<PAGE>
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 12, 2000
REGISTRATION NO. 333-89521
------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
--------------
AMENDMENT NO. 3
TO
FORM S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
--------------
CE GENERATION, LLC
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C> <C>
DELAWARE 4911 47-0818523
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
--------------
302 SOUTH 36TH STREET, SUITE 400
OMAHA, NEBRASKA 68131
(402) 231-1641
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)
DOUGLAS L. ANDERSON
VICE PRESIDENT AND GENERAL COUNSEL
CE GENERATION, LLC
302 SOUTH 36TH STREET, SUITE 400
OMAHA, NEBRASKA 68131
(402) 231-1641
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
--------------
Copy to:
KELLEY M. GALE, ESQ.
LATHAM & WATKINS
701 B STREET, SUITE 2100
SAN DIEGO, CALIFORNIA 92101
(619) 236-1234
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon
as practicable after this Registration Statement becomes effective.
If any of 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. [ ]
--------------
CALCULATION OF REGISTRATION FEE
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PROPOSED PROPOSED AMOUNT OF
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AGGREGATE REGISTRATION
SECURITIES TO BE REGISTERED REGISTERED PER SECURITY(1) OFFERING PRICE(1) FEE(2)
<S> <C> <C> <C> <C>
7.416% Senior Secured Bonds Due December 15, 2018 $400,000,000 100% $400,000,000 $111,200
</TABLE>
- --------------------------------------------------------------------------------
(1) Estimated solely for purposes of calculating the registration fee
pursuant to Rule 457.
(2) Paid with the initial filing of the Registration Statement.
--------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
- --------------------------------------------------------------------------------
<PAGE>
SUBJECT TO COMPLETION, DATED JANUARY 12, 2000
PROSPECTUS
CE GENERATION, LLC
Exchange Offer for 7.416% Senior Secured Bonds Due December 15, 2018
----------------
This is an offer to exchange our outstanding, unregistered 7.416% Senior
Secured Bonds you now hold for new, substantially identical 7.416% Senior
Secured Bonds that will be free of the transfer restrictions that apply to the
old bonds. This offer will expire at 5:00 p.m., New York City time, on ,
2000, unless we extend it. You must tender the old, unregistered bonds by the
deadline to obtain new, registered bonds and the liquidity benefits they offer.
We agreed with the initial purchasers of the old bonds to make this offer
and register the issuance of the new bonds following the closing. This offer
applies to any and all old bonds tendered before the deadline.
The new bonds will not trade on any established exchange. The new bonds
have the same financial terms and covenants as the old bonds, and are subject
to the same business and financial risks.
A DESCRIPTION OF THOSE RISKS BEGINS ON PAGE 15.
The terms of the exchange offer will include the following:
o We will exchange all old securities that are validly tendered and not
withdrawn prior to the expiration of the exchange offer.
o You may withdraw tenders of old securities at any time prior to the
expiration of the exchange offer.
o 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 PASSED UPON THE
ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL
OFFENSE.
----------------
The date of this prospectus is January , 2000
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
<S> <C> <C> <C>
Prospectus Summary .......................... 1 Legal Matters ............................. 125
Risk Factors ................................ 15 Experts ................................... 125
The Exchange Offer .......................... 22 Power Generation Projects Independent
Engineer ................................. 125
Capitalization .............................. 32 Natural Gas Projects Independent
Selected Financial Data ..................... 33 Engineer ............................... 125
Management's Discussion and Geothermal Projects Independent
Analysis of Financial Condition Engineer ............................... 126
and Results of Operations .................. 35 Consultants' Reports ..................... 126
Our Business and the Business of the Where You Can Find More Information ...... 126
Our Management .............................. 53 Index to Financial Statements ............ F-1
Ownership of Our Membership Appendix A--Power Generation
Interests .................................. 55 Projects Independent Engineer's
Report .................................. A-1
Our Relationships and Related Appendix B--Natural Gas Projects
Transactions ............................... 55 Independent Engineer's Report ........... B-1
Reports of Third Party Consultants .......... 56 Appendix C--Geothermal Projects
Summary Description of Principal Independent Engineer's Report ........... C-1
Project Contracts .......................... 62 Appendix D--Power Market
Description of the Securities ............... 89 Consultant's Report .................... D-1
Summary Description of the Principal Appendix E--Geothermal Resource
Financing Documents ........................ 97 Consultant's Report..................... E-1
Plan of Distribution ........................ 122
United States Federal Income Tax
Considerations ............................. 123
</TABLE>
i
<PAGE>
PROSPECTUS SUMMARY
The following summary highlights selected information from this prospectus
and may not contain all of the information that is important to you. This
prospectus includes specific terms of the securities we are offering, as well
as information regarding our business and detailed financial data. We encourage
you to read the prospectus in its entirety. You should pay special attention to
the "Risk Factors" section beginning on page 15 of this prospectus.
