreement are included herein
--------
for convenience of reference only and shall not constitute a part of this
Agreement for any other purpose.
3
<PAGE>
11. Counterparts. This Agreement may be executed in any number of
------------
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
Effective Date.
CAITHNESS ACQUISITION COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
NEW CHIP COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
CAITHNESS COSO HOLDINGS, LLC,
a Delaware limited liability company
By: Caithness CEA Geothermal, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness BLM Group, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Geothermal 1980 Ltd., L.P.
a Delaware limited partnership
its General Partner
4
<PAGE>
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Geothermal 1980 Ltd., Special Group I, L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: West Coast Geothermal Ltd., L.P.,
a Delaware limited partnership
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Pacific Geothermal Ltd., L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
5
<PAGE>
By: Mt. Whitney Geothermal Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Dominion Energy, Inc.,
a Virginia corporation,
its Limited Partner
By: /s/ James W. Braswell
--------------------------------------
Name: James W. Braswell
Its: Vice President
6
<PAGE>
COSO OPERATING COMPANY LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
COSO ENERGY DEVELOPERS,
a California general partnership
By: New CHIP Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ James D. Bishop, Jr
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Coso Holdings, LLC,
a Delaware limited liability company,
its General Partner
By: Caithness CEA Geothermal, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness BLM Group, L.P.,
a Delaware limited partnership,
its Member
By: Caithness Geothermal 1980 Ltd., L.P.
a Delaware limited partnership
its General Partner
7
<PAGE>
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Geothermal 1980 Ltd., Special Group I, L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: West Coast Geothermal Ltd., L.P.,
a Delaware limited partnership
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Pacific Geothermal Ltd., L.P.,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------------
James D. Bishop, Jr.
Vice Chairman
8
<PAGE>
By: Mt. Whitney Geothermal Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
----------------------------------------
Christopher T. McCallion
Executive Vice President
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its General Partner
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
----------------------------------------
Christopher T. McCallion
Executive Vice President
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ Christopher T. McCallion
----------------------------------------
Christopher T. McCallion
Executive Vice President
By: Dominion Energy, Inc.,
a Virginia corporation,
its Limited Partner
By: /s/ James W. Braswell
-------------------------------------
Name: James W. Braswell
Its: Vice President
9
<PAGE>
Exhibit 3.8
AMENDMENT AGREEMENT
-------------------
(CPD)
This AMENDMENT AGREEMENT ("Agreement") is entered into and is effective as
of this 28th day of May, 1999, by and among COSO POWER DEVELOPERS, a California
general partnership ("CPD"), CAITHNESS ACQUISITION COMPANY, LLC, a Delaware
limited liability company ("CAC"), NEW CTC COMPANY, LLC ("New CTC"), a Delaware
limited liability company, CAITHNESS NAVY II GROUP, LLC, a Delaware limited
liability company ("Navy II Group") and COSO OPERATING COMPANY LLC ("COC"), a
Delaware limited liability company.
RECITALS
--------
WHEREAS, CPD is a California general partnership that is the owner of a
geothermal power facility located in Inyo County, California, commonly known as
the Navy II Project (the "Project");
WHEREAS, CPD was, prior to February 25, 1999, co-owned by Navy II Group,
L.P. (predecessor to Navy II Group), an affiliate of Caithness Energy, L.L.C., a
Delaware limited liability company ("Caithness Energy") and Coso Technology
Corporation ("CTC"), a former affiliate of CalEnergy Company, Inc., a Delaware
corporation ("CalEnergy"). CPD was constituted under the General Partnership
Agreement of CPD, as amended (the "Partnership Agreement") and was managed by
COC, previously a wholly owned subsidiary of CalEnergy, as assignee of
CalEnergy, pursuant to two Operations and Maintenance Agreements (the "O&M
Agreements");
WHEREAS, CTC previously served as the Managing General Partner and COC
previously served as the Operator of the Project, in consideration for which CTC
and COC received a management fee (the "Management Fee") and operator fees (the
"Operator Fees") in accordance with the Partnership Agreement and O&M
Agreements. CTC also received a fee in consideration for its participation as a
member of the Management Committee of CPD (the "Committee Fee");
WHEREAS, on February 25, 1999, CTC was merged with and into New CTC, a
wholly owned subsidiary of CAC itself a wholly owned subsidiary of Caithness
Energy. In addition, CAC acquired COC;
WHEREAS, New CTC, as successor to CTC, now serves as the Managing General
Partner of CPD;
WHEREAS, COC, now a wholly owned subsidiary of CAC, in conjunction with FPL
Energy Operating Services, Inc., now serves as the Operator of the Project;
<PAGE>
WHEREAS, CAC, as sole parent of New CTC and COC, has agreed to a large
reduction in the amount of the Management Fee and has negotiated a reduction in
Operator Fees from those fees previously in effect. Furthermore, New CTC has
agreed to eliminate the Committee Fee. These reductions in fees are in the best
interests of CPD and will have the effect of bringing the amount the Management
Fee and Operating Fees more in line with the actual cost of running the Project.
WHEREAS, CAC, as parent of New CTC and COC, has also agreed that the right
to receive the Management Fee and Operator Fees payable to COC shall be
subordinate to debt service payments. This will reverse the prior arrangement,
pursuant to which debt service payments were subordinate to CTC and COC's rights
to receive the Management Fee and Operator Fees. This will constitute a
substantial benefit to CPD as it will increase the amount of cash available for
debt service;
WHEREAS, in consideration for CAC's agreement to cause its subsidiaries to
amend the Partnership Agreement and O&M Agreements to reflect the restructuring
of these fees and to negotiate lower operating fees with FPL Operating Services,
Inc., Navy II Group has agreed to pay to CAC a one-time fee that will represent
its share of the net present value of the savings that will result from the
restructuring of the fee payments over the next ten years.
NOW, THEREFORE, in consideration of the foregoing Recitals, which are by
this reference incorporated herein, and for other good and valuable
consideration, the receipt of which is hereby acknowledged, the parties hereto
agree as follows:
AGREEMENT
1. Reduction and Subordination of Fees. CAC, as parent of New CTC and
-----------------------------------
COC, hereby agrees to cause New CTC and COC to execute and deliver an amended
Partnership Agreement and O&M Agreements reflecting a reduction in the amount of
the Management Fee payable to Navy II Group and Operator Fees payable to COC and
elimination of the Committee Fee payable to New CTC.
2. Subordination of Fees. CAC also agree that it will cause COC to
---------------------
execute an agreement pursuant to which its right to receive Management Fees
shall be subordinate to debt service payments on account of the new senior
secured debt.
3. Fee Buy Down Amount. The net present value of aggregate amount of the
-------------------
savings over the next ten years to CPD resulting from CAC's agreement to cause
New CTC and COC to execute and deliver an amended Partnership Agreement and O&M
Agreement is approximately $17,214,000 (the "Fee Buy Down Amount").
2
<PAGE>
4. Payment by Caithness Navy II Group, LLC. Upon execution of the amended
---------------------------------------
Partnership Agreement and new O&M Agreement described in Section 1 and solely
from funds received by Navy II Group from distributions in connection with the
refinancing of the senior debt of CPD, Caithness Navy II Group, LLC shall pay to
CAC, as designee of New CTC and COC, in consideration for CAC's acceptance of
the provisions herein, the sum of $8,607,000, which represents Navy II Group's
share of the Fee Buy Down Amount equal to Navy II Group's proportionate
ownership of CPD.
5. Further Assurances. The parties hereto agree that, at any times and
------------------
from time to time, upon the written request of the other, such party will
promptly and duly execute and deliver any and all such further instruments and
documents and take such further action as the other party may reasonably request
in order to obtain the full benefit of the this Agreement.
6. Severability. Any provision of this Agreement which is prohibited,
------------
unenforceable or not authorized in any jurisdiction shall, as to such
jurisdiction, be ineffective to the extent of such prohibition, unenforceability
or non-authorization, without invalidating the remaining provisions hereof or
affecting the validity, enforceability or legality of such provision in any
other jurisdiction.
7. Successors and Assigns. Whenever in this Agreement any of the parties
----------------------
hereto is named or referred to, successors and assigns of such party shall be
deemed to be included and all covenants, promises and agreements in this
Agreement by and on behalf of the respective parties hereto shall be binding
upon and inure to the benefit of the respective successors and permitted assigns
of such parties, whether so expressed or not.
8. Governing Law. This Agreement shall be governed by, interpreted
-------------
under, and construed and enforced in accordance with the laws of the State of
California.
9. Amendments and Waivers. This Agreement may be amended only by a
----------------------
writing signed by the parties hereto. No amendment or waiver of any provision
of this Agreement nor consent by any party or any departure by any other party
herefrom shall in any event be effective unless the same shall be in writing and
signed by the party to be charged thereby. Any such waiver or consent shall be
effective only in the specific instance and for the specific purpose for which
given. No failure on the part of any party hereto to exercise, and no delay in
exercising, any right hereunder shall operate as a waiver thereof (except as
expressly provided herein) nor shall any single or partial exercise or any right
hereunder preclude any other or further exercise thereof or the exercise of any
other right.
10. Headings. The section headings in this Agreement are included herein
--------
for convenience of reference only and shall not constitute a part of this
Agreement for any other purpose.
3
<PAGE>
11. Counterparts. This Agreement may be executed in any number of
------------
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
IN WITNESS WHEREOF, the Parties have executed this Agreement as of the
Effective Date.
CAITHNESS ACQUISITION COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
--------------------------------------------
James D. Bishop, Jr.
Vice Chairman
NEW CTC COMPANY, LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
--------------------------------------------
James D. Bishop, Jr.
Vice Chairman
CAITHNESS NAVY II GROUP, LLC,
a Delaware limited liability company
By: Caithness Geothermal 1980 Ltd., L.P.,
a Delaware limited partnership
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
----------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its Member
4
<PAGE>
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
--------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ James D. Bishop, Jr.
-------------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Dominion Energy, Inc.,
a Virginia corporation,
its Limited Member
By: /s/ James W. Braswell
-------------------------------------------------
Name: James W. Braswell
Title: Vice President
COSO OPERATING COMPANY LLC,
a Delaware limited liability company
By: /s/ James D. Bishop, Jr.
------------------------------------------------------
James D. Bishop, Jr.
Vice Chairman
COSO POWER DEVELOPERS,
a California general partnership
By: New CTC Company, LLC,
a Delaware limited liability company,
its Managing General Partner
By: /s/ James D. Bishop, Jr.
-------------------------------------------------
James D. Bishop, Jr.
Vice Chairman
5
<PAGE>
By: Caithness Navy II Group, LLC,
a Delaware limited liability company
its General Partner
By: Caithness Geothermal 1980 Ltd., L.P.,
a Delaware limited partnership
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
--------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Mt. Whitney Geothermal-II Limited Partnership,
a Delaware limited partnership,
its Member
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its General Partner
By: /s/ James D. Bishop, Jr.
--------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Caithness Power, L.L.C.,
a Delaware limited liability company,
its Managing Member
By: /s/ James D. Bishop, Jr.
-------------------------------------------------
James D. Bishop, Jr.
Vice Chairman
By: Dominion Energy, Inc.,
a Virginia corporation,
its Limited Member
By: /s/ James W. Braswell
-------------------------------------------------
Name: James W. Braswell
Title: Vice Presdient
6
<PAGE>
October 6, 1999
Caithness Coso Funding Corp.
1114 Avenue of the Americas
Grace Building, 41st Floor
New York, NY 10036
Re: Registration Statement on Form S-4 (File No. 333-83815)
Exchange of 6.80% Series A Senior Secured Notes due 2001
and 9.05% Series A Senior Secured Notes due 2009
------------------------------------------------
Ladies and Gentlemen:
We have acted as special California counsel to Caithness Coso Funding
Corp., a Delaware corporation (the "Company"), Coso Finance Partners, a
California general partnership ("CFP"), Coso Energy Developers, a California
general partnership ("CED"), and Coso Power Developers, a California general
partnership ("CPD," and, together with CFP and CED, the "Guarantors"), in
connection with the Company's offer (the "Exchange Offer") to exchange its 6.80%
Series B Senior Secured Notes due 2001 for any and all of its outstanding 6.80%
Series A Senior Secured Notes due 2001 and its 9.05% Series B Senior Secured
Notes due 2009 for any and all of its outstanding 9.05% Series A Senior Secured
Notes due 2009. The Company's outstanding 6.80% Series A Senior Secured Notes
due 2001 and 9.05% Series A Senior Secured Notes due 2009 are hereinafter
referred to as the "Series A Notes," and the Company's 6.80% Series B Notes due
2001 and 9.05% Series B Senior Secured Notes due 2009 are hereinafter referred
to as the "Series B Notes." The Series A Notes were issued, and the Series B
Notes will be issued, under an Indenture, dated as of May 28, 1999 (the
"Indenture"), among the Company, the Guarantors and U.S. Bank Trust National
Association, as Trustee and as Collateral Agent. Capitalized terms used but not
otherwise defined herein shall have the meanings assigned to such terms in the
Indenture.
In connection with this opinion, we have examined, among other things:
<PAGE>
Caithness Coso Funding Corp.
October 6, 1999
Page 2
(i) The Registration Statement on Form S-4 (File No. 333-83815)
filed by the Company and the Guarantors with the Securities and Exchange
Commission to register under the Securities Act of 1933, as amended, the
issuance of the Series B Notes and the Guarantees;
(ii) The general partnership agreement of each Guarantor, as amended
through the date hereof;
(iii) The Unanimous Written Consent of the Management Committee of
each Guarantor, dated as of May 21, 1999, authorizing the issuance of the Series
A Notes and the Series B Notes;
(iv) The Indenture;
(v) The form of Series B Notes to be issued in the Exchange Offer;
and
(vi) the form of Guarantee to be endorsed on or attached to the
Series B Notes.
For the purpose of this opinion, we have assumed and our opinions are
subject to the following:
A. The genuineness, authenticity and acknowledgment (if applicable)
of all signatures;
B. The legal capacity of all natural persons;
C. Each document submitted to us for review is accurate and
complete, each such document that is an original is authentic, and each such
document that is a copy conforms to an authentic original;
D. The filing or recordation of each document required to be filed
or recorded; and
E. Each document of each governmental authority is accurate,
complete and authentic, and all official records and proper indexing and filing
are accurate and complete.
<PAGE>
Caithness Coso Funding Corp.
October 6, 1999
Page 3
We call your attention to the fact that the Guarantees select the internal
laws of the State of New York as the governing law and, as provided below, that
we are not rendering any opnion under the laws of the State of New York.
Based upon the foregoing, and upon our examination of such other documents,
general partnership proceedings, statutes, decisions and questions of law as we
have considered necessary in order to enable us to furnish our opinion, we are
of the opinion that:
1. Each of the Guarantors is a general partnership formed under the laws
of the State of California, is validly existing as a general partnership under
the laws of the State of California and has the organizational power and
authority to execute, deliver and perform its obligations under the Indenture
and its Guarantee; and
2. The execution and delivery by each Guarantor of the Indenture and of
its Guarantee and the performance of its obligations thereunder have been duly
authorized by all necessary organizational action on the part of each such
Guarantor, and the Guarantee to be endorsed on or attached to the Series B Notes
by each such Guarantor has been duly authorized by all necessary organizational
action on the part of each such Guarantor.
We are admitted to practice in the State of California. This opinion is
limited to the present laws of the State of California and we express no opinion
as to the laws of the State of New York or any other jurisdiction. We undertake
no obligation to advise you as a result of developments occurring after the date
hereof or as a result of facts or circumstances brought to our attention after
the date hereof.
This opinion is being rendered solely for your benefit and the benefit of
those persons participating in the Exchange Offer. We hereby consent to the
filing of this opinion as an exhibit to the Registration Statement on Form S-4
filed by the Company and the Guarantors with the Securities and Exchange
Commission relating to the Exchange Offer. We also consent to the use of our
name in the prospectus contained in such Registration Statement under the
caption "Legal Matters."
Very truly yours,
/s/ Riordan & McKinzie
RIORDAN & McKINZIE
<PAGE>
EXHIBIT 5.2
[LETTERHEAD OF REED SMITH SHAW & MCCLAY LLP]
October 6, 1999
Caithness Coso Funding Corp.
1114 Avenue of the Americas
Grace Building, 41st Floor
New York, New York 10036
Re: Registration Statement on Form S-4
for 6.80% Series B Senior Secured
Notes due 2001 and 9.05% Series B
Senior Secured Notes due 2009
Ladies and Gentlemen:
We have acted as counsel to Caithness Coso Funding Corp., a Delaware
corporation (the "Company"), Coso Finance Partners, a California general
partnership ("CFP"), Coso Energy Developers, a California general partnership
("CED"), and Coso Power Developers, a California general partnership ("CPD,"
and, together with CFP and CED, the "Guarantors"), in connection with the
Company's offer (the "Exchange Offer") to exchange its 6.80% Series B Senior
Secured Notes due 2001 for any and all of its outstanding 6.80% Series A Senior
Secured Notes due 2001 and its 9.05% Series B Senior Secured Notes due 2009 for
any and all of its outstanding 9.05% Series A Senior Secured Notes due 2009.
The Company's outstanding 6.80% Series A Senior Secured Notes due 2001 and 9.05%
Series A Senior Secured Notes due 2009 are hereinafter referred to as the
"Series A Notes" and the Company's 6.80% Series B Senior Secured Notes due 2001
and 9.05% Series B Senior Secured Notes due 2009 are hereinafter referred to as
the "Series B Notes". The Series A Notes were issued, and it is proposed that
the Series B Notes will be issued, under an Indenture, dated as of May 28, 1999
(the "Indenture"), among the Company, the Guarantors and U.S. Bank Trust
National Association, as Trustee and Collateral Agent. Capitalized terms used
herein but not otherwise defined shall have the meanings assigned to such terms
in the Indenture.
In connection with this opinion we have examined, among other things:
1. The Certificate of Incorporation of the Company;
2. The By-Laws of the Company;
<PAGE>
REED SMITH SHAW & MCCLAY LLP
Caithness Coso Funding Corp. -- October 6, 1999
3. The Unanimous Written Consent of the Board of Directors of the
Company dated May 21, 1999, authorizing the issuance of the
Series A Notes and the Series B Notes;
4. The Unanimous Written Consent of the Shareholders of the Company
dated May 21, 1999, authorizing the issuance of the Series A
Notes and the Series B Notes; and
5. The Indenture.
In rendering this opinion, we have assumed:
(1) Each of the Guarantors is a general partnership formed under the
laws of the State of California and is validly existing as a
general partnership under the laws of the State of California,
and has the organizational power and authority to execute,
deliver and perform its obligations under the Indenture and its
Guarantee; and
(2) The execution and delivery by each Guarantor of the Indenture and
of its Guarantee and the performance of its obligations
thereunder have been duly authorized by all necessary
organizational action on the part of each Guarantor, and the
Guarantee to be endorsed on the Series B Notes by each Guarantor
has been duly authorized by all necessary organizational action
on the part of each Guarantor.