SUMMARY OF OUR EXCHANGE OFFER
On March 2, 1999 we completed the offering of $400,000,000 aggregate
principal amount of our 7.416% Senior Secured Bonds due 2018 in reliance on
exemptions from the registration requirements of the Securities Act. As part of
that offering, we entered into a registration rights agreement with the initial
purchasers of those old securities in which we agreed, among other things, to
deliver this prospectus to you and to complete an exchange offer for the old
securities. Below is a summary of the exchange offer.
The Exchange Offer.......... We are offering to exchange up to $400,000,000
principal amount of new securities which have
been registered under the Securities Act for up
to $400,000,000 principal amount of old
securities. We will exchange old securities only
in integral multiples of $1,000.
In order to be exchanged, an old security must
be properly tendered and accepted. We will
exchange all old securities that are validly
tendered and not withdrawn. As of the date of
this prospectus, there are $400,000,000
principal amount of old securities outstanding.
We will issue new securities promptly after the
expiration of the exchange offer.
Resales Without Further
Registration................ Based on interpretations by the staff of the
Securities and Exchange Commission, we believe
that the new securities issued in the exchange
offer may be offered for resale, resold or
otherwise transferred by you without compliance
with the registration and prospectus delivery
requirements of the Securities Act, so long as:
o you are acquiring the new securities in the
ordinary course of your business;
o you are not participating, do not intend to
participate and have no arrangement or
understanding with any person to participate,
in a distribution of the new securities; and
o you are not an "affiliate" of ours.
By tendering your old securities as described
below, you will be making representations to
this effect.
Transfer Restrictions on
New Securities.............. If you are an affiliate of ours, are engaged
in, or intend to engage in or have any
arrangement or understanding with any person to
participate in, the distribution of the new
securities:
1
<PAGE>
(1) you cannot rely on the applicable
interpretations of the staff of the
Securities and Exchange Commission; and
(2) you must comply with the registration
requirements of the Securities Act in
connection with any resale transaction.
Each broker or dealer that receives new
securities for its own account in exchange for
old securities that were acquired as a result of
market-making or other trading activities must
acknowledge that it will deliver this prospectus
in connection with any offer to resell, resale
or other transfer of the new securities issued
in the exchange offer.
Expiration Date............. 5:00 p.m., New York City time, on 2000,
unless we extend the expiration date.
Accrued Interest on the New
Securities and
Old Securities.............. The new securities will bear interest from the
most recent date to which interest has been paid
on the old securities. If your old securities are
accepted for exchange, then you will waive
interest on the old securities accrued to the
date the new securities are issued.
Increase in Interest Rate... As the registration statement of which this
prospectus is a part was not declared effective
by November 27, 1999, the interest rate on the
old securities was increased by 0.50% per annum
beginning November 27, 1999 until the
registration statement is declared effective.
Conditions to our Acceptance and
Exchange of Old Securities... Our obligations to accept old securities and
exchange old securities for new securities are
subject to the following conditions, which we may
assert or waive in our sole discretion:
o the exchange offer cannot violate applicable
law;
o there cannot exist any law or governmental
proceeding which (1) seeks to restrain or
prohibit the exchange offer, (2) seeks
damages as a result of the exchange offer or
(3) results in a material delay in our
ability to exchange old securities;
o there cannot have occurred (1) a suspension
of trading in securities on the New York
Stock Exchange, (2) a declaration of a
banking moratorium or (3) a commencement of a
war involving the United States; and
o there cannot have occurred a material
adverse change in our business, financial or
other condition, operations, stock ownership
or prospects.