Based upon the foregoing and upon examination of such other documents,
corporate proceedings, statutes, decisions and questions of law as we considered
necessary in order to enable us to furnish this opinion, we are pleased to
advise you that in our opinion (1) the Series B Notes have been duly authorized,
and when executed, authenticated and delivered in exchange for the Series A
Notes in accordance with the terms of the Indenture and the Exchange Offer, will
be duly issued delivered and will constitute valid and binding obligations of
the Company, enforceable in accordance with their terms, except (x) as such
enforcement may be limited by bankruptcy, insolvency, fraudulent conveyance or
similar laws affecting creditors' rights generally, (y) as such enforcement may
be limited by general principles of equity, regardless of whether enforcement is
sought in a
<PAGE>
REED SMITH SHAW & MCCLAY LLP
Caithness Coso Funding Corp. -- October 6, 1999
proceeding at law or in equity, and (z) to the extent that a waiver of rights
under any usury or stay law may be unenforceable, and (2) the guarantee (the
"Guarantee") by each Guarantor of the Company's obligations under the Series B
Notes, when the Series B Notes have been executed, authenticated and delivered
in exchange for the Series A Notes in accordance with the terms of the Indenture
and the Exchange Offer, will be duly issued and delivered and will constitute a
valid and binding obligation of such Guarantor, enforceable in accordance with
its terms, except (x) as such enforcement may be limited by bankruptcy,
insolvency, fraudulent conveyance of similar laws affecting creditors' rights
generally, (y) as such enforcement may be limited by general principles of
equity, regardless of whether enforcement is sought in a proceeding at law or in
equity, and (z) to the extent that a waiver of rights under any usury or stay
law may be unenforceable.
In rendering the foregoing opinion, we have not examined the laws of
any jurisdiction other than the general corporate laws of the State of Delaware,
the laws of the State of New York and the federal laws of the United States of
America and the foregoing opinion is limited to such laws.
We hereby consent to the filing of this opinion as an exhibit to the
Registration Statement and to the use of our name in the prospectus contained in
such registration statement under the caption "Legal Matters" on Form S-4 filed
by the Company and the Guarantors with the Securities and Exchange Commission
relating to the Exchange Offer.
Very truly yours,
/s/ Reed Smith Shaw & McClay LLP
JFC/WFR/HRK
<PAGE>
EXHIBIT 10.16
SALE AGREEMENT
--------------
This Sale Agreement (this "Agreement"), dated as of October 6, 1999 is
entered into by and among Caithness Acquisition Company, LLC, a Delaware limited
liability company ("CAC") and ESI Geothermal, Inc., a Florida corporation
("ESI").
All capitalized terms not otherwise defined herein have the meanings set
forth in that certain Indenture (the "Indenture"), dated as of May 28, 1999, by
and among Caithness Coso Funding Corp., a Delaware corporation, Coso Finance
Partners, a California general partnership, Coso Energy Developers, a California
general partnership, Coso Power Developers, a California general partnership,
and U.S. Bank Trust National Association as trustee.
RECITALS
--------
A. ESI owns a membership interest (the "Interest") in ESCA, LLC, a
Delaware limited liability company ("ESCA") governed by the Limited Liability
Company Agreement of ESCA, LLC dated as of May 28, 1999 (the "ESCA Agreement"),
which is a general partner of Coso Finance Partners (the "Partnership"), which
owns the geothermal power generation facilities commonly known as the Navy I
project located at China Lake, California (the "Project," and collectively with
the adjoining facilities commonly known as the BLM Project and the Navy II
Project, the "Coso Projects").
B. CAC desires to purchase from ESI, and ESI desires to sell to CAC, the
Interest subject to the terms and conditions of this Agreement.
C. Simultaneously, the three Plant Operating and Maintenance Agreements
("Plant O&M Agreements"), each dated May 28, 1999, by FPL Energy Operating
Services, Inc. ("FPLEOS") with the Partnership, Coso Energy Developers, Coso
Power Developers and/or Coso Transmission Line Partners (collectively, the
"Partnerships") will be assigned to Coso Operating Company LLC ("COC"), all
obligations thereunder novated and assumed by COC, and all collateral financing
documents related thereto will be terminated and replaced or amended.
AGREEMENT
---------
NOW, THEREFORE, in consideration of the mutual covenants and promises
contained herein and for other good and valuable consideration, the receipt and
adequacy of which are hereby acknowledged, the parties hereto agree as follows:
1
<PAGE>
ARTICLE I
PURCHASE AND SALE OF THE INTEREST
---------------------------------
1.1 Transfer of Interest. At the Closing (as hereinafter defined), ESI
--------------------
will sell, convey, transfer, assign and deliver to CAC, and CAC will acquire
from ESI, the Interest.
1.2 Purchase Price. As consideration for the purchase of the Interest, at
--------------
the Closing CAC shall pay to ESI Five Million U.S. Dollars (US$5,000,000) by
wire transfer of immediately available funds to the account designated by ESI.
1.3 Refinancing Distribution. At the Closing, the sum of Three Million
------------------------
Four Hundred Seventeen Thousand Nine Hundred Fifty U.S. Dollars ($3,417,950)
shall be distributed (the "Distribution") by ESCA to ESI as its share of the net
refinancing proceeds from the financing ("Financing") issued by Caithness Coso
Funding Corp. to Donaldson Lufkin Jenrette Securities Corporation. Payment of
such sum shall be made by wire transfer of immediately available funds to the
account designated by ESI.
1.4 Tax Matters. CAC shall cause ESCA to close its books as of the
-----------
Closing and profits, losses and items thereof of ESCA, computed for the portion
of the year ending on the Closing, shall be allocated among the members of ESCA
without regard to the transfer of the Interest from ESI to CAC. For purposes of
the preceding sentence, the Partnership shall be treated as having closed its
books as of the Closing and profits, losses and items thereof of the
Partnership, computed for the portion of the year ending on the Closing, shall
be allocated among the partners of the Partnership, as of that date. ESI shall
bear all income tax liability relating to the Interest for all periods ending
prior to the Closing date and CAC shall bear all income tax liability relating
to the Interest after the Closing date.
ARTICLE II
CLOSING
-------
2.1 Closing. The closing of the transactions contemplated herein (the
-------
"Closing") shall be held on October 15, 1999 at 10:00 a.m. Eastern time at the
offices of CAC in New York, New York, unless the parties hereto otherwise agree
in writing to a different date or location.
2.2 Documents to be Delivered. On the Closing date ESI shall convey to
-------------------------
CAC the Interest, free and clear of all encumbrances, by an Assignment,
Assumption and Novation Agreement in the form of Exhibit A hereto.
2.3 Termination. If the Closing shall not have occurred on or before
-----------
October 15, 1999, then the Closing date shall be extended from time to time, but
not later than November 1, 1999, upon request of either party; provided that, if
the Closing shall not have occurred on or
2
<PAGE>
before November 1, 1999, this Agreement shall terminate and neither party shall
have any obligation to the other pursuant hereto.
ARTICLE III
ASSIGNMENT OF PLANT O&M AGREEMENTS
----------------------------------
AND COMPLIANCE WITH FINANCING DOCUMENTS
---------------------------------------
3.1 O&M Assignments. It is a condition of this transaction that FPLEOS
---------------
and COC execute and deliver three Assignment, Assumption and Novation Agreements
in the form of Exhibits B-1, B-2 and B-3 ("O&M Assignments") hereto relating to
the Plant O&M Agreements.
3.2 Additional Documents. In order to effect such assignments of the
--------------------
Plant O&M Agreements, the parties contemplate that the following additional
documents will have to be executed and delivered in order to comply with the
documentation executed in connection with the Financing:
(a) Assumption Agreement and consent with respect to FPLEOS Security
Agreements regarding permits (3) and related UCCs (6) for each Coso Project.
(b) Termination Agreement and Consent with respect to FPLEOS Operating
Fee Subordination Agreements (3) for each Coso Project.
(c) Termination Agreement and Consent with respect to the Consent and
Agreements (O&M Agreements) (3) for each Coso Project.
(d) Assignments, amendments, replacements and/or terminations of
applicable project operating permits listed on Schedule 1 to Exhibit B where
FPLEOS is named as an applicant or a responsible party.
(e) Certification to and consent of U.S. Bank Trust, N.A., as trustee
(the "Trustee"), and as collateral agent (the "Collateral Agent"), as required
by the applicable documents entered into in connection with the Financing (the
"Financing Documents").
3.3 Best Efforts and Cooperation. CAC agrees to use its best efforts to
----------------------------
execute, or to cause its affiliates to execute, the documents called for by this
Article. FPLEOS agrees to execute such agreements, reasonably satisfactory in
form and substance to FPLEOS, and take such actions as may be reasonably
necessary on its part to effectuate the foregoing. The forms of all such
documents shall be prepared by CAC at its expense and shall be subject to
approval by the Trustee and Collateral Agent under the Financing Documents.
3
<PAGE>
ARTICLE IV
ESI'S REPRESENTATIONS AND WARRANTIES
------------------------------------
ESI hereby represents and warrants to CAC as follows:
4.1 Organization. ESI is a corporation duly organized, validly existing
------------
and in good standing under the laws of the State of Florida.
4.2 Authorization. ESI has all requisite power and authority, and has
-------------
taken all corporate action necessary, to execute and deliver this Agreement, to
consummate the transactions contemplated hereby and to perform its obligations
hereunder. This Agreement has been duly executed and delivered by ESI and is a
legal, valid and binding obligation of ESI enforceable against ESI in accordance
with its terms, subject to applicable bankruptcy, insolvency, reorganization,
moratorium or similar laws or equitable principles relating to or limiting
creditors' rights generally.
4.3 Interest. ESI is the sole owner of the Interest.
--------
4.4 No Encumbrances. ESI owns as of the date hereof, and will own as of
---------------
the Closing date, the Interest free and clear of all encumbrances other than the
encumbrances, if any, created in connection with the Financing.
4.5 No Brokers, Etc. Neither ESI nor its affiliates have employed or made
----------------
any agreement with any representative, broker, finder or similar agent or any
other person or firm which will result in the obligation of CAC, or any of its
respective affiliates, to pay any finder's fee, brokerage fee, consulting fee,
severance fee, services fee, commission or similar payment or expense in
connection with the transactions contemplated hereby.
4.6 Due Diligence. ESI acknowledges that based on such documents and
-------------
information as it has deemed appropriate, it has made its appraisal of and own
investigation into the business, financial condition and prospects of ESCA and
has made its own decision to sell the Interest and to enter into this Agreement.
ARTICLE V
CAC'S REPRESENTATIONS AND WARRANTIES
------------------------------------
CAC hereby represents and warrants to ESI as follows.
5.1 Organization. CAC is a limited liability company duly organized,
------------
validly existing and in good standing under the laws of the State of Delaware.
4
<PAGE>
5.2 Authorization. CAC has all requisite power and authority, and has
-------------
taken all action necessary, to execute and deliver this Agreement, the
Assignment, Assumption and Novation Agreement, to consummate the transactions
contemplated hereby and thereby and to perform its obligations hereunder and
thereunder. This Agreement has been, and the Assignment, Assumption and
Novation Agreement when executed will be, duly executed and delivered by CAC and
are legal, valid and binding obligations of CAC enforceable against CAC in
accordance with their terms, subject to applicable bankruptcy, insolvency,
reorganization, moratorium or similar laws or equitable principles relating to
or limiting creditors' rights generally.
5.3 No Consents or Approvals.
------------------------
(a) Neither the execution, delivery or performance by ESI of this
Agreement, nor consummation by ESI of the transactions contemplated hereby, will
require ESI or ESCA to obtain or effect the consent or approval of, the giving
of notice to, or the taking of any other action under the documents entered into
in connection with the Financing, except such as will have been obtained on or
prior to the Closing.
(b) Neither the execution, delivery or performance by FPLEOS of the
O&M Assignments, nor consummation by FPLEOS, the Partnership, Coso Energy
Developers, Coso Power Developers, Coso Transmission Line Partners or Coso
Operating Company LLC of the transactions contemplated thereby (including the
payment to FPLEOS of all amounts described therein), will require FPLEOS, the
Partnership, Coso Energy Developers, Coso Power Developers, Coso Transmission
Line Partners, Coso Operating Company LLC or Caithness Coso Funding Corp. to
obtain or effect the consent or approval of, the giving of notice to, or the
taking of any other action (other than the assistance with the assignment and
transfer of permits at the expense of CAC described in Section 3.2(d) under any
documents entered into in connection with the Financing, except such as will
have been obtained prior to the Closing.
5.4 No Brokers, Etc. Neither CAC nor its affiliates has employed or made
----------------
any agreement with any representative, broker, finder or similar agent or any
other person or firm which will result in the obligation of ESI, or ESI's
affiliates, to pay any finder's fee, brokerage fee, consulting fee, severance
fee, services fee or commission or similar payment or expense in connection with
the transactions contemplated hereby.
5.5 Due Diligence. CAC acknowledges that, based on such documents and
-------------
information as it has deemed appropriate, it has made its own appraisal of and
investigation into the business, financial conditions and prospects of ESCA and
has made its own decision to acquire the Interest and to enter into this
Agreement.
5.6 Acquisition for Investment. CAC is acquiring the Interest hereunder
--------------------------
for its own account for investment and not with a view to, or for sale in
connection with, any distribution of any portion thereof or any beneficial
interest therein in violation of the Securities Act of 1934, as
5
<PAGE>
amended (the "Securities Act"), or other applicable law, and CAC understands and
agrees that the transfer of the Interest or any portion thereof or any
beneficial interest therein may only be made in compliance with the Securities
Act and other applicable law.
ARTICLE VI
COVENANTS OF CAC AND ESI
------------------------
CAC and ESI each covenants with the other as follows:
6.1 Actions to Consummate Closing; Further Assurances. Each agrees, both
-------------------------------------------------
before and after the Closing, (a) to use reasonable efforts to take, or cause to
be taken, all actions and to do, or cause to be done, all things necessary,
proper or advisable to remove or satisfy Closing conditions which are within
such party's control and otherwise to consummate and make effective the
transactions contemplated by this Agreement, (b) to execute any documents,
instruments or conveyances reasonably satisfactory in form and substance to the
executing party of any kind which may be reasonably necessary or advisable to
carry out any of the transactions contemplated hereunder, and (c) to cooperate
with each other in connection with the foregoing.
6.2 Conduct of Business. From the date hereof through the Closing or
-------------------
earlier termination of this Agreement, ESI agrees that it will cooperate with,
and consent, and not exercise any veto, to any action or document as requested
by CAC or ESCA in order to carry out or implement any business decision or
agreement with respect to the Project, including, without limitation, with
regard to any litigation; provided, however, that ESI shall not be required to
consent, cooperate, or refrain from exercising any veto with respect to any
document or action which, in the reasonable opinion of counsel to ESI, may
subject ESI to criminal or civil liability.
6.3 Indemnity. CAC agrees to defend, indemnify and hold harmless ESI, any
---------
shareholder in ESI and any of their respective officers, directors, employees,
agents, attorneys and affiliates (collectively, the "ESI Indemnified Parties")
from and against, on a net after-tax basis, and shall pay and reimburse the ESI
Indemnified Parties for, any loss, cost or other expense that any such ESI
Indemnified Party incurs or suffers arising out of (a) any claim made at any
time after the Closing by any person or entity against ESI in its capacity as a
member or a former member in ESCA or as a partner or former partner in any
predecessor entity to ESCA or any entity which merged with ESCA or against any
other ESI Indemnified Party on account of any liability or obligation of ESI in
its capacity as a member or a former member in ESCA or as a partner or former
partner in any predecessor entity to ESCA or any entity which merged with ESCA,
which claim relates to or arises out of (x) a failure of CAC, or any designee
that acquires the Interest, to perform after the Closing any of its obligations
hereunder or assumed pursuant to the Assignment, Assumption and Novation
Agreement, (y) a failure of ESCA to perform any of its liabilities or
obligations under any agreement to which it is a party, or (z) the business of
the Coso Projects, or (b) any representation or warranty of CAC herein not being
true and correct as and when made, or any agreement of CAC, or any designee that
acquires the Interest, in this
6
<PAGE>
Agreement or the Assignment, Assumption and Novation Agreement not being
performed. ESI shall give prompt written notice to CAC of any matter in respect
of which indemnity may be sought pursuant to this Section (provided that a
failure to give timely notice shall not affect rights to indemnification under
this Section except to the extent that CAC has been damaged by such failure) and
shall reasonably cooperate with CAC with respect to the resolution of any such
matter.
6.4 Litigation. After the Closing, ESI and CAC agree to cooperate as may
----------
be reasonably requested by the other party in connection with any pending or
future litigation relating to ESCA.
ARTICLE VII
CONDITIONS TO ESI'S OBLIGATIONS
-------------------------------
The obligations of ESI to consummate the transactions provided for hereby
are subject to the satisfaction, on or prior to the Closing date, of each of the
following conditions, any of which may be waived by ESI:
7.1 Representations, Warranties and Covenants. All representations and
-----------------------------------------
warranties of CAC contained in this Agreement shall be true and correct at and
as of the date of this Agreement and at and as of the Closing date as if made
thereon and CAC shall have delivered to ESI an officer's certificate certifying
thereto, and CAC shall have performed and satisfied all agreements and covenants
required hereby to be performed by it on or prior to the Closing date.
7.2 Consents. All consents and waivers under the Financing Documents
--------
necessary to the consummation of the transactions contemplated hereby and under
the O&M Assignments shall have been obtained and be in form and substance
reasonably satisfactory to ESI.
7.3 Payments. ESI shall have received the purchase price described in
--------
Section 1.2 and refinancing distribution described in Section 1.3.
7.4 Article III Documents. All documents specified in Article III shall
---------------------
have been executed and delivered by all parties thereto, the parties shall have
agreed to the form of all schedules attached to such documents and all
conditions precedent to the effectiveness of the O&M Assignments (including
receipt of all waivers and consents under the Financing Documents) shall have
been satisfied or waived and all payments then due thereunder shall have been
made.
7.5 Assignment, Assumption and Novation Agreement. The Assignment,
---------------------------------------------
Assumption and Novation Agreement shall have been duly authorized, executed and
delivered by CAC.
7
<PAGE>
7.6 Release. Each of CAC and its affiliates party to the form of Release
--------
attached hereto as Exhibit C-1 shall have executed and delivered such Release.
ARTICLE VII
CONDITIONS TO CAC'S OBLIGATIONS
-------------------------------
The obligations of CAC to consummate the transactions provided for hereby
are subject to the satisfaction, on or prior to the Closing date, of each of the
following conditions, any of which may be waived by CAC:
8.1 Representations, Warranties and Covenants. All representations and
-----------------------------------------
warranties of ESI contained in this Agreement shall be materially true and
correct at and as of the date of this Agreement and at and as of the Closing
date, as if made thereon, and ESI shall have performed and satisfied all
agreements and covenants required hereby to be performed by them on or prior to
the Closing date.
8.2 Consents. All consents and waivers necessary to the consummation of
--------
the transactions contemplated hereby under applicable Financing Documents shall
have been obtained.
8.3 Article III Documents. All documents specified in Article III (other
---------------------
than Section 3.2(d)) shall have been delivered, the parties shall have agreed to
the form of all schedules attached to such documents and all conditions
precedent to the effectiveness of the O&M Assignments shall have been satisfied
or waived.
8.4 Assignment, Assumption and Novation Agreement. The Assignment,
---------------------------------------------
Assumption and Novation Agreement shall have been duly authorized, executed and
delivered by ESI.
8.5 Other Release. Each of ESI and its affiliates party to the form of
-------------
Release attached hereto as Exhibit C-2 shall have executed and delivered such
Release.
ARTICLE IX
MISCELLANEOUS
-------------
9.1 Assignment. CAC may, at its election, direct ESI to transfer all or a
----------
portion of the Interest to one or more designees who are affiliates of CAC
rather than to CAC in connection with the Closing (but no such transfer shall
relieve CAC of any of its obligations hereunder) and such affiliate shall
execute and deliver an Assignment, Assumption and Novation Agreement in respect
of such Interest or portion thereof. Subject to the foregoing, this Agreement
shall be binding upon and inure to the benefit of the parties hereto and their
respective successors and
8
<PAGE>
permitted assigns, and no other person shall have any right, benefit or
obligation under this Agreement as a third party beneficiary or otherwise.
9.2 Notices. All notices, requests, demand and other communications which
-------
are required or may be given under this Agreement shall be in writing and shall
be deemed to have been duly given when received if personally delivered; when
transmitted if transmitted by facsimile; the day after it is sent, if sent for
next day deliver by a recognized overnight delivery service (e.g., Federal
----
Express); and upon receipt, if sent by certified or registered mail, return
receipt requested. In each case, notice shall be sent to:
If to ESI addressed to:
ESI Geothermal, Inc.
c/o ESI Energy, Inc.
700 Universe Boulevard
Juno Beach, Florida 33408
Attention: Vice-President - Business Management
Fax No.: (561) 691-7309
If to CAC addressed to:
Caithness Acquisition Company, LLC
41st Floor
1114 Avenue of the Americas
New York, New York 10036-7790
Attention: President
Fax No.: (212) 921-9239
With a copy to:
Riordan & McKinzie
300 South Grand Avenue, 29th Floor
Los Angeles, California 90071
Attention: Thomas L. Harnsberger
Fax No.: (213) 229-8550
and to such other places and with such other copies as either party may
designate as to itself by written notice to the others.
9.3 Choice of Law. This Agreement shall be construed, interpreted and the
-------------
rights of the parties determined in accordance with the laws of the State of
Delaware.
9
<PAGE>
9.4 Amendments and Waivers. This Agreement may not be amended except by
----------------------
an instrument in writing signed on behalf of each of the parties hereto. No
amendment, supplement, modification or waiver of this Agreement shall be binding
unless executed in writing by the party to be bound thereby.
9.5 Multiple Counterparts. This Agreement may be executed in one or more
---------------------
counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
9.6 Expenses. Each of ESI and CAC shall pay their own legal, accounting,
--------
out-of-pocket and other expenses incident to this Agreement and to any action
taken by or on behalf of such party in preparation for carrying this Agreement
into effect unless expressly provided otherwise herein.
9.7 Attorneys' Fees. If either party hereto or affiliate to a party
---------------
hereto ("Affiliate") brings any action or suit against the other party or
Affiliate by reason of any breach of covenant, condition, agreement or provision
of this Agreement or any agreement contemplated by this Agreement on the part of
the other party or Affiliate, the prevailing party shall be entitled to recover
from the other party or parties all costs and expenses of the action or suit,
including reasonable attorneys' fees, charges and costs, in addition to any
other relief to which it may be entitled.
9.8 Invalidity. In the event that any one or more of the provisions
----------
contained in this Agreement or in any other instrument referred to herein,
shall, for any reason, be held to be invalid, illegal or unenforceable in any
respect, then to the maximum extent permitted by law, such invalidity,
illegality or unenforceability shall not affect any other provision of this
Agreement or any other such instrument.
9.9 Captions. The titles, captions or headings of the Articles and
--------
Sections herein are inserted for convenience of reference only and are not
intended to be a part of or to affect the meaning or interpretation of this
Agreement.
9.10 Public Statements and Press Releases. The parties hereto covenant and
------------------------------------
agree that if either party plans to issue a press release or other public
announcement disclosing the execution of this Agreement or the transactions
contemplated hereby ("Statement"), it shall provide a copy of the Statement to
the other party for review and comment in advance of issuance.
9.11 Cumulative Remedies. All rights and remedies of either party hereto
-------------------
are cumulative of each other and of every other right or remedy such party may
otherwise have at law or in equity, and the exercise of one or more rights or
remedies shall not prejudice or impair the concurrent or subsequent exercise of
other rights or remedies.
10
<PAGE>
9.12 Entire Agreement. This Agreement and any other agreements or
----------------
documents executed pursuant to the terms hereof including, without limitation,
agreements in the form attached as exhibits hereto, constitute the entire
agreement and understanding of the parties hereto with respect to the subject
matter hereof.
ESI GEOTHERMAL, INC. CAITHNESS ACQUISITION COMPANY, LLC
By:/s/ Michael Yackira By: /s/ Leslie J. Gelber
------------------------- -------------------------
Name: Michael Yackira Name: Leslie J. Gelber
----------------------- -------------------------
Its: President Its: President
------------------------ -------------------------
11
<PAGE>
EXHIBIT 10.18
SECURITY AGREEMENT
(Governmental Approvals)
Dated as
of May 28, 1999
between
COSO OPERATING COMPANY LLC,
a Delaware limited liability company,
and
U.S. BANK TRUST NATIONAL ASSOCIATION,
as Collateral Agent
<PAGE>
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
1. Definitions.................................................. 2
2. Assignment, Pledge and Grant of Security Interest............ 2
3. Obligations Secured.......................................... 3
4. Events of Default............................................ 4
5. Remedies..................................................... 4
6. Remedies Cumulative; Delay Not Waiver........................ 5
7. Covenants.................................................... 6
8. Certain Consents and Waivers................................. 7
9. Representations and Warranties............................... 8
10. Notices...................................................... 10
11. Further Assurances........................................... 11
12. Place of Perfection; Records................................. 12
13. Continuing Assignment and Security Interest; Transfer........ 12
14. Attorneys' Fees.............................................. 12
15. Severability................................................. 12
16. Time......................................................... 13
17. Agreement for Security Purposes.............................. 13
18. Governing Law................................................ 13
19. Reinstatement................................................ 13
20. WAIVER OF JURY TRIAL......................................... 13
</TABLE>
i
<PAGE>
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
21. Amendment................................................... 14
22. Duties and Liabilities of the Collateral Agent Generally.... 14
</TABLE>
ii
<PAGE>
SECURITY AGREEMENT
------------------
This Security Agreement ("Agreement"), dated as of May 28, 1999, is entered
into by and between COSO OPERATING COMPANY LLC, a Delaware limited liability
company ("Grantor"), and U.S. BANK TRUST NATIONAL ASSOCIATION, in its capacity
as collateral agent ("Collateral Agent"), for the benefit of U.S. BANK TRUST
NATIONAL ASSOCIATION, in its capacity as trustee ("Trustee") for the holders of
all senior secured notes issued pursuant to that certain Indenture dated as of
May 28, 1999 (the "Indenture"), among Trustee, Coso Finance Partners, a
California general partnership ("Navy I"), Coso Energy Developers, a California
general partnership ("BLM"), Coso Power Developers, a California general
partnership ("Navy II"), and Caithness Coso Funding Corp., a Delaware
corporation (the "Issuer") (such notes, the "Senior Secured Notes," and the
holders thereof, the "Holders of the Senior Secured Notes") and all other
Permitted Additional Senior Lenders (as defined in the Indenture).
PREFACE
-------
A. Issuer has, as of the date of this Security Agreement, issued
$413,000,000 of the Senior Secured Notes, the proceeds of which will be used to
make loans to the Coso Partnerships.
B. Pursuant to a Guarantee dated as of the date of this Security
Agreement (the "Guarantee") the Coso Partnerships have guaranteed to Trustee and
the Holders of the Senior Secured Notes the payment and performance of Issuer's
obligations under the Senior Secured Notes and the Indenture.
C. The Grantor is party to the Amended and Restated Field Operation and
Maintenance Agreement dated as of May 28, 1999, by and between Navy I and the
Grantor (the "Field O&M Agreement"), and the Amended and Restated Plant
Operation and Maintenance Agreement dated as of May 28, 1999, by and between
Navy I, FPL Energy Operating Services, Inc., a Florida corporation, and the
Grantor.
D. As a condition precedent to the sale of the Senior Secured Notes, the
Grantor is required to have executed this Security Agreement as security for the
payment and performance of the Navy I's obligations under the Guarantee.
E. As additional security for the payment and performance of Navy I's
obligations under the Guarantee, it is the intent of Grantor to grant to the
Collateral Agent, for the benefit of the Trustee, the Holders of the Senior
Secured Notes and the Permitted Additional Senior Lenders, if any, a security
interest in the Collateral (as defined below) as security for the payment and
performance of Navy I's obligations under the Guarantee.
<PAGE>
AGREEMENT
---------
In consideration of the premises herein, and for other good and valuable
consideration, the receipt and adequacy of which are hereby acknowledged,
Grantor hereby agrees with the Collateral Agent as follows:
1. Definitions.
-----------
(a) Unless otherwise defined, all terms used herein which are defined
in the Indenture shall have their respective meanings therein defined and the
Rules of Interpretation included in the Indenture shall apply hereto. All terms
defined in the UCC shall have the respective meanings given to those terms in
the UCC; and (b) "UCC" shall mean the Uniform Commercial Code as the same may,
from time to time, be in effect in the State of New York; provided, however, in
the event that, by reason of mandatory provisions of law, any or all of the
attachment, perfection or priority of the security interest in any Collateral is
governed by the Uniform Commercial Code as in effect in a jurisdiction other
than the State of New York, the term "UCC" shall mean the Uniform Commercial
Code as in effect in such other jurisdiction for purposes of the provisions
hereof relating to such attachment, perfection or priority and for purposes of
definitions related to such provisions.
2. Assignment, Pledge and Grant of Security Interest.
-------------------------------------------------
(a) To secure the timely payment and performance of the Obligations
(as that term is defined in Section 3), Grantor does hereby assign, grant and
pledge to, and subject to a security interest in favor of, the Collateral Agent,
on behalf of the Trustee, the Holders of the Senior Secured Notes, and the
Permitted Additional Senior Lenders, if any, all the estate, right, title and
interest of Grantor, whether now owned or hereafter acquired, in, to and under:
(i) all Governmental Approvals (as defined in the Indenture)
relating to the Navy I Project whether now existing or hereafter acquired,
excluding, however, any such Governmental Approvals and consents which by their
terms or by operation of law would become void solely by virtue of a security
interest being granted therein;
(ii) the proceeds of all of the foregoing (all of the collateral
described in clauses (i) and (ii) being herein collectively referred to as the
"Collateral"), including without limitation (1) all rights of Grantor to receive
moneys due and to become due under or pursuant to the Collateral, (2) all rights
of Grantor to receive return of any premiums for or proceeds of any insurance,
indemnity, warranty or guaranty with respect to the Collateral or to receive
condemnation proceeds, (3) all claims of Grantor for damages arising out of or
for breach of or default under the Governmental Approvals or any other
Collateral, and (4) to the extent not included in the foregoing, all proceeds
receivable or received when any and all of the foregoing Collateral is sold,
collected, exchanged or otherwise disposed, whether voluntarily or
involuntarily.
2
<PAGE>
(b) Grantor has heretofore delivered or concurrently with the delivery
hereof is delivering to the Collateral Agent, a true and correct copy of each of
the Governmental Approvals. Grantor will deliver to Collateral Agent a true and
correct copy of any additional Governmental Approval, and material amendments
and supplements to the foregoing, included in the Collateral, as they are
obtained by Grantor.
(c) Anything herein contained to the contrary notwithstanding, Grantor
shall remain liable under each of the Governmental Approvals, to perform all of
the obligations undertaken by it thereunder, all in accordance with and pursuant
to the terms and provisions thereof, and the Collateral Agent shall have no
obligation or liability under any of such Governmental Approvals by reason of or
arising out of this Agreement (during the period of Grantor's right of use and
possession thereof as provided herein), nor shall the Collateral Agent be
required or obligated in any manner to perform or fulfill any obligations of
Grantor thereunder.
(d) Upon the occurrence and during the continuance of an Event of
Default, Grantor does hereby constitute the Collateral Agent, acting for and on
behalf of Trustee, the Holders of the Senior Secured Notes, and the Permitted
Additional Senior Lenders, if any, and each successor or assign thereof, the
true and lawful attorney of Grantor, irrevocably, with full power coupled with
an interest (in the name of Grantor or otherwise) to ask, require, demand,
receive, compound and give acquittance for any and all claims arising out of the
Governmental Approvals to elect remedies thereunder, to endorse any checks or
other instruments or orders in connection therewith and to file any claims or
take any action or institute any proceedings in connection therewith which the
Collateral Agent may deem to be necessary or advisable; provided, however, that
the Collateral Agent shall give Grantor notice of any action taken by it as such
attorney-in-fact promptly after taking any such action.
3. Obligations Secured. This Agreement and all of the Collateral secure
-------------------
the payment and performance of Grantor's (a) obligations under the Guarantee,
including, but not limited to, the payment of all amounts owed to Trustee for
the benefit of the Holders of the Senior Secured Notes and (b) obligations
owing, if any, to the Permitted Additional Senior Lenders, of every kind and
description (whether or not evidenced by any note or instrument and whether or
not for the payment of money), direct or indirect, absolute or contingent, due
or to become due, now existing or hereafter arising, pursuant to the terms of
the Guarantee, or any other instrument evidencing Permitted Indebtedness (other
than Permitted Indebtedness described in clause (4) of the definition of
Permitted Indebtedness), including, but not limited to, the payment of all
amounts owed to the Collateral Agent of every kind and description (whether or
not evidenced by any note or instrument and whether or not for the payment of
money), direct or indirect, absolute or contingent, due or to become due, now
existing or hereafter arising, pursuant to the terms of the Indenture, the
Financing Documents or this Agreement, including all interest, fees, charges,
expenses, attorney's fees and accountant's fees (all such obligations being
herein called the "Obligations").
3
<PAGE>
4. Events of Default. The following shall constitute an Event of Default
-----------------
hereunder:
(a) The occurrence and continuance of an Event of Default under the
Indenture, whatever the reason for such Event of Default and whether it shall be
voluntary or involuntary or be effected by operation of law or pursuant to any
judgment, decree or order of any court or any order, rule or regulation of any
administrative or governmental body; and
(b) the failure on the part of Grantor to observe or perform any
covenant, condition or agreement on its part to be observed or performed under,
or the breach of any representation or warranty of Grantor contained in this
Agreement and such failure continues uncured for 30 or more days from the date a
Responsible Officer of Grantor receives notice thereof from the Collateral
Agent; provided that if Grantor commences and diligently pursues efforts to
cure such default within such 30-day period, Grantor may continue to effect such
cure of the default and such default will not be deemed an Event of Default for
an additional 60 days so long as Grantor is diligently pursuing such cure.
5. Remedies.
--------
(a) Subject to the terms of the Guarantee and the notice and other
requirements of applicable law, if any Event of Default has occurred and is
continuing, the Collateral Agent may (i) exercise the rights of acceleration set
forth in Section 5.2 of the Indenture, (ii) proceed to protect and enforce the
rights vested in it by this Agreement, and to enforce its rights hereunder by
such appropriate judicial proceedings as it shall deem most effective to protect
and enforce any of such rights, either at law or in equity or otherwise, whether
for specific enforcement of any covenant or agreement contained in any of the
Governmental Approvals, or in aid of the exercise of any power therein or herein
granted, or for any foreclosure hereunder and sale under a judgment or decree in
any judicial proceeding, or to enforce any other legal or equitable right vested
in it by this Agreement or by law; (iii) cause any action at law or suit in
equity or other proceeding to be instituted and prosecuted to collect or enforce
any Obligations or rights included in the Collateral, or to foreclose or enforce
any other agreement or other instrument by or under or pursuant to which such
Obligations are issued or secured, either in Grantor's name or in Collateral
Agent's name as Collateral Agent may deem necessary, subject in each case to the
provisions and requirements thereof; (iv) sell or otherwise dispose of any or
all of the Collateral or cause the Collateral to be sold or otherwise disposed
of in one or more sales or transactions, at such prices as the Collateral Agent
may deem commercially reasonable, and for cash or on credit or for future
delivery, without assumption of any credit risk, at any broker's board or at
public or private sale, without demand of performance or notice of intention to
sell or of time or place of sale (except such notice as is required by
applicable statute and cannot be waived or is contemplated herein or by the
other Financing Documents), it being agreed that the Collateral Agent may be a
purchaser on behalf of Trustee, the Holders of the Senior Secured Notes, the
Permitted Additional Senior Lenders, if any, or on its own behalf at any such
sale and that the Collateral Agent or anyone else who may be the purchaser of
any or all of the Collateral so sold shall thereafter hold the same absolutely,
free
4
<PAGE>
from any claim or right of whatsoever kind, including any equity of redemption,
of Grantor, any such demand, notice or right and equity being hereby expressly
waived and released to the extent permitted by law; (v) incur reasonable
expenses, including reasonable attorneys' fees, consultants' fees, and other
costs appropriate to the exercise of any right or power under this Agreement;
(vi) perform any obligation of Grantor under this Agreement, or under any other
Financing Document, Project Document or Additional Project Document, and make
payments, purchase, contest or compromise any encumbrance, charge, or lien, and
pay taxes and expenses, without, however, any obligation so to do; (vii) take
possession of the Collateral and render it usable, and repair and renovate the
same, without, however, any obligation to do so, and enter upon the site where
the Project is located or any other location where the same may be located for
that purpose, control, manage, operate, rent and lease the Collateral, either
separately or in conjunction with the Project, collect all rents and income from
the Collateral and apply the same to reimburse the Holders of the Senior Secured
Notes or the Permitted Additional Senior Lenders, if any, for any cost or
expenses incurred hereunder or under any of the Financing Documents and to the
payment or performance of the Obligations, and apply the balance to whomsoever
is legally entitled thereto; (viii) secure the appointment of a receiver of the
Collateral or any part thereof (to the extent and in the manner provided by
applicable law); or (ix) exercise any other or additional rights or remedies
granted to a secured party under the UCC. f, pursuant to applicable law, prior
notice of any such action is required to be given to Grantor, Grantor hereby
acknowledges that the minimum time required by such applicable law, or if no
minimum is specified, ten (10) Business Days, shall be deemed a reasonable
notice period. Notwithstanding anything herein to the contrary, any purchase
price obtained by the Collateral Agent in a foreclosure sale instituted and
prosecuted in accordance with the terms hereof shall be deemed binding and
conclusive on the parties hereto and the Trustee, the Holders of the Senior
Secured Notes and the Permitted Additional Senior Lenders, if any.
(b) All costs and expenses (including, but without being limited to,
reasonable attorneys' fees and expenses) incurred by the Collateral Agent in
connection with any such suit or proceeding, or in connection with the
performance by the Collateral Agent of any of Grantor's agreements contained
herein or in any exercise of Collateral Agent's rights or remedies hereunder,
including any of the Governmental Approvals pursuant to the terms of this
Agreement, together with interest thereon (to the extent permitted by law)
computed at a rate per annum equal to the "Prime Rate" of Bankers Trust Company,
as such rate is announced from time to time, plus one percent (1%), said rate to
change when and as the said Prime Rate changes, from the date on which such
costs or expenses are incurred to the date of payment thereof, shall constitute
additional indebtedness secured by this Agreement and shall be paid by Grantor
to the Trustee on demand.
6. Remedies Cumulative; Delay Not Waiver.
-------------------------------------
(a) No right, power or remedy herein conferred upon or reserved to the
Collateral Agent is intended to be exclusive of any other right, power or
remedy, and every such right, power and remedy shall, to the extent permitted by
law, be cumulative and in addition
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to every other right, power and remedy given hereunder or now or hereafter
existing at law or in equity or otherwise. The assertion or employment of any
right or remedy hereunder, or otherwise, shall not prevent the concurrent
assertion or employment of any other appropriate right or remedy. Resort to any
or all security now or hereafter held by the Collateral Agent, may be taken
concurrently or successively and in one or several consolidated or independent
judicial actions or lawfully taken nonjudicial proceedings, or both.
(b) No delay or omission of the Collateral Agent to exercise any right
or power accruing upon the occurrence and during the continuance of any Event of
Default as aforesaid shall impair any such right or power or shall be construed
to be a waiver of any such Event of Default or an acquiescence therein; and
every power and remedy given by this Agreement may be exercised from time to
time, and as often as shall be deemed expedient, by the Collateral Agent.
(c) The net proceeds of any foreclosure, collection, recovery,
receipt, appropriation, realization or sale of the Collateral shall be applied
in the order of priority specified in Section 5.10 of the Indenture. If all
Obligations and any other amounts due under this Agreement have been
indefeasibly paid, satisfied and discharged in full, any surplus then remaining
shall be paid to Grantor, if it is lawfully entitled to receive the same, or
shall be paid to whomsoever a court of competent jurisdiction may direct.
7. Covenants. Grantor covenants as follows:
---------
(a) Any action or proceeding to enforce this Agreement or any Assigned
Agreement may be taken by the Collateral Agent either in Grantor's name or in
the Collateral Agent's name, as the Collateral Agent may deem necessary.
(b) Not to make any other assignment (other than to Collateral Agent)
of its rights under the Governmental Approvals.
(c) To do all acts that may reasonably be necessary to maintain,
preserve and protect the Collateral.
(d) Not to use or permit any Collateral to be used unlawfully or in
material violation of any provision of applicable statute, regulation or
ordinance.
(e) To pay promptly when due all taxes, assessments, charges,
encumbrances and liens now or hereafter imposed upon or affecting any
Collateral.
(f) To procure, execute and deliver from time to time any
endorsements, assignments, financing statements and other writings reasonably
necessary to perfect, maintain and protect the Collateral Agent's security
interest hereunder and the priority thereof.
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<PAGE>
(g) To appear in and defend any action or proceeding that may affect
its title to or the Collateral Agent's interest in the Collateral.
(h) Not to sell, encumber, lease, rent, or otherwise dispose of or
transfer any Collateral or right or interest therein.
(i) To comply with all laws, regulations and ordinances relating to
the Collateral.
8. Certain Consents and Waivers.
----------------------------
(a) Grantor hereby waives, to the maximum extent permitted by law (i)
all rights under any law limiting remedies, including recovery of a deficiency,
under an obligation secured by a deed of trust on real property if the real
property is sold under a power of sale contained in the deed of trust, and all
defenses based on any loss whether as a result of any such sale or otherwise, of
Grantor's right to recover any amount from Navy I, whether by right of
subrogation or otherwise; (ii) all rights under any law to require Collateral
Agent to pursue Navy I or any other Person, any security which Collateral Agent
may hold, or any other remedy before proceeding against Grantor; (iii) all
rights of reimbursement or subrogation, all rights to enforce any remedy that
Collateral Agent, the Trustee, the Holders of the Senior Secured Notes or the
Permitted Additional Senior Lenders, if any, may have against Navy I, and all
rights to participate in any security held by Collateral Agent until the
Obligations have been paid and the covenants of the Indenture have been
performed in full; (iv) all rights to require Collateral Agent to give any
notices of any kind, including without limitation notices of nonpayment,
nonperformance, protest, dishonor, default, delinquency or acceleration, or to
make any presentments, demands or protests, except as expressly provided herein
and in the Indenture; (v) all rights to assert the bankruptcy or insolvency of
Navy I as a defense hereunder or as the basis for rescission hereof; (vi) all
rights under any law purporting to reduce Grantors' Obligations hereunder if
Navy I's Obligations are reduced; (vii) all defenses based on the disability or
lack of authority of Navy I or any Person, the repudiation of the Guarantees or
any related Financing Documents by Navy I or any Person, the failure by
Collateral Agent, the Trustee, the Holders of the Senior Secured Notes or any
Permitted Additional Senior Lender, if any, to enforce any claim against Navy I,
or the unenforceability in whole or in part of any Financing Document; (viii)
all suretyship and guarantor's defenses generally; (ix) all rights to insist
upon, plead or in any manner whatever claim or take the benefit or advantage of,
any appraisal, valuation, stay, extension, marshaling of assets, redemption or
similar law, or exemption, whether now or at any time hereafter in force, which
may delay, prevent or otherwise affect the performance by Grantor or its
obligations under, or the enforcement by Collateral Agent of, this Agreement;
(x) any requirement on the part of Collateral Agent, Trustee, the Holders of the
Senior Secured Notes or any Permitted Additional Senior Lender, if any, to
mitigate the damages resulting from any default; and (xi) except as otherwise
specifically set forth herein, all rights of notice and hearing of any kind
prior to the exercise of rights by Collateral Agent upon the occurrence and
during the continuation of an Event of Default to
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<PAGE>
repossess with judicial process or to replevy, attach or levy upon the
Collateral. To the extent permitted by applicable law, Grantor waives the
posting of any bond otherwise required of Collateral Agent in connection with
any judicial process or proceeding to obtain possession of, replevy, attach, or
levy upon the Collateral, to enforce any judgment or other security for the
Obligations, to enforce any judgment or other court order entered in favor of
Collateral Agent, or to enforce by specific performance, temporary restraining
order, preliminary or permanent injunction, this Agreement or any other
agreement or document between Grantor, Collateral Agent, Trustee, the Holders of
the Senior Secured Notes or any Permitted Additional Senior Lender, if any.
Grantor further agrees that upon the occurrence and continuance of an Event of
Default, Collateral Agent may elect to nonjudicially or judicially foreclose
against any real or personal property security it holds for the Obligations or
any part thereof, or to exercise any other remedy against Navy I, any security
or any guarantor, even if the effect of that action is to deprive a Grantor of
the right to collect reimbursement from Navy I for any sums paid by Grantor to
Collateral Agent, Trustee or any Holder of the Senior Secured Notes or any
Permitted Additional Senior Lender, if any.
(b) If Collateral Agent may, under applicable law, proceed to realize
its benefits under any of the Financing Documents giving Collateral Agent a Lien
upon any Collateral, whether owned by any Navy I, Grantor or by any other
Person, either by judicial foreclosure or by nonjudicial sale or enforcement,
Collateral Agent may, at its sole option, determine which of its remedies or
rights it may pursue without affecting any of the rights and remedies of
Collateral Agent under this Agreement. In the event Collateral Agent shall bid
at any foreclosure or trustee's sale or at any private sale permitted by law or
the Financing Documents, Collateral Agent may bid all or less than the amount of
Obligations. To the extent permitted by applicable law, the amount of the
successful bid at any such sale, whether Collateral Agent or any other party is
the successful bidder, shall be conclusively deemed to be the fair market value
of the Collateral and the difference between such bid amount and the remaining
balance of the Obligations shall be conclusively deemed to be the amount of the
Obligations.
9. Representations and Warranties. Grantor represents and warrants as
------------------------------
follows:
(a) No effective financing statement or other instrument similar in
effect covering all or any part of Grantor's interest in the Collateral is on
file in any recording office, except such as may have been filed pursuant to
this Agreement and the other Financing Documents or pursuant to the documents
evidencing Permitted Liens.
(b) Grantor has not assigned any of its rights under the Governmental
Approvals except as specifically provided in this Agreement or as set forth in
the Indenture.
(c) Grantor will perform and comply, in all material respects, with
all obligations and conditions on its part to be performed hereunder, under the
Field O&M Agreement or with respect to the Collateral.
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<PAGE>
(d) Grantor (i) is a limited liability company duly organized, validly
existing and in good standing under the laws of the State of Delaware and has
all requisite power and authority under the laws of its state of organization to
enter into this Agreement and to perform its obligations hereunder and to
consummate the transactions contemplated hereby, (ii) is duly qualified,
authorized to do business and in good standing in each jurisdiction where the
character of its properties or the nature of its activities makes such
qualification necessary, and (iii) has all requisite power and authority to
carry on its business as now being conducted and as proposed to be conducted by
it, (X) to execute, deliver and perform this Agreement, (Y) to take all action
as may be necessary to consummate the transactions contemplated hereunder, and
(Z) to grant liens and security interest provided for in this Agreement.
(e) Grantor has (i) taken all necessary action to authorize the
execution, delivery and performance of this Agreement; and (ii) duly executed
and delivered this Agreement. Neither Grantor's execution and delivery of this
Agreement nor its consummation of the transactions contemplated hereby nor its
compliance with the terms hereof (i) does or will contravene the documents of
formation of Grantor or any other requirements of law applicable to or binding
on such Grantor or any of its properties, (ii) does or will contravene or result
in any breach of or constitute any default under, or result in or require the
creation of any Lien (other than Permitted Liens) upon any of its property
under, any agreement or instrument to which it is a party or by which it or any
of its properties may be bound or affected or (iii) does or will require the
consent or approval of any Person which has not already been obtained.
(f) This Agreement is the legal, valid and binding obligation of such
Grantor, enforceable against such Grantor in accordance with its terms, except
to the extent the enforceability may be limited by applicable bankruptcy,
insolvency, moratorium, reorganization or other similar laws affecting the
enforcement of creditors' rights generally and subject to general equitable
principles.
(g) Grantor is the lawful owner of and has full right, title and
interest in and to, the Collateral, subject to no mortgages, liens, charges, or
encumbrances of any kind and has full power and lawful authority to pledge,
assign and grant a security interest in the Collateral granted by it hereunder.
Grantor will, so long as any Obligations shall be outstanding, warrant and
defend its title to the Collateral against any claims and demands which may
affect to a material extent its title to, or the Collateral Agent's right or
interest in, such Collateral.
(h) Grantor will not directly or indirectly create, incur, assume or
suffer to exist any Liens on or with respect to any part of the Collateral other
than the rights and interests of the Collateral Agent, the Trustee, the Holders
of the Senior Secured Notes and the Permitted Additional Senior Lenders, if any,
hereunder. Grantor will at its own cost and expense promptly take such action
as may be necessary to discharge any such liens not so permitted.
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<PAGE>
(i) Any action or proceeding to enforce the rights granted or to
protect or preserve the Collateral under this Agreement may be taken by
Collateral Agent either in Grantor's name or in Collateral Agent's name, as
Collateral Agent may deem necessary.
(j) Grantor will, at all times, keep accurate and complete records of
the Collateral. Grantor shall, at all times on three (3) Business Days' notice,
permit representatives of Collateral Agent at any time during normal business
hours of such Grantor to inspect and make abstracts from such Grantor's books
and records pertaining to the Collateral. Upon the occurrence and continuance
of any Event of Default, at Collateral Agent's request, Grantor shall promptly
deliver any and all such records to Collateral Agent.
(k) Grantor will give prompt notice in writing to Collateral Agent of
any change in the location of the place of business where correspondence,
notices or proceeds in connection with the Collateral are received or located or
of any change in the location of the place of business where records concerning
Collateral are kept.
10. Notices. Any notice or communication by the Grantor or the Collateral
-------
Agent to the other is duly given if in writing and delivered in person or mailed
by first class mail (registered or certified, return receipt requested), telex,
telecopier or overnight air courier guaranteeing next day delivery, to the
other's address:
If to the Grantor:
Coso Operating Company
c/o Caithness Energy, L.L.C.
1114 Avenue of the Americas, 41st Floor
New York, New York 10036
Telecopier No.: (212) 921-9239
Attention: Christopher T. McCallion
With a copy to:
Riordan & McKenzie
300 South Grand Avenue
Twenty-Ninth Floor
Los Angeles, Ca 90071
Telecopier No.: (213) 629-4824
Attention: Thomas L. Harnsberger, Esq.
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<PAGE>
If to the Collateral Agent:
U.S. Bank Trust National Association
One California Street
Fourth Floor
San Francisco, California 94111
Telecopier No.: (415) 273-4590
11. Further Assurances.
------------------
(a) Grantor agrees that from time to time, at the expense of Grantor,
Grantor will promptly execute and deliver all further instruments and documents,
and take all further action, that may be necessary or required, or that the
Collateral Agent may reasonably request, in order to perfect and protect the
assignment and security interest granted or intended to be granted hereby or to
enable the Collateral Agent to exercise and enforce its rights and remedies
hereunder with respect to any Collateral. Without limiting the generality of
the foregoing, Grantor will: (i) if any Collateral shall be evidenced by a
promissory note or other instrument, deliver and pledge to the Collateral Agent,
for the benefit of Trustee, the Holders of Senior Secured Notes and the
Permitted Additional Senior Lenders, if any, such note or instrument duly
endorsed (without recourse) and accompanied by duly executed instruments of
transfer or assignment, all in form and substance satisfactory to enable the
Collateral Agent to enforce the provisions of this Agreement and the security
interests described herein; and (ii) execute and file such financing or
continuation statements, or amendments thereto, and such other instruments,
endorsement or notices, as may be necessary or required, or as the Collateral
Agent may reasonably request, in order to perfect and preserve the assignments
and security interests granted or purported to be granted hereby; it being
understood and agreed that the Collateral Agent shall have no obligation in
respect of the filing of such statements or in the perfection or preservation of
any such security interests.
(b) Grantor hereby authorizes the Collateral Agent to file one or more
financing or continuation statements, and amendments thereto, relative to all or
any part of the Collateral without the signature of Grantor where permitted by
law. Copies of any such statement or amendment thereto shall promptly be
delivered to Grantor.
(c) Grantor shall pay all filing, registration and recording fees or
refiling, re-registration and re-recording fees, and all expenses incident to
the execution and acknowledgment of this Agreement, any instruments of further
assurance, and (except as otherwise provided in the Indenture) all federal,
state, county and municipal stamp taxes and other taxes, duties, imports,
assessments and charges arising out of or in connection with the execution and
delivery of this Agreement, any agreement supplemental hereto and any
instruments of further assurance.
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12. Place of Perfection; Records. The location of Grantor's chief
----------------------------
executive office is 1114 Avenue of the Americas, New York, New York 10036-7790,
and the location of Grantor's place of business is Inyo and Kern County,
California. Grantor shall give the Collateral Agent at least forty-five (45)
days prior written notice before it changes the location of its chief executive
office and shall at the expense of Grantor execute and deliver such instruments
and documents as required to maintain a prior perfected security interest and as
requested by the Collateral Agent. Grantor will hold and preserve such records
and will permit representatives of the Collateral Agent upon reasonable notice
during normal business hours to inspect and make abstracts from such records.
13. Continuing Assignment and Security Interest; Transfer. This Agreement
-----------------------------------------------------
shall create a continuing assignment of and security interest in the Collateral
and shall (i) remain in full force and effect until payment in full of the
Obligations, (ii) be binding upon Grantor, its successors and assigns and (iii)
inure, together with the rights and remedies of the Collateral Agent, to the
benefit of the Trustee, the Holders of the Senior Secured Notes, the Permitted
Additional Senior Lenders, if any, and their respective successors, transferees
and assigns. Without limiting the generality of the foregoing clause (iii), but
subject to Section 2.06 of the Indenture, the Holders of the Senior Secured
Notes may assign or otherwise transfer their Senior Secured Notes to any other
Person, and such other Person shall thereupon become vested with all or an
appropriate part of the benefits in respect thereof granted to the Holders of
the Senior Secured Notes herein or otherwise. The release of the security
interest in any or all of the Collateral, the taking or acceptance of additional
security, or the resort by Collateral Agent to any security it may have in any
order it may deem appropriate, shall not affect the liability of any person on
the indebtedness secured hereby. Upon the payment in full of the Obligations,
the security interest granted hereby shall terminate and all rights to the
Collateral shall revert to Grantor. Upon any such termination, the Collateral
Agent shall, at Grantor's expense, execute and deliver to Grantor such documents
as Grantor shall reasonably request to evidence such termination. If this
Agreement shall be terminated or revoked by operation of law, Grantor will
indemnify and save Collateral Agent, Trustee, the Holders of the Senior Secured
Notes and the Permitted Additional Senior Lenders, if any, harmless from any
loss which may be suffered or incurred by Collateral Agent, Trustee, the Holders
of the Senior Secured Notes and the Permitted Additional Senior Lenders, if any,
in acting hereunder prior to the receipt by Collateral Agent, its successors,
transferees, or assigns of written notice of such termination or revocation.
14. Attorneys' Fees. In the event any legal action or proceeding
---------------
(including without limitation any of the remedies provided for herein or at law)
is commenced to enforce or interpret this Agreement or any provision thereof,
the prevailing party shall be entitled to recover its reasonable attorneys' fees
and other reasonable costs and expenses incurred therein from the losing party,
and, if a judgment or award is entered in any such action or proceeding, such
attorneys' fees and other costs and expenses may be made a part of such judgment
or award.
15. Severability. Any provision of this Agreement which is prohibited or
------------
unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective
to the extent of such
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prohibition or unenforceability without invalidating the remaining provisions
hereof, and any such prohibition or unenforceability in any jurisdiction shall
not invalidate or render unenforceable such provision in any other jurisdiction.
16. Time. Time is of the essence of this Agreement.
----
17. Agreement for Security Purposes. This Agreement is for security
-------------------------------
purposes only. Accordingly, the Collateral Agent shall not, pursuant to this
Agreement, enforce Grantor's rights with respect to the Collateral, including
the exercise of any rights granted under the Consents, until such time as an
Event of Default shall have occurred and is continuing at the time such
enforcement is sought, and after any required notice of such enforcement has
been given, and until such time, subject to the terms of the Indenture and the
other Financing Documents, Grantor reserves the right to exercise all of its
right, title and interest in, to and under the Collateral (including the
Governmental Approvals).
18. Governing Law. This Agreement, including all matters of construction,
-------------
validity, performance and the creation, validity, enforcement or priority of the
lien of, and security interests created by, this Agreement in or upon the
Collateral shall be governed by the laws of the State of New York, without
reference to conflicts of law (other than Section 5-1401 of the New York General
Obligations Law), except as required by mandatory provisions of law and except
to the extent that the validity or perfection of the lien and security interest
hereunder, or remedies hereunder, in respect of any particular Collateral are
governed by the laws of a jurisdiction other than the State of New York.
19. Reinstatement. This Agreement shall continue to be effective or be
-------------
reinstated, as the case may be, if at any time any amount received by Collateral
Agent in respect of the Obligations is rescinded or must otherwise be restored
or returned by Collateral Agent upon the insolvency, bankruptcy, reorganization,
liquidation of Grantor or any of the Coso Partnerships or upon the dissolution
of, or appointment of any intervenor or conservator of, or trustee or similar
official for, Grantor or any of the Coso Partnerships or any substantial part of
Grantor's or any of the Coso Partnership's assets, or otherwise, all as though
such payments had been made.
20. WAIVER OF JURY TRIAL. GRANTOR AND COLLATERAL AGENT HEREBY KNOWINGLY,
--------------------
VOLUNTARILY, AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY JURY
IN RESPECT OF ANY LITIGATION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN
CONNECTION WITH, THIS AGREEMENT OR ANY OTHER FINANCING DOCUMENT, OR ANY COURSE
OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OR
ACTIONS OF COLLATERAL AGENT OR GRANTOR. THIS PROVISION IS A MATERIAL INDUCEMENT
FOR COLLATERAL AGENT TO ENTER INTO THIS AGREEMENT.
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21. Amendment. No modification or waiver of any of the provisions of this
---------
Agreement shall be binding on Collateral Agent, except as expressly set forth in
a writing duly signed and delivered by Collateral Agent and which is otherwise
in accordance with Article 8 of the Indenture.
22. Duties and Liabilities of the Collateral Agent Generally.
--------------------------------------------------------
(a) The Collateral Agent undertakes to perform such duties and only
such duties as are specifically set forth in this Agreement. The Collateral
Agent shall not have any duties or responsibilities except those expressly set
forth in this Agreement or be a trustee for or have any fiduciary obligation to
any party hereto.
(b) The duties and obligations of the Collateral Agent shall be
determined solely by the express provisions of this Agreement, and the
Collateral Agent shall take such action with respect to this Agreement as it
shall be directed in writing by Trustee, and the Collateral Agent shall not be
liable except for the performance of such duties and obligations as are
specifically set forth in this Agreement and no implied covenants or obligations
shall be read into this Agreement against the Collateral Agent; and
(i) In the absence of bad faith on the part of the Collateral
Agent, the Collateral Agent may conclusively rely, as to the truth of the
statements and the correctness of the opinions expressed therein, upon any
certificates or opinions furnished to the Collateral Agent which conform to the
requirements of this Agreement;
(ii) The Collateral Agent shall not be liable for any error of
judgment made in good faith by an officer or officers of the Collateral Agent,
unless it shall be conclusively determined by a court of competent jurisdiction
that the Collateral Agent was negligent in ascertaining the pertinent facts; and
(iii) The Collateral Agent shall not be liable with respect to any
action taken or omitted to be taken by it in good faith in accordance with any
direction of Trustee or Grantor given under this Agreement.
(c) None of the provisions of this Agreement shall require the
Collateral Agent to expend or risk its own funds or otherwise to incur any
liability, financial or otherwise, in the performance of any of its duties
hereunder, or in the exercise of any of its rights or powers if it shall have
reasonable grounds for believing that repayment of such funds or indemnity
satisfactory to it against such risk or liability is not assured to it.
(d) The Collateral Agent may conclusively rely and shall be fully
protected in acting or refraining from acting upon any resolution, certificate,
statement, instrument, opinion, report, notice, request, consent, order,
approval or other paper or document believed by it to be genuine and to have
been signed or presented by the proper party or parties.
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<PAGE>
(e) Whenever in the administration of the provisions of this Agreement
the Collateral Agent shall deem it necessary or desirable that a matter be
proved or established prior to taking or suffering any action to be taken
hereunder, such matter (unless other evidence in respect thereof be herein
specifically prescribed) may, in the absence of negligence or bad faith on the
part of the Collateral Agent, be deemed to be conclusively proved and
established by a certificate signed by a Responsible Officer of Trustee or
Grantor as the case may be, and delivered to the Collateral Agent and such
certificate, in the absence of negligence or bad faith on the part of the
Collateral Agent, shall be full warrant to the Collateral Agent for any action
taken, suffered or omitted by it under the provisions of this Agreement upon the
faith thereof.
(f) The Collateral Agent may consult with counsel and the advice or
any opinion of counsel shall be full and complete authorization and protection
in respect of any action taken or omitted by it hereunder in good faith and in
accordance with such advice or opinion of counsel.
(g) The Collateral Agent shall not be bound to make any investigation
into the facts or matters stated in any resolution, certificate, statement,
instrument, opinion, report, notice, request, consent, entitlement order,
approval or other paper or document.
(h) The Collateral Agent may execute any of the powers hereunder or
perform any duties hereunder either directly or by or through agents, attorneys,
custodians or nominees appointed with due care, and shall not be responsible for
any willful misconduct or negligence on the part of or for the supervision of,
any agent, attorney, custodian or nominee so appointed.
(i) Grantor covenants and agrees to pay to the Collateral Agent from
time to time, and the Collateral Agent shall be entitled to, the fees and
expenses agreed in writing between Grantor and the Collateral Agent, and will
further pay or reimburse the Collateral Agent upon its request for all
reasonable expenses, disbursements and advances incurred or made by the
Collateral Agent in accordance with any of the provisions hereof or any other
documents executed in connection herewith (including the compensation and the
expenses and disbursements of its counsel and of all persons not regularly in
its employ). The obligations of Grantor under this Section 22(i) to compensate
the Collateral Agent and to pay or reimburse the Collateral Agent for reasonable
expenses, disbursements and advances shall survive the satisfaction and
discharge of this Agreement or the earlier resignation or removal of the
Collateral Agent.
(j) The Collateral Agent may at any time resign by giving 30 days
written notice of resignation to Trustee. Upon receiving such notice of
resignation, Grantor shall promptly appoint a successor and, upon the acceptance
by the successor of such appointment, release the resigning Collateral Agent
from its obligations hereunder by written instrument, a copy of which instrument
shall be delivered to each of Grantor and Trustee, the resigning Collateral
Agent and the successor. If no successor shall have been so appointed and have
accepted appointment within 45 days after the giving of such notice of
resignation, the resigning
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<PAGE>
Collateral Agent may petition any court of competent jurisdiction for the
appointment of a successor.
(k) Any corporation into which the Collateral Agent may be merged or
converted or with which it may be consolidated, or any corporation resulting
from any merger, conversion or consolidation to which the Collateral Agent shall
be a party, or any corporation succeeding to the business of the Collateral
Agent shall be the successor of the Collateral Agent hereunder without the
execution or filing of any paper with any party hereto or any further act on the
part of any of the parties hereto except where an instrument of transfer or
assignment is required by law to effect such succession, anything herein to the
contrary notwithstanding.
(l) Neither the Collateral Agent nor any of its officers, directors,
employees or agents shall be liable for any action taken or omitted under this
Agreement or in connection therewith except to the extent caused by the
Collateral Agent's negligence or willful misconduct, as determined by the final
judgment of a court of competent jurisdiction, no longer subject to appeal or
review. The parties each (for itself and any person or entity claiming through
it) hereby releases, waives, discharges, exculpates and covenants not to sue the
Collateral Agent for any action taken or omitted under this Agreement except to
the extent caused by the Collateral Agent's negligence or willful misconduct.
Anything in this Agreement to the contrary notwithstanding, in no event shall
the Collateral Agent be liable for special, indirect or consequential loss or
damage of any kind whatsoever (including but not limited to lost profits), even
if the Collateral Agent has been advised of the likelihood of such loss or
damage and regardless of the form of action,
(m) Grantor shall indemnify, defend and hold harmless the Collateral
Agent and its officers, directors, employees, representatives and agents, from
and against and reimburse the Collateral Agent for any and all claims, expenses,
obligations, liabilities, losses, damages, injuries (to person, property, or
natural resources), penalties, stamp or other similar taxes, actions, suits,
judgments, reasonable costs and expenses (including reasonable attorney's and
agent's fees and expenses) of whatever kind or nature regardless of their merit,
demanded, asserted or claimed against the Collateral Agent directly or
indirectly relating to, or arising from, claims against the Collateral Agent by
reason of its participation in the transactions contemplated hereby, including
without limitation all reasonable costs required to be associated with claims
for damages to persons or property, and reasonable attorneys' and consultants'
fees and expenses and court costs except to the extent caused by the Collateral
Agent's negligence or willful misconduct. The provisions of this Section 22(m)
shall survive the termination of this Agreement or the earlier resignation or
removal of the Collateral Agent.
(n) The Collateral Agent shall not be responsible in any manner
whatsoever for the correctness of any recitals, statements, representations or
warranties contained herein or in the other Security Documents, except for those
made by the Collateral Agent, or for filing any financing statement,
continuation statement or any other perfection instrument or notice, or for
recording or re-recording any Security Document in any public office at any time
or for taking
16
<PAGE>
any other action to perfect or maintain the perfection, priority or
effectiveness of any interest on any of the Collateral or in any other property
granted to it hereunder or under any of the other Security Documents. The
Collateral Agent makes no representations as to the value or condition of the
Collateral or any part thereof, or as to the title of the Grantor thereto or as
to the security afforded by the Security Documents or this Agreement or as to
the validity, execution, enforceability, legality or sufficiency of this
Agreement, of any other Security Document, of the Obligations secured hereby and
thereby and the Collateral Agent shall incur no liability or responsibility in
respect of any such matters. The Collateral Agent shall not be responsible for
insuring the Collateral or for the payment of taxes, charges, assessments or
liens upon the Collateral or for the maintenance of the Collateral, except that
in the event the Collateral Agent enters into possession of all or any part of
the Collateral, the Collateral Agent shall preserve the portion of the
Collateral in its possession.
(o) The Collateral Agent shall not be required to ascertain or inquire
as to the Grantor's performance of any of the covenants or agreements contained
herein or in any Security Document. Whenever it is necessary, or in the opinion
of the Collateral Agent advisable, for the Collateral Agent to ascertain the
amount of obligations then held by a Trustee, on behalf of the Holders of the
Senior Secured Notes, or Permitted Additional Senior Lender, the Collateral
Agent may conclusively rely on a certificate of such party as to such amount.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]
17
<PAGE>
IN WITNESS WHEREOF, Grantor and Collateral Agent have caused this Security
Agreement to be duly executed by their partners and officers thereunto duly
authorized, as of the day and year first above written.
GRANTOR:
COSO OPERATING COMPANY LLC,
a Delaware limited liability company
By: \s\ Christopher T. McCallion
-----------------------------
Christopher T. McCallion
Executive Vice President
COLLATERAL AGENT:
U.S. BANK TRUST NATIONAL ASSOCIATION,
as Collateral Agent
By: \s\ Judy P. Manansala
---------------------
Name: Judy P. Manansala
Its: Trust Officer
The undersigned consents and agrees to the foregoing:
COSO FINANCE PARTNERS.
a California general partnership
By: New CLOC Company, LLC
a Delaware limited liability company,
its Managing General Partner
By: \s\ Christopher T. McCallion
-----------------------------
Christopher T. McCallion
Executive Vice President
By: ESCA, LLC,
a Delaware limited liability company,
its General Partner
By: \s\ Christopher T. McCallion
----------------------------
Christopher T. McCallion
Executive Vice President
18
<PAGE>
Exhibit 23.1
[Letterhead of KPMG]
The Board of Directors
Caithness Coso Funding Corp.
We consent to the use of our report included herein for Caithness Coso Funding
Corp. dated April 23, 1999, relating to the balance sheet of Caithness Coso
Funding Corp. and to the reference to our firm under the heading "Experts" in
the registration statement.
/s/ KPMG LLP
New York, NY
October 6, 1999
<PAGE>
Exhibit 23.2
Consent of Independent Accountants
----------------------------------
We hereby consent to the use in this Amendment No. 1 to Registration Statement
on Form S-4 of Caithness Coso Funding Corp. of our reports dated February 12,
1999 relating to the combining and combined financial statements of Coso Finance
Partners and Coso Finance Partners II, the financial statements of Coso Energy
Developers and the financial statements of Coso Power Developers, which appear
in such Registration Statement. We also consent to the reference to us under
the heading "Experts" in such Registration Statement.
/s/ PRICEWATERHOUSECOOPERS LLP
San Francisco, California
October 6, 1999
<PAGE>
Exhibit 23.3
CONSENT OF SANDWELL ENGINEERING, INC.
In connection with the filing with the Securities and Exchange Commission
on or about October 7, 1999, of Amendment No. 1 to Registration Statement on
Form S-4 (the "Exchange Offer Registration Statement") of Caithness Coso Funding
Corp. (the "Issuer"), Coso Finance Partners, Coso Energy Developers and Coso
Power Developers, relating to the Issuer's offer to exchange any and all of its
outstanding 6.80% Series A Senior Secured Notes due 2001 for its 6.80% Series B
Senior Secured Notes due 2001 and any and all of its 9.05% Series A Senior
Secured Notes due 2009 for its 9.05% Series B Senior Secured Notes due 2009, the
undersigned hereby consents to the references to it in the prospectus (the
"Prospectus") included in the Exchange Offer Registration Statement and to the
inclusion of its report entitled "Project 263105 - Coso Geothermal Projects -
Independent Engineer's Report for Caithness Coso Funding Corp." dated May 20,
1999, as Exhibit A to the Prospectus.
Dated: October 6, 1999 SANDWELL ENGINEERING, INC.
By /s/ Richard G. Low
___________________________
Richard G. Low, P.Eng.
Project Manager
<PAGE>
Exhibit 23.4
CONSENT OF HENWOOD ENERGY SERVICES, INC.
In connection with the filing with the Securities and Exchange Commission
on or about October 7, 1999, of Amendment No. 1 to Registration Statement on
Form S-4 (the "Exchange Offer Registration Statement") of Caithness Coso Funding
Corp. (the "Issuer"), Coso Finance Partners, Coso Energy Developers and Coso
Power Developers, relating to the Issuer's offer to exchange any and all of its
outstanding 6.80% Series A Senior Secured Notes due 2001 for its 6.80% Series B
Senior Secured Notes due 2001 and any and all of its 9.05% Series A Senior
Secured Notes due 2009 for its 9.05% Series B Senior Secured Notes due 2009, the
undersigned hereby consents to the references to it in the prospectus (the
"Prospectus") included in the Exchange Offer Registration Statement and to the
inclusion of its report entitled "The Southern California Electricity Market and
Price Forecast 1999-2009" dated May 20, 1999, as Exhibit B to the Prospectus.
Dated: October 6, 1999 HENWOOD ENERGY SERVICES, INC.
By /s/ Kevin Woodruff
___________________________
Kevin Woodruff
Principal Consultant
<PAGE>
Exhibit 23.5
CONSENT OF GEOTHERMEX, INC.
In connection with the filing with the Securities and Exchange Commission
on or about October 7, 1999, of Amendment No. 1 to Registration Statement on
Form S-4 (the "Exchange Offer Registration Statement") of Caithness Coso Funding
Corp. (the "Issuer"), Coso Finance Partners, Coso Energy Developers and Coso
Power Developers, relating to the Issuer's offer to exchange any and all of its
outstanding 6.80% Series A Senior Secured Notes due 2001 for its 6.80% Series B
Senior Secured Notes due 2001 and any and all of its 9.05% Series A Senior
Secured Notes due 2009 for its 9.05% Series B Senior Secured Notes due 2009, the
undersigned hereby consents to the references to it in the prospectus (the
"Prospectus") included in the Exchange Offer Registration Statement and to the
inclusion of its report entitled "Independent Review of Steam Supply and
Resource - Related Capital and Operating Costs - Coso Geothermal Field for
Caithness Coso Funding Corporation [sic]" dated May 1999, as Exhibit C to the
Prospectus.
Dated: October 6, 1999 GEOTHERMEX, INC.
By /s/ Subir K. Sanyal
___________________________
Subir K. Sanyal
President
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<CIK> 0001088866
<NAME> CAITHNESS COSO FUNDING CORP.
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 6-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1999
<PERIOD-START> JAN-01-1998 JAN-01-1999
<PERIOD-END> DEC-31-1998 JUN-30-1999
<CASH> 0 0
<SECURITIES> 0 0
<RECEIVABLES> 0 0
<ALLOWANCES> 0 0
<INVENTORY> 0 0
<CURRENT-ASSETS> 0 0
<PP&E> 0 0
<DEPRECIATION> 0 0
<TOTAL-ASSETS> 0 413,000
<CURRENT-LIABILITIES> 0 0
<BONDS> 0 413,000
0 0
0 0
<COMMON> 0 0
<OTHER-SE> 0 0
<TOTAL-LIABILITY-AND-EQUITY> 0 413,000
<SALES> 0 0
<TOTAL-REVENUES> 0 4,986
<CGS> 0 0
<TOTAL-COSTS> 0 0
<OTHER-EXPENSES> 0 0
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 0 4,986
<INCOME-PRETAX> 0 0
<INCOME-TAX> 0 0
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 0
<NET-INCOME> 0 0
<EPS-BASIC> 0 0
<EPS-DILUTED> 0 0
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<CIK> 0001088870
<NAME> COSO FINANCE PARTNERS
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 6-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1999
<PERIOD-START> JAN-01-1998 JAN-01-1999
<PERIOD-END> DEC-31-1998 JUN-30-1999
<CASH> 0 3,049
<SECURITIES> 7,524 26,600
<RECEIVABLES> 9,186 8,958
<ALLOWANCES> 0 0
<INVENTORY> 0 0
<CURRENT-ASSETS> 17,136 38,826
<PP&E> 298,916 225,316
<DEPRECIATION> 118,536 67,363
<TOTAL-ASSETS> 201,888 219,013
<CURRENT-LIABILITIES> 11,389 17,462
<BONDS> 40,566 151,550
0 0
0 0
<COMMON> 0 0
<OTHER-SE> 0 0
<TOTAL-LIABILITY-AND-EQUITY> 201,888 219,013
<SALES> 53,153 25,609
<TOTAL-REVENUES> 53,738 27,507
<CGS> 0 0
<TOTAL-COSTS> 0 0
<OTHER-EXPENSES> 31,894 15,389
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 4,333 6,615
<INCOME-PRETAX> 0 0
<INCOME-TAX> 0 0
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 2,374
<CHANGES> 923 0
<NET-INCOME> 16,588 3,129
<EPS-BASIC> 0 0
<EPS-DILUTED> 0 0
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<CIK> 0001088869
<NAME> COSO ENERGY DEVELOPERS
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 6-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1999
<PERIOD-START> JAN-01-1998 JAN-01-1999
<PERIOD-END> DEC-31-1998 JUN-30-1999
<CASH> 0 8,153
<SECURITIES> 290 13,507
<RECEIVABLES> 19,835 8,615
<ALLOWANCES> 0 0
<INVENTORY> 0 0
<CURRENT-ASSETS> 21,651 30,640
<PP&E> 311,940 225,346
<DEPRECIATION> 110,340 64,235
<TOTAL-ASSETS> 228,087 220,032
<CURRENT-LIABILITIES> 26,938 24,796
<BONDS> 37,958 107,900
0 0
0 0
<COMMON> 0 0
<OTHER-SE> 0 0
<TOTAL-LIABILITY-AND-EQUITY> 228,087 220,032
<SALES> 107,199 28,220
<TOTAL-REVENUES> 108,380 28,670
<CGS> 0 0
<TOTAL-COSTS> 0 0
<OTHER-EXPENSES> 44,687 19,463
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 6,267 5,480
<INCOME-PRETAX> 0 0
<INCOME-TAX> 0 0
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 1,822
<CHANGES> 953 0
<NET-INCOME> 56,473 1,905
<EPS-BASIC> 0 0
<EPS-DILUTED> 0 0
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<CIK> 0001088873
<NAME> COSO POWER DEVELOPERS
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 6-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1999
<PERIOD-START> JAN-01-1998 JAN-01-1999
<PERIOD-END> DEC-31-1998 JUN-30-1999
<CASH> 818 13,042
<SECURITIES> 0 18,676
<RECEIVABLES> 22,504 25,891
<ALLOWANCES> 0 0
<INVENTORY> 0 0
<CURRENT-ASSETS> 24,016 57,935
<PP&E> 287,789 201,634
<DEPRECIATION> 98,927 54,578
<TOTAL-ASSETS> 218,965 243,326
<CURRENT-LIABILITIES> 3,981 6,859
<BONDS> 61,323 153,550
0 0
0 0
<COMMON> 0 0
<OTHER-SE> 0 0
<TOTAL-LIABILITY-AND-EQUITY> 218,965 243,326
<SALES> 119,564 52,697
<TOTAL-REVENUES> 121,363 53,580
<CGS> 0 0
<TOTAL-COSTS> 0 0
<OTHER-EXPENSES> 41,120 20,440
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 8,122 7,399
<INCOME-PRETAX> 0 0
<INCOME-TAX> 0 0
<INCOME-CONTINUING> 0 0
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 2,147
<CHANGES> 1,664 0
<NET-INCOME> 70,457 23,594
<EPS-BASIC> 0 0
<EPS-DILUTED> 0 0
</TABLE>
<PAGE>
Exhibit 99.1
CAITHNESS COSO FUNDING CORP.
LETTER OF TRANSMITTAL
OFFER TO EXCHANGE
6.80% Series B Senior Secured Notes Due 2001
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
6.80% Series A Senior Secured Notes Due 2001
and
9.05% Series B Senior Secured Notes Due 2009
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
9.05% Series A Senior Secured Notes Due 2009
Pursuant to the Prospectus
Dated October 7, 1999
- ----------------------------------------------------------------------
THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT
5:00 P.M., NEW YORK CITY TIME, ON MONDAY, NOVEMBER 8, 1999, UNLESS
THE OFFER IS EXTENDED.
- ----------------------------------------------------------------------
The Exchange Agent for the Exchange Offer is:
U.S. BANK TRUST NATIONAL ASSOCIATION
<TABLE>
<CAPTION>
<S> <C> <C>
By Registered or Certified Mail: By Hand: By Overnight Delivery of Courier:
U.S. Bank Trust U.S. Bank Trust U.S. Bank Trust
National Association National Association National Association
180 East Fifth Street 180 East Fifth Street 180 East Fifth Street
St. Paul, MN 55101 St. Paul, MN 55101 St. Paul, MN 55101
</TABLE>
Attention:
4th Floor Bond Drop Window
Facsimile Transmission Number:
(For Eligible Institutions Only)
(651) 244-1537
Confirm by Telephone:
Bondholder Communications
(800) 934-6802
Delivery of this Letter of Transmittal to an address other than as set
forth above, or transmission of this Letter of Transmittal via facsimile to a
number other than as set forth above, does not constitute a valid delivery.
PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.
<PAGE>
The undersigned acknowledges receipt of the Prospectus dated October 7,
1999 (the "Prospectus"), of Caithness Coso Funding Corp. (the "Issuer"),
relating to the offer by the Issuer, upon the terms and subject to the
conditions set forth in the Prospectus and this Letter of Transmittal and the
instructions hereto (the Prospectus, this Letter of Transmittal and the
instructions hereto constitute the "Exchange Offer"), to exchange its 6.80%
Series B Senior Secured Notes due 2001 for any and all of its outstanding 6.80%
Series A Senior Secured Notes due 2001 and its 9.05% Series B Senior Secured
Notes due 2009 for any and all of its outstanding 9.05% Series A Senior Secured
Notes due 2009. The 6.80% Series A Senior Secured Notes due 2001 and the 9.05%
Series A Senior Secured Notes due 2009 are called the "Series A Notes," and the
6.80% Series B Senior Secured Notes due 2001 and the 9.05% Series B Senior
Secured Notes due 2009 are called the "Series B Notes." Only Series B Notes due
2001 may be exchanged for tendered Series A Notes due 2001, and only Series B
Notes due 2009 may be exchanged for tendered Series A Notes due 2009.
Capitalized terms used but not defined herein shall have the same meaning given
them in the Prospectus.
This Letter of Transmittal is to be completed by holders of Series A Notes
if Series A Notes are to be forwarded herewith. If tenders of Series A Notes
are to be made by book-entry transfer to an account maintained by U.S. Bank
Trust National Association (the "Exchange Agent") at The Depository Trust
Company ("DTC") pursuant to the procedures set forth in "The Exchange Offer--
Procedures for Tendering" in the Prospectus and in accordance with the Automated
Tender Offer Program ("ATOP") established by DTC, a tendering holder will become
bound by the terms and conditions hereof in accordance with the procedures
established under ATOP.
Holders of Series A Notes whose certificates for the Series A Notes are not
immediately available or who cannot deliver their certificates and all other
required documents to the Exchange Agent on or prior to the Expiration Date (as
defined in the Prospectus) or who cannot complete the procedures for book-entry
transfer on a timely basis, must tender their Series A Notes according to the
guaranteed delivery procedures set forth in "The Exchange Offer--Guaranteed
Delivery Procedures" in the Prospectus. SEE INSTRUCTION 1. DELIVERY OF
DOCUMENTS TO DTC IN ACCORDANCE WITH ITS PROCEDURES DOES NOT CONSTITUTE DELIVERY
TO THE EXCHANGE AGENT.
Any holder of Series A Notes participating in the exchange offer for the
purpose of participating in a distribution of the Series B Notes to be acquired
in the Exchange Offer cannot rely on the position of the Staff of the Division
of Corporation Finance of the Securities and Exchange Commission enunciated in
Exxon Capital Holdings Corporation (available April 13, 1989) or similar letters
and must comply with the registration and prospectus delivery requirements of
the Securities Act in connection with a secondary resale transaction.
Any broker-dealer who holds Series A Notes acquired for its own account as
a result of market-making activities or other trading activities, and who
receives Series B Notes in exchange for such Series A Notes pursuant to the
Exchange Offer, may be a statutory underwriter and must deliver a prospectus
meeting the requirements of the Securities Act in connection with any resale of
such Series B Notes.
2
<PAGE>
The Instructions contained herein and in the Prospectus should be read
carefully before this Letter of Transmittal is completed.
- ------------------------------------------------------------------------------
CHECK THE BOX TO INDICATE TO WHICH SERIES OF SERIES A NOTES THIS LETTER OF
TRANSMITTAL RELATES. USE A SEPARATE LETTER OF TRANSMITTAL FOR EACH SERIES
OF SERIES A NOTES.
[_] 6.80% Series A Senior Secured Notes due 2001
[_] 9.05% Series A Senior Secured Notes due 2009
- ------------------------------------------------------------------------------
List below the Series A Notes to which this Letter of Transmittal relates.
If the space provided below is inadequate, list the certificate numbers and
principal amounts on a separately executed schedule and affix the schedule to
this Letter of Transmittal. Tenders of Series A Notes will be accepted only in
principal amounts equal to $1,000 or integral multiples thereof.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
DESCRIPTION OF SERIES A NOTES
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Name(s) and Address(es) of Holder(s) Certificate Aggregate Principal Amount
(Please fill in, if blank) Number(s)* Principal Amount Tendered
Represented**
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
TOTAL PRINCIPAL AMOUNT OF SERIES A NOTES
- ------------------------------------------------------------------------------------------------------------
* Need not be completed by Holders tendering by book-entry transfer (see below).
** Unless otherwise indicated in the column labeled "Principal Amount Tendered" and subject to the terms
and conditions of the Exchange Offer, a Holder will be deemed to have tendered the entire aggregate
principal amount represented by the Series A Notes indicated in the column labeled "Aggregate
Principal Amount Represented." See Instruction 4.
- ------------------------------------------------------------------------------------------------------------
</TABLE>
3
<PAGE>
[_] CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED BY BOOK-ENTRY
TRANSFER TO THE ACCOUNT MAINTAINED BY THE DEPOSITARY WITH DTC AND COMPLETE
THE FOLLOWING:
Name of Tendering Institution: _____________________________________
Account Number with DTC: ___________________________________________
VOI Number: ________________________________________________________
[_] CHECK HERE IF TENDERED SERIES A NOTES ARE BEING DELIVERED PURSUANT TO A
NOTICE OF GUARANTEED DELIVERY PREVIOUSLY DELIVERED TO THE DEPOSITARY
AND COMPLETE THE FOLLOWING:
Name of Registered Holder(s): ______________________________________
Window Ticket No. (if any):_________________________________________
Date of Execution of Notice of Guaranteed Delivery: ________________
Name of Eligible Institution that Guaranteed Delivery: _____________
If Delivered by Book-Entry Transfer: _______________________________
Account Number with DTC: ___________________________________________
VOI Number: ________________________________________________________
4
<PAGE>
Ladies and Gentlemen:
The undersigned hereby tenders to Caithness Coso Funding Corp., a Delaware
corporation (the "Company"), the principal amount of the Company's 6.80% Series
A Senior Secured Notes due 2001 specified above for a like aggregate principal
amount of the Company's 6.80% Series A Senior Secured Notes due 2001 or the
Company's 9.05% Series A Senior Secured Notes due 2009 specified above in
exchange for a like aggregate principal amount of the Company's 9.05% Series B
Senior Secured Notes due 2009, upon the terms and subject to the conditions set
forth in the Prospectus dated October 7, 1999 (as the same may be amended or
supplemented from time to time, the "Prospectus"), receipt of which is hereby
acknowledged, and in this Letter of Transmittal (which, together with the
Prospectus, constitute the "Exchange Offer"). The Exchange Offer has been
registered under the Securities Act of 1933, as amended (the "Securities Act").
Subject to and effective upon the acceptance for exchange of all or any
portion of the Series A Notes tendered herewith in accordance with the terms and
conditions of the Exchange Offer (including, if the Exchange Offer is extended
or amended, the terms and conditions of any such extension or amendment), the
undersigned hereby sells, assigns and transfers to or upon the order of the
Company all right, title and interest in and to such Series A Notes as are being
tendered herewith. The undersigned hereby irrevocably constitutes and appoints
the Exchange Agent as its agent and attorney-in-fact (with full knowledge that
the Exchange Agent is also acting as agent of the Company in connection with the
Exchange Offer) with respect to the tendered Series A Notes, with full power of
substitution (such power of attorney being deemed to be an irrevocable power
coupled with an interest), subject only to the right of withdrawal described in
the Prospectus, to (i) deliver certificates for tendered Series A Notes to the
Company, together with all accompanying evidences of transfer and authenticity
to, or upon the order of, the Company, upon receipt by the Exchange Agent, as
the undersigned's agent, of the Series B Notes to be issued in exchange for such
Series A Notes, (ii) present certificates for such Series A Notes for transfer,
and to transfer the Series A Notes on the books of the Company and (iii) receive
for the account of the Company all benefits and otherwise exercise all rights of
beneficial ownership of such Series A Notes, all in accordance with the terms
and conditions of the Exchange Offer.
The undersigned hereby represents and warrants that the undersigned has
full power and authority to tender, exchange, sell, assign and transfer the
Series A Notes tendered hereby and that, when the same are accepted for
exchange, the Company will acquire good, marketable and unencumbered title
thereto, free and clear of all liens, restrictions, charges and encumbrances,
and that the Series A Notes tendered hereby are not subject to any adverse
claims or proxies. The undersigned will, upon request, execute and deliver any
and all additional documents deemed by the Company or the Exchange Agent to be
necessary or desirable to complete the exchange, assignment and transfer of the
Series A Notes tendered hereby. The undersigned has read and agrees to all of
the terms of the Exchange Offer.
The name(s) and address(es) of the registered holder(s) of the Series A
Notes tendered hereby should be printed above, if they are not already set forth
above, as they appear on the certificates representing such Series A Notes. The
certificate number(s) and the Series A Notes that the undersigned wishes to
tender should be indicated in the appropriate boxes above.
If any tendered Series A Notes are not exchanged pursuant to the Exchange
Offer for any reason, or if certificates are submitted for more Series A Notes
than are tendered or accepted for exchange, certificates for such unaccepted or
nonexchanged Series A Notes will be returned (or, in the case of Series A Notes
tendered by book-entry transfer, such Series A Notes will be credited to an
account maintained at DTC), without expense to the tendering holder, promptly
following the expiration or termination of the Exchange Offer.
The undersigned understands that tenders of Series A Notes pursuant to any
one of the procedures described in "The Exchange Offer--Procedures for
Tendering" in the Prospectus and in the instructions hereto will, upon the
Company's acceptance for exchange of such tendered Series A Notes, constitute a
binding agreement between the undersigned and the Company upon the terms and
subject to the conditions of the Exchange Offer. In all cases in which a
participant elects to accept the Exchange Offer by transmitting an express
acknowledgment in accordance with the established ATOP procedures, such
participant shall be bound by all of the terms and conditions of this Letter of
Transmittal. The undersigned recognizes that, under certain circumstances set
forth in the Prospectus, the Company may not be required to accept for exchange
any of the Series A Notes tendered hereby.
5
<PAGE>
Unless otherwise indicated herein in the box entitled "Special Issuance
Instructions" below, the undersigned hereby directs that the Series B Notes be
issued in the name(s) of the undersigned or, in the case of a book-entry
transfer of Series A Notes, that such Series B Notes be credited to the account
indicated above maintained at DTC. If applicable, substitute certificates
representing Series A Notes not exchanged or not accepted for exchange will be
issued to the undersigned or, in the case of a book-entry transfer of Series A
Notes, will be credited to the account indicated above maintained at DTC.
Similarly, unless otherwise indicated under "Special Delivery Instructions,"
please deliver Series B Notes to the undersigned at the address shown below the
undersigned's signature.
By tendering Series A Notes and executing, or otherwise becoming bound by,
this Letter of Transmittal, the undersigned hereby represents and agrees that:
(i) the undersigned is not an "affiliate" of the Company,
(ii) any Series B Notes to be received by the undersigned are being
acquired in the ordinary course of its business, and
(iii) the undersigned is not engaged in, does not intend to engage in, and
has no arrangement or understanding with any person to participate
in, a distribution of the Series B Notes.
By tendering Series A Notes pursuant to the Exchange Offer and executing,
or otherwise becoming bound by, this Letter of Transmittal, a holder of Series A
Notes which is a broker-dealer represents and agrees, consistent with certain
interpretive letters issued to third parties by the Staff of the Division of
Corporation Finance of the Securities and Exchange Commission, that (a) such
Series A Notes held by the broker-dealer are held only as a nominee or (b) such
Series A Notes were acquired by such broker-dealer for its own account as a
result of market-making activities or other trading activities and it will
deliver a prospectus meeting the requirements of the Securities Act in
connection with any resale of such Series B Notes (provided that, by so
acknowledging and by delivering a prospectus, such broker-dealer will not be
deemed to admit that it is an "underwriter" within the meaning of the Securities
Act).
The Company has agreed that, subject to the provisions of the Registration
Rights Agreement, the Prospectus, as it may be amended or supplemented from time
to time, may be used by a participating broker-dealer (as defined below) in
connection with resales of Series B Notes received in exchange for Series A
Notes, where such Series A Notes were acquired by such participating broker-
dealer for its own account as a result of market-making activities or other
trading activities, for a period ending 180 days after the expiration date
(subject to extension under certain limited circumstances) or, if earlier, when
all such Series B Notes have been disposed of by each participating broker-
dealer. In that regard, each broker dealer who acquired Series A Notes for its
own account as a result of market-making or other trading activities (a
"participating broker-dealer"), by tendering such Series A Notes and executing,
or otherwise becoming bound by, this Letter of Transmittal, agrees that, upon
receipt of notice from the Company of the occurrence of any event or the
discovery of any fact which makes any statement contained in the Prospectus
untrue in any material respect or which causes the Prospectus to omit to state a
material fact necessary in order to make the statements contained therein, in
light of the circumstances under which they were made, not misleading or of the
occurrence of certain other events specified in the Registration Rights
Agreement, such participating broker-dealer will suspend the sale of Series B
Notes pursuant to the Prospectus until the Company has amended or supplemented
the Prospectus to correct such misstatement or omission and has furnished copies
of the amended or supplemented Prospectus to the participating broker-dealer or
the Company has given notice that the sale of the Series B Notes may be resumed,
as the case may be. If the Company gives such notice to suspend the sale of the
Series B Notes, it shall extend the 180-day period referred to above during
which participating broker-dealers are entitled to use the Prospectus in
connection with the resale of Series B Notes by the number of days during the
period from and including the date of the giving of such notice to and including
the date when participating broker-dealers shall have received copies of the
supplemented or amended Prospectus necessary to permit resales of the Series B
Notes or to and including the date on which the Company has given notice that
the sale of Series B Notes may be resumed, as the case may be.
All authority herein conferred or agreed to be conferred in this Letter of
Transmittal shall survive the death or incapacity of the undersigned and any
obligation of the undersigned hereunder shall be binding upon the heirs,
6
<PAGE>
executors, administrators, personal representatives, trustees in bankruptcy,
legal representatives successors and assigns of the undersigned. Except as
stated in the Prospectus, this tender is irrevocable.
PLEASE SIGN HERE
(To be completed by all tendering holders of Series A Notes regardless of
whether Series A Notes are being physically delivered herewith,
unless an Agent's Message is delivered in connection with
a Book-Entry Transfer of such Series A Notes)
This Letter of Transmittal must be signed by the Registered Holder(s) of
Series A Notes exactly as their name(s) appear(s) on certificate(s) for Notes
or, if tendered by a participant in DTC, exactly as such participant's name
appears on a security position listing as the owner of Series A Notes, or by
person(s) authorized to become Registered Holder(s) by endorsements and
documents transmitted with this Letter of Transmittal. If the signature is by a
trustee, executor, administrator, guardian, attorney-in-fact, officer or other
person acting in a fiduciary or representative capacity, such person must set
forth his or her full title below under "Capacity" and submit evidence
satisfactory to the Company of such person's authority to so act. See
Instruction 5 below.
If the signature appearing below is not of the Registered Holder(s) of the
Series A Notes, then the Registered Holder(s) must sign a valid proxy.
X ___________________________________________________________________________
X ___________________________________________________________________________
(Signature(s) of Holder(s) or Authorized Signatory)
Date: ___________________, 1999.
Name(s): ___________________________________________________________________
____________________________________________________________________________
(Please Print)
Capacity: __________________________________________________________________
Address: ___________________________________________________________________
____________________________________________________________________________
____________________________________________________________________________
(Including ZIP Code)
Area Code and Telephone No.: _______________________________________________
7
<PAGE>
SIGNATURE GUARANTEE
(See Instructions 1 and 5 below)
Certain Signatures Must be Guaranteed by a Medallion Signature Guarantor
____________________________________________________________________________
(Name of Medallion Signature Guarantor Guaranteeing Signatures)
____________________________________________________________________________
____________________________________________________________________________
____________________________________________________________________________
(Address (including ZIP Code) and Telephone Number (including Area Code) of
Firm)
____________________________________________________________________________
(Authorized Signature)
____________________________________________________________________________
(Print Name)
____________________________________________________________________________
(Title)
Date: ___________________, 1999.
8
<PAGE>
SPECIAL ISSUANCE INSTRUCTIONS
(See Instructions 1, 5 and 6)
To be completed ONLY if the Series B Notes are to be issued in the name of
someone other than the registered holder of the Series A Notes whose name(s)
appear(s) above.
Issue Series B Notes to:
Name(s):____________________________________________________________________
(Please Print)
Address:____________________________________________________________________
(Please Print)
____________________________________________________________________________
ZIP Code
____________________________________________________________________________
Area Code and Telephone Number
____________________________________________________________________________
(Tax Identification or Social Security Number(s))
9
<PAGE>
SPECIAL DELIVERY INSTRUCTIONS
(See Instructions 1, 5 and 6)
To be completed ONLY if the Series B Notes are to be sent to someone other
than the registered holder of the Series A Notes whose name(s) appear(s) above,
or to such registered holder(s) at an address other than that shown above.
Mail Series B Notes To:
Name(s): ___________________________________________________________________
(Please Print)
Address: ___________________________________________________________________
(Please Print)
____________________________________________________________________________
ZIP Code
____________________________________________________________________________
Area Code and Telephone Number
____________________________________________________________________________
(Tax Identification or Social Security Number(s))
10
<PAGE>
INSTRUCTIONS
FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER
1. Delivery of Letter of Transmittal and Certificates; Guaranteed
Delivery Procedures. This Letter of Transmittal is to be completed if
certificates are to be forwarded herewith. If tenders are to be made pursuant
to the procedures for tender by book-entry transfer in accordance with ATOP
established by DTC, a tendering holder will become bound by the terms and
conditions hereof in accordance with the procedures established under ATOP.
Certificates, or timely confirmation of a book-entry transfer of such Series A
Notes into the Exchange Agent's account at DTC, as well as this Letter of
Transmittal (or facsimile thereof), if required, properly completed and duly
executed, with any required signature guarantees, must be received by the
Exchange Agent at one of its addresses set forth herein on or prior to the
Expiration Date. Series A Notes may be tendered in whole or in part in the
principal amount of $1,000 and integral multiples of $1,000.
Holders who wish to tender their Series A Notes and (i) whose Series A
Notes are not immediately available or (ii) who cannot deliver their Series A
Notes and this Letter of Transmittal to the Exchange Agent on or prior to the
Expiration Date or (iii) who cannot complete the procedures for delivery by
book-entry transfer on a timely basis, may tender their Series A Notes by
properly completing and duly executing a Notice of Guaranteed Delivery pursuant
to the guaranteed delivery procedures set forth in "The Exchange Offer--
Guaranteed Delivery Procedures" in the Prospectus. Pursuant to such procedures:
(i) such tender must be made by or through an Eligible Institution (as defined
below); (ii) a properly completed and duly executed Letter of Transmittal (or
facsimile thereof), and Notice of Guaranteed Delivery, substantially in the form
made available by the Company, must be received by the Exchange Agent on or
prior to the expiration date; and (iii) the certificates (or a book-entry
confirmation) representing all tendered Series A Notes, in proper form for
transfer, must be received by the Exchange Agent within three New York Stock
Exchange trading days after the date of execution of such Notice of Guaranteed
Delivery, and otherwise as provided in "The Exchange Offer--Guaranteed Delivery
Procedures" in the Prospectus.
The Notice of Guaranteed Delivery may be delivered by hand or transmitted
by telegram, telex, facsimile or mail to the Exchange Agent, and must include a
guarantee by an Eligible Institution in the form set forth in such Notice. For
Series A Notes to be properly tendered pursuant to the guaranteed delivery
procedure, the Exchange Agent must receive a Notice of Guaranteed Delivery on or
prior to the Expiration Date. As used herein and in the Prospectus, "Eligible
Institution" means a firm which is a member of a registered national securities
exchange or a member of the National Association of Securities Dealers, Inc. or
a commercial bank or trust company having an office or correspondent in the
United States.
The method of delivery of Series A Notes, this Letter of Transmittal and
all other required documents is at the election and risk of the tendering
holder. If such delivery is by mail, it is recommended that registered mail
with return receipt requested, properly insured, be used. In all cases,
sufficient time should be allowed to assure timely delivery. No letters of
transmittal or Series A Notes should be sent to the Company.
The Company will not accept any alternative, conditional or contingent
tenders. Each tendering holder, by execution of a Letter of Transmittal (or
facsimile thereof), or any Agent's Message in lieu thereof, waives any right to
receive any notice of the acceptance of such tender.
2. Guarantee of Signatures. No signature guarantee on this Letter of
Transmittal is required if:
(i) this Letter of Transmittal is signed by the registered holder
(which term, for purposes of this document, shall include any
participant in DTC whose name appears on a security position
listing as the owner of the Series A Notes) of Series A Notes
tendered herewith, unless such holder(s) has completed either
the box entitled "Special Issuance Instructions" or the box
entitled "Special Delivery Instructions" above, or
(ii) such Series A Notes are tendered for the account of a firm that
is an Eligible Institution.
11
<PAGE>
In all other cases, an Eligible Institution must guarantee the signature(s)
on this Letter of Transmittal. See Instruction 5.
3. Inadequate Space. If the space provided in the box captioned
"Description of Series A Notes" is inadequate, the certificate number(s) and/or
the principal amount of Series A Notes and any other required information should
be listed on a separate signed schedule which is attached to this Letter of
Transmittal.
4. Partial Tenders and Withdrawal Rights. Tenders of Series A Notes will
be accepted only in the principal amount of $1,000 and integral multiples
thereof. If less than all the Series A Notes evidenced by any certificate
submitted are to be tendered, fill in the principal amount of Series A Notes
which are to be tendered in the box entitled "Principal Amount Tendered." In
such case, new certificate(s) for the remainder of the Series A Notes that were
evidenced by your old certificate(s) will only be sent to the holder of the
Series A Notes, promptly after the Expiration Date. All Series A Notes
represented by certificates delivered to the Exchange Agent will be deemed to
have been tendered unless otherwise indicated.
Except as otherwise provided herein, tenders of Series A Notes may be
withdrawn at any time on or prior to the Expiration Date. In order for a
withdrawal to be effective on or prior to that time, a written notice of
withdrawal must be timely received by the Exchange Agent at one of its addresses
set forth above or in the Prospectus on or prior to the Expiration Date. Any
such notice of withdrawal must specify the name of the person who tendered the
Series A Notes to be withdrawn, identify the Series A Notes to be withdrawn
(including the principal amount of such Series A Notes) and (where certificates
for Series A Notes have been transmitted) specify the name in which such Series
A Notes are registered, if different from that of the withdrawing holder. If
certificates for the Series A Notes have been delivered or otherwise identified
to the Exchange Agent, then prior to the release of such certificates, the
withdrawing holder must submit the serial numbers of the particular certificates
for the Series A Notes to be withdrawn and a signed notice of withdrawal with
signatures guaranteed by an Eligible Institution, unless such holder is an
Eligible Institution. If Series A Notes have been tendered pursuant to the
procedures for book-entry transfer, any notice of withdrawal must specify the
name and number of the account at DTC to be credited with the withdrawal of
Series A Notes and otherwise comply with the procedures of such facility.
Series A Notes properly withdrawn will not be deemed validly tendered for
purposes of the Exchange Offer, but may be retendered at any time on or prior to
the Expiration Date by following one of the procedures described in the
Prospectus under "The Exchange Offer--Withdrawal Rights."
All questions as to the validity, form and eligibility (including time of
receipt) of such withdrawal notices will be determined by the Company, whose
determination shall be final and binding on all parties. Any Series A Notes
which have been tendered for exchange but which are not exchanged for any reason
will be returned to the holder thereof without cost to such holder (or, in the
case of Series A Notes tendered by book-entry transfer into the Exchange Agent's
account at DTC pursuant to the book-entry procedures described in the Prospectus
such Series A Notes will be credited to an account maintained with DTC for the
Series A Notes) as soon as practicable after withdrawal, rejection of tender or
termination of the Exchange Offer.
5. Signatures on Letter of Transmittal, Assignments and Endorsements. If
this Letter of Transmittal is signed by the registered holder(s) of the Series A
Notes tendered hereby, the signature(s) must correspond exactly with the name(s)
as written on the face of the certificate(s) without alteration, enlargement or
any change whatsoever.
If any of the Series A Notes tendered hereby are owned of record by two or
more joint owners, all such owners must sign this Letter of Transmittal.
If any tendered Series A Notes are registered in different names on several
certificates, it will be necessary to complete, sign and submit as many separate
Letters of Transmittal (or facsimiles thereof) as there are different
registrations of certificates.
If this Letter of Transmittal or any certificates or powers of attorney are
signed by trustees, executors, administrators, guardians, attorneys-in-fact,
officers of corporations or others acting in a fiduciary or representative
capacity, such persons should so indicate when signing and, unless waived by the
Company, proper evidence satisfactory to the Company of such persons' authority
to so act must be submitted.
12
<PAGE>
When this Letter of Transmittal is signed by the registered holder(s) of
the Series A Notes listed and transmitted hereby, no endorsement(s) of
certificate(s) or written instrument or instruments of transfer or exchange are
required unless Series B Notes are to be issued in the name of a person other
than the registered holder(s). Signature(s) on such certificate(s) or written
instrument or instruments of transfer or exchange must be guaranteed by an
Eligible Institution.
If this Letter of Transmittal is signed by a person other than the
registered holder(s) of the Series A Notes listed, the certificates must be
endorsed or accompanied by a written instrument or instruments of transfer or
exchange, in satisfactory form as determined by the Company in its sole
discretion and executed by the registered holder(s), in either case signed
exactly as the name or names of the registered holder(s) appear(s) on the
certificates. Signatures on such certificates or written instrument or
instruments of transfer or exchange must be guaranteed by an Eligible
Institution.
6. Special Issuance and Delivery Instructions. If Series B Notes are to
be issued in the name of a person other than the signer of this Letter of
Transmittal, or if Series B Notes are to be sent to someone other than the
signer of this Letter of Transmittal or to an address other than that shown
above, the appropriate boxes on this Letter of Transmittal should be completed.
Certificates for Series A Notes not exchanged will be returned by mail or, if
tendered by book-entry transfer, by crediting the account indicated above
maintained at DTC. See Instruction 4.
7. Irregularities. The Company will determine, in its sole discretion,
all questions as to the form, validity, eligibility (including time of receipt)
and acceptance for exchange of any tender of Series A Notes, which determination
shall be final and binding. The Company reserves the absolute right to reject
any and all tenders of any particular Series A Notes not properly tendered or to
not accept any particular Series A Notes which acceptance might, in the judgment
of the Company or its counsel, be unlawful. The Company also reserves the
absolute right, in its sole discretion, to waive any defects or irregularities
or conditions of the Exchange Offer as to any particular Series A Notes either
before or after the expiration date (including the right to waive the
ineligibility of any holder who seeks to tender Series A Notes in the Exchange
Offer). The interpretation of the terms and conditions of the Exchange Offer as
to any particular Series A Notes either before or after the Expiration Date
(including the Letter of Transmittal and the instructions thereto) by the
Company shall be final and binding on all parties. Unless waived, any defects
or irregularities in connection with the tender of Series A Notes for exchange
must be cured within such reasonable period of time as the Company shall
determine. Neither the Company, the Exchange Agent nor any other person shall
be under any duty to give notification of any defect or irregularity with
respect to any tender of Series A Notes for exchange, nor shall any of them
incur any liability for failure to give such notification.
8. Questions, Requests for Assistance and Additional Copies. Questions
and requests for assistance may be directed to the Exchange Agent at its address
and telephone number set forth on the front of this Letter of Transmittal.
Additional copies of the Prospectus, the Notice of Guaranteed Delivery and the
Letter of Transmittal may be obtained from the Exchange Agent or from your
broker, dealer, commercial bank, trust company or other nominee.
9. Lost, Destroyed or Stolen Certificates. If any certificate(s)
representing Series A Notes have been lost, destroyed or stolen, the holder
should promptly notify the Exchange Agent. The holder will then be instructed
as to the steps that must be taken in order to replace the certificate(s). This
Letter of Transmittal and related documents cannot be processed until the
procedures for replacing lost, destroyed or stolen certificate(s) have been
followed.
10. Security Transfer Taxes. Holders who tender their Series A Notes for
exchange will not be obligated to pay any transfer taxes in connection
therewith, except that holders who instruct the Company to register Series B
Notes in the name of or request that Series A Notes not tendered or not accepted
in the Exchange Offer to be returned to, a person other than the registered
tendering holder will be responsible for the payment of any applicable transfer
tax thereon.
IMPORTANT: This Letter of Transmittal (or facsimile thereof), or an
Agent's Message in lieu thereof, and all other required
documents must be received by the Exchange Agent on or prior to
the Expiration Date.
13
<PAGE>
EXHIBIT 99.2
CAITHNESS COSO FUNDING CORP.
NOTICE OF GUARANTEED DELIVERY
For Tender of
6.80% Series A Senior Secured Notes Due 2001
9.05% Series A Senior Secured Notes Due 2009
This Notice of Guaranteed Delivery or one substantially equivalent hereto
must be used to accept the Exchange Offer (as defined below) if (i) certificates
for the Company's (as defined below) 6.80% Series A Senior Secured Notes due
2001 and/or 9.05% Series A Senior Secured Notes due 2009 (collectively, the
"Series A Notes") are not immediately available, (ii) Series A Notes, the Letter
of Transmittal and any other documents required by the Letter of Transmittal
cannot be delivered to U.S. Bank Trust National Association (the "Exchange
Agent") on or prior to the Expiration Date (as defined in the Prospectus
referred to below) or (iii) the procedures for book-entry transfer cannot be
completed on a timely basis. This Notice of Guaranteed Delivery may be
delivered by hand or sent by facsimile transmission, overnight courier, telex,
telegram or mail to the Exchange Agent. See "The Exchange Offer--Guaranteed
Delivery Procedures" in the Prospectus dated October 7, 1999 (which, together
with the related Letter of Transmittal, constitutes the "Exchange Offer") of
Caithness Coso Funding Corp., a Delaware corporation (the "Company").
<TABLE>
<CAPTION>
U.S. Bank Trust National Association
<S> <C> <C>
By Registered or Certified Mail: By Hand: By Overnight Delivery or Courier:
U.S. Bank Trust National U.S. Bank Trust U.S. Bank Trust National
Association National Association Association
180 East Fifth Street 180 East Fifth Street 180 East Fifth Street
St. Paul, MN 55101 St. Paul, MN 55101 St. Paul, MN 55101
Attention:
4th Floor Bond Drop Window
Facsimile Transmission Number:
(For Eligible Institutions Only)
(651) 244-1537
Confirm by Telephone:
Bondholder Communications
(800) 934-6802
</TABLE>
DELIVERY OF THIS NOTICE OF GUARANTEED DELIVERY TO AN ADDRESS OTHER THAN AS
SET FORTH ABOVE OR TRANSMISSION OF THIS NOTICE OF GUARANTEED DELIVERY VIA A
FACSIMILE TRANSMISSION TO A NUMBER OTHER THAN AS SET FORTH ABOVE WILL NOT
CONSTITUTE A VALID DELIVERY.
THIS NOTICE OF GUARANTEED DELIVERY IS NOT TO BE USED TO GUARANTEE
SIGNATURES. IF A SIGNATURE ON A LETTER OF TRANSMITTAL IS REQUIRED TO BE
GUARANTEED BY AN "ELIGIBLE INSTITUTION" UNDER THE INSTRUCTIONS THERETO, SUCH
SIGNATURE GUARANTEE MUST APPEAR IN THE APPLICABLE SPACE PROVIDED ON THE LETTER
OF TRANSMITTAL.
- ------------------------------------------------------------------------------
THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK
CITY TIME, ON MONDAY, NOVEMBER 8, 1999, UNLESS THE OFFER IS EXTENDED.
- ------------------------------------------------------------------------------
<PAGE>
Ladies and Gentlemen:
The undersigned hereby tenders to the Company, upon the terms and subject
to the conditions set forth in the Prospectus dated October 7, 1999
("Prospectus") and in the related Letter of Transmittal (which, together with
any amendments or supplements thereto, collectively constitute the "Exchange
Offer"), receipt of each of which is hereby acknowledged, the principal amount
of Series A Notes indicated below pursuant to the guaranteed delivery procedures
set forth in the Prospectus under the caption "The Exchange Offer--Guaranteed
Delivery Procedures."
<TABLE>
<CAPTION>
<S> <C>
Signature(s) ________________________________ Address(es) __________________________________
______________________________________________
Name(s) of Eligible Holders Zip Code
____________________________________________ Area Code and Tel. No(s). ____________________
____________________________________________
Please Type or Print (Check box if Series A Notes will be tendered by
book-entry transfer)
Principal Amount of Series A Notes Tendered for
Exchange $ ________________________ [_] The Depository Trust Company
Series A Note Certificate No(s). (If available)
____________________________________________ Account Number _______________________________
____________________________________________
____________________________________________
Dated ________________________________, 1999
</TABLE>
2
<PAGE>
THE FOLLOWING GUARANTEE MUST BE COMPLETED
GUARANTEE OF DELIVERY
(NOT TO BE USED FOR SIGNATURE GUARANTEE)
The undersigned, a firm which is a member of a registered national
securities exchange or a member of the National Association of Securities
Dealers, Inc. or a commercial bank or trust company having an office or
correspondent in the United States, hereby guarantees to deliver to the Exchange
Agent, at one of its addresses set forth above, either the certificates for all
physically tendered Series A Notes, in proper form for transfer, or confirmation
of the book-entry transfer of such Series A Notes to the Exchange Agent's
account at The Depository Trust Company ("DTC"), pursuant to the procedures for
book-entry transfer set forth in the Prospectus, in either case together with
any other documents required by the Letter of Transmittal, within three New
York Stock Exchange trading days after the date of execution of this Notice of
Guaranteed Delivery.
The undersigned acknowledges that it must deliver the Series A Notes
tendered hereby to the Exchange Agent within the time period set forth above and
that failure to do so could result in a financial loss to the undersigned.
X
- ------------------------------------- -----------------------
Authorized Signature Date
Name:
-----------------------------------------------------------------
-----------------------------------------------------------------
(Please Print)
Capacity: -----------------------------------------------------------------
(Include Full Title)
Name of Firm:
-----------------------------------------------------------------
Address:
-----------------------------------------------------------------
-----------------------------------------------------------------
(Include Zip Code)
Area Code and Telephone Number:
-----------------------------------------------
NOTE: DO NOT SEND SERIES A NOTES WITH THIS NOTICE OF GUARANTEED DELIVERY.
ACTUAL SURRENDER OF SERIES A NOTES MUST BE MADE PURSUANT TO, AND BE
ACCOMPANIED BY, A PROPERLY COMPLETED AND FULLY EXECUTED LETTER OF
TRANSMITTAL AND ANY OTHER REQUIRED DOCUMENTS.
3
<PAGE>
Exhibit 99.3
CAITHNESS COSO FUNDING CORP.
OFFER TO EXCHANGE
6.80% Series B Senior Secured Notes Due 2001
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
6.80% Series A Senior Secured Notes Due 2001
and
9.05% Series B Senior Secured Notes Due 2009
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
9.05% Series A Senior Secured Notes Due 2009
______________, 1999
To: Registered Holders and
The Depository Trust Company Participants:
Enclosed are the materials listed below relating to the offer by
Caithness Coso Funding Corp., a Delaware corporation (the "Company"), to
exchange its 6.80% Series B Senior Secured Notes due 2001 for any and all
outstanding 6.80% Series A Senior Secured Notes due 2001 and its 9.05% Series B
Senior Secured Notes due 2009 for any and all outstanding 9.05% Series A Senior
Secured Notes due 2009, pursuant to an offering registered under the Securities
Act of 1933, as amended (the "Securities Act"), upon the terms and subject to
the conditions set forth in the Prospectus dated October 7, 1999 of the Company
and Coso Finance Partners, a California general partnership, Coso Energy
Developers, a California general partnership, and Coso Power Developers, a
California general partnership (collectively, the "Guarantors"), and the related
Letter of Transmittal enclosed herewith (which, together with any amendments or
supplements thereto, constitute the "Exchange Offer"). The 6.80% Series A Senior
Secured Notes due 2001 and the 9.05% Series A Senior Secured Notes due 2009 are
called the "Series A Notes," and the 6.80% Series B Senior Secured Notes due
2001 and the 9.05% Series B Senior Secured Notes due 2009 are called the "Series
B Notes."
Enclosed herewith are copies of the following documents:
1. Prospectus dated October 7, 1999;
2. The blue Letter of Transmittal to tender Series A Notes for
exchange;
3. The pink Notice of Guaranteed Delivery;
4. A white Instruction to Registered Holder and/or Book-Entry Transfer
Facility Participant from Owner;
<PAGE>
5. A yellow printed form of letter which may be sent to your clients
for whose account you hold Series A Notes in your name or in the name of your
nominee, to accompany the instruction form referred to above, for obtaining such
client's instruction with regard to the Exchange Offer; and
6. A return envelope addressed to the Exchange Agent.
WE URGE YOU TO CONTACT YOUR CLIENTS PROMPTLY. PLEASE NOTE THAT THE
EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON MONDAY, NOVEMBER
8, 1999, UNLESS EXTENDED.
The Exchange Offer is not conditioned upon any minimum number of Series
A Notes being tendered.
Pursuant to the Letter of Transmittal, each holder of Series A Notes
will represent to the Company and the Guarantors that (i) the holder is not an
"affiliate" of the Company, (ii) any Series B Notes to be received by it are
being acquired in the ordinary course of its business, and (iii) the holder is
not engaged in, and does not intend to engage in, a distribution of the Series B
Notes. If the tendering holder is a broker-dealer that will receive Series B
Notes for its own account in exchange for Series A Notes, you will represent on
behalf of such broker-dealer that the Series A Notes to be exchanged for the
Series B Notes were acquired by it as a result of market-making activities or
other trading activities, and acknowledge on behalf of such broker-dealer that
it will deliver a prospectus meeting the requirements of the Securities Act in
connection with any resale of such Series B Notes. By acknowledging that it will
deliver and by delivering a prospectus meeting the requirements of the
Securities Act in connection with any resale of such Series B Notes, such
broker-dealer is not deemed to admit that it is an "underwriter" within the
meaning of the Securities Act.
The enclosed Instruction to Registered Holder and/or Book-Entry Transfer
Facility Participant from Owner contains an authorization by the beneficial
owners of the Series A Notes for you to make the foregoing representations.
The Company will not pay any fee or commission to any broker or dealer
or to any other persons (other than the Exchange Agent) in connection with the
solicitation of tenders of Series A Notes pursuant to the Exchange Offer. The
Company will pay or cause to be paid any transfer taxes payable on the transfer
of Series A Notes to it, except as otherwise provided in Instruction 10 of the
enclosed Letter of Transmittal.
Any inquiries you may have with respect to the Exchnage Offer should be
addressed to U.S. Bank Trust National Association, the Exchange Agent, at its
address and telephone number set forth on the back cover page of the Prospectus.
Additional copies of the enclosed material may be obtained from the undersigned.
Very truly yours,
U.S. Bank Trust National Association
NOTHING CONTAINED HEREIN OR IN THE ENCLOSED DOCUMENTS SHALL CONSTITUTE
YOU OR ANY OTHER PERSON THE AGENT OF CAITHNESS COSO FUNDING CORP., COSO FINANCE
PARTNERS, COSO ENERGY DEVELOPERS, COSO POWER DEVELOPERS OR U.S. BANK TRUST
NATIONAL ASSOCIATION OR AUTHORIZE YOU TO USE ANY DOCUMENT OR MAKE ANY STATEMENT
ON THEIR BEHALF IN CONNECTION WITH THE EXCHANGE OFFER OTHER THAN THE DOCUMENTS
ENCLOSED HEREWITH AND THE STATEMENTS CONTAINED THEREIN.
2
<PAGE>
EXHIBIT 99.4
CAITHNESS COSO FUNDING CORP.
OFFER TO EXCHANGE
6.80% Series B Senior Secured Notes Due 2001
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
6.80% Series A Senior Secured Notes Due 2001
and
9.05% Series B Senior Secured Notes Due 2009
(Registered under the Securities Act of 1933)
for
Any and All of its Outstanding
9.05% Series A Senior Secured Notes Due 2009
- ----------------------------------------------------------------------
THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT
5:00 P.M., NEW YORK CITY TIME, ON MONDAY, NOVEMBER 8, 1999, UNLESS
THE OFFER IS EXTENDED.
- ----------------------------------------------------------------------
___________, 1999
To Our Clients:
Enclosed is a Prospectus, dated October 7, 1999, of Caithness Coso Funding
Corp., a Delaware corporation (the "Company"), Coso Finance Partners, a
California general partnership, Coso Energy Developers, a California general
partnership, and Coso Power Developers, a California general partnership, and a
related Letter of Transmittal (which together constitute the "Exchange Offer"),
relating to the offer by the Company to exchange its 6.80% Series B Senior
Secured Notes due 2001 for a like principal amount of its issued and outstanding
6.80% Series A Senior Secured Notes due 2001 and its 9.05% Series B Senior
Secured Notes due 2009 for a like principal amount of its issued and outstanding
9.05% Series A Senior Secured Notes due 2009, pursuant to an offering registered
under the Securities Act of 1933, as amended (the "Securities Act"), upon the
terms and subject to the conditions set forth in the Exchange Offer. The 6.80%
Series A Senior Secured Notes due 2001 and the 9.05% Series A Senior Secured
Notes due 2009 are called the "Series A Notes," and the 6.80% Series B Senior
Secured Notes due 2001 and the 9.05% Series B Senior Secured Notes due 2009 are
called the "Series B Notes."
The Exchange Offer is not conditioned upon any minimum number of Series A
Notes being tendered.
We are the holder of record and/or participant in the book-entry transfer
facility of Series A Notes held by us for your account. A tender of such Series
A Notes can be made only by us as the record holder and/or participant in the
book-entry transfer facility and pursuant to your instructions. The Letter of
Transmittal is furnished to you for your information only and cannot be used by
you to tender Series A Notes held by us for your account.
<PAGE>
We request instructions as to whether you wish to tender any or all of the
Series A Notes held by us for your account pursuant to the terms and conditions
of the Exchange Offer. We urge you to read carefully the Prospectus and the
Letter of Transmittal before instructing us to tender your Series A Notes. Your
instructions to us should be forwarded as promptly as possible in order to
permit us to tender your Series A Notes on your behalf in accordance with the
provisions of the Exchange Offer. The Exchange Offer will expire at 5:00 p.m.,
New York City time, on Monday, November 8, 1999, unless the Expiration Date is
extended as provided in the Prospectus. Tenders of Series A Notes may be
withdrawn at any time on or prior to the Expiration Date or as otherwise
provided in the Prospectus. We also request that you confirm that we may on
your behalf make the representations contained in the Letter of Transmittal.
Pursuant to the Letter of Transmittal, each holder of Series A Notes will
represent to the Company that (i) the holder is not an "affiliate" of the
Company, (ii) any Series B Notes to be received by the holder are being acquired
in the ordinary course of its business, and (iii) the holder is not engaged in,
does not intend to engage in, and has no arrangement or understanding with any
person to participate in, a distribution of the Series B Notes. If the
tendering holder is a broker-dealer that will receive Series B Notes for its own
account in exchange for Series A Notes, we will represent on behalf of such
broker-dealer that the Series A Notes to be exchanged for the Series B Notes
were acquired by it as a result of market-making activities or other trading
activities, and acknowledge on behalf of such broker-dealer that it will deliver
a prospectus meeting the requirements of the Securities Act in connection with
any resale of such Series B Notes. By acknowledging that it will deliver and by
delivering a prospectus meeting the requirements of the Securities Act in
connection with any resale of such Series B Notes, such broker-dealer is not
deemed to admit that it is an "underwriter" within the meaning of the Securities
Act.
If you wish to have us tender Series A Notes held by us for your account or
benefit pursuant to the Exchange Offer, please so instruct us by completing,
executing and returning to us the enclosed Instruction to Registered Holder
and/or Book-Entry Transfer Facility Participant from Owner. The accompanying
Letter of Transmittal is furnished to you for informational purposes only and
may not be used by you to tender Series A Notes held by us for your account or
benefit.
Very truly yours,
2
<PAGE>
EXHIBIT 99.5
INSTRUCTION TO REGISTERED HOLDER AND/OR
BOOK-ENTRY TRANSFER FACILITY PARTICIPANT
FROM OWNER OF
6.80% Series A Senior Secured Notes Due 2001
9.05% Series A Senior Secured Notes Due 2009
OF
CAITHNESS COSO FUNDING CORP.
_____________, 1999
To Registered Holder and/or Book-Entry Transfer Facility Participant:
The undersigned hereby acknowledges receipt of the Prospectus dated October
7, 1999 (the "Prospectus") of Caithness Coso Funding Corp., a Delaware
corporation (the "Company"), and Coso Finance Partners, a California general
partnership, Coso Energy Developers, a California general partnership, and Coso
Power Developers, a California general partnership, and the accompanying Letter
of Transmittal (the "Letter of Transmittal"), that together constitute the
Company's offer to exchange its 6.80% Series B Senior Secured Notes due 2001 for
a like principal amount of its issued and outstanding 6.80% Series A Senior
Secured Notes due 2001 and its 9.05% Series B Senior Secured Notes due 2009 for
a like principal amount of its issued and outstanding 9.05% Series A Senior
Secured Notes due 2009 (the "Exchange Offer"). The 6.80% Series A Senior Secured
Notes due 2001 and the 9.05% Series A Senior Secured Notes due 2009 are called
the "Series A Notes," and the 6.80% Series B Senior Secured Notes due 2001 and
the 9.05% Series B Senior Secured Notes due 2009 are called the "Series B
Notes." Capitalized terms used but not defined herein have the meanings assigned
to them in the Prospectus or the Letter of Transmittal.
This will instruct you, the registered holder and/or book-entry transfer
facility participant, as to the action to be taken by you relating to the
Exchange Offer with respect to the Series A Notes held by you for the account of
the undersigned.
The aggregate face amount of the Series A Notes held by you for the account
of the undersigned is (fill in amount):
$____________ of the 6.80% Series A Senior Secured Notes due 2001
$____________ of the 9.05% Series A Senior Secured Notes due 2009
<PAGE>
With respect to the Exchange Offer, the undersigned hereby instructs you
(check appropriate box):
[_] To TENDER the following Series A Notes held by you for the
account of the undersigned (insert principal amount of Series A Notes to be
tendered, if any):
$____________ of the 6.80% Series A Senior Secured Notes due 2001
$____________ of the 9.05% Series A Senior Secured Notes due 2009
[_] NOT to TENDER any Series A Notes held by you for the account
of the undersigned.
If the undersigned instructs you to tender the Series A Notes held by you
for the account of the undersigned, it is understood that you are authorized to
make, on behalf of the undersigned (and the undersigned, by its signature below,
hereby makes to you), the representations and warranties contained in the Letter
of Transmittal that are to be made with respect to the undersigned as a
beneficial owner, including but not limited to the representations, that (i) the
holder is not an "affiliate" of the Company, (ii) any Series B Notes to be
received by the holder are being acquired in the ordinary course of its
business, and (iii) the holder is not engaged in, and does not intend to engage
in, a distribution of the Series B Notes. If the undersigned is a broker-dealer
that will receive Series B Notes for its own account in exchange for Series A
Notes, it represents that such Series A Notes were acquired as a result of
market-making activities or other trading activities, and it acknowledges that
it will deliver a prospectus meeting the requirements of the Securities Act of
1933, as amended (the "Securities Act") in connection with any resale of such
Series B Notes. By acknowledging that it will deliver and by delivering a
prospectus meeting the requirements of the Securities Act in connection with any
resale of such Series B Notes, such broker-dealer is not deemed to admit that it
is an "underwriter" within the meaning of the Securities Act.
SIGN HERE
Name of beneficial owner(s):
------------------------------------
Signature(s):
---------------------------------------------------
Name(s) (please print):
-----------------------------------------
Address:
--------------------------------------------------------
Telephone Number:
-----------------------------------------------
Taxpayer Identification or Social Security Number:
--------------
Beneficial owner's account number:
------------------------------
Date:
-----------------------------------------------------------
2