2
<PAGE>
Procedures for Tendering Old
Securities.................. If you wish to tender your old securities, you
must complete, sign and date the letter of
transmittal, or a facsimile of it, in accordance
with its instructions and transmit the letter of
transmittal, together with your old securities
and any other required documentation, and Chase
Manhattan Bank and Trust Company, National
Association, who is the exchange agent, must
receive the documentation at the address set
forth in the letter of transmittal by 5:00 p.m.
New York City time, on the expiration date. By
executing the letter of transmittal, you will
represent to us that you are acquiring the new
securities in the ordinary course of your
business, that you are not participating, do not
intend to participate and have no arrangement or
understanding with any person to participate, in
the distribution of new securities, and that you
are not an "affiliate" of ours.
Special Procedures for Beneficial
Holders..................... If you are the beneficial holder of old
securities that are registered in the name of
your broker, dealer, commercial bank, trust
company or other nominee, and you wish to tender
in the exchange offer, you should promptly
contact the person in whose name your old
securities are registered and instruct them to
tender on your behalf.
Guaranteed Delivery
Procedures.................. If you wish to tender your old securities and you
cannot deliver your notes, the letter of
transmittal or any other required documents to
the exchange agent before the expiration date,
you may tender your old securities according to
the guaranteed delivery procedures.
Withdrawal Rights........... Tenders may be withdrawn at any time before 5:
00 p.m., New York City time, on the expiration
date.
Acceptance of Old Securities and
Delivery of New Securities... Subject to the conditions described above, we
will accept for exchange any and all old
securities which are properly tendered in the
exchange offer before 5:00 p.m., New York City
time, on the expiration date. The new securities
will be delivered promptly after the expiration
date.
Exchange Agent.............. Chase Manhattan Bank and Trust Company,
National Association, is serving as exchange
agent in connection with the exchange offer.
Federal Income Tax
Considerations.............. We believe that your exchange of old securities
for new securities in the exchange offer will not
result in any gain or loss to you for United
States federal income tax purposes.
Use of Proceeds............. We will not receive any proceeds from the
issuance of new securities in the exchange offer.
We will pay all expenses incident to the exchange
offer.
3
<PAGE>
SUMMARY OF THE TERMS OF THE SECURITIES
The form and terms of the new securities and the old securities are
identical in all material respects, except that transfer restrictions and
registration rights applicable to the old securities do not apply to the new
securities. The new securities will evidence the same debt as the old
securities and will be governed by the same indenture.
Securities Offered.......... $400,000,000 7.416% Senior Secured Bonds Due
December 15, 2018.
Interest Payment Dates...... June 15 and December 15.
Scheduled Principal
Payments.................... Principal of the securities will be payable in
semiannual installments on each June 15 and
December 15, beginning June 15, 2000, as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
- ----------------------------- ---------------
<S> <C>
June 15, 1999 ............. 0.000%
December 15, 1999 ......... 0.000%
June 15, 2000 ............. 1.300%
December 15, 2000 ......... 1.300%
June 15, 2001 ............. 1.575%
December 15, 2001 ......... 1.575%
June 15, 2002 ............. 2.575%
December 15, 2002 ......... 2.575%
June 15, 2003 ............. 2.250%
December 15, 2003 ......... 2.250%
June 15, 2004 ............. 1.825%
December 15, 2004 ......... 1.825%
June 15, 2005 ............. 1.850%
December 15, 2005 ......... 1.850%
June 15, 2006 ............. 2.400%
December 15, 2006 ......... 2.400%
June 15, 2007 ............. 2.250%
December 15, 2007 ......... 2.250%
June 15, 2008 ............. 3.525%
December 15, 2008 ......... 3.525%
June 15, 2009 ............. 3.075%
December 15, 2009 ......... 3.075%
June 15, 2010 ............. 1.775%
December 15, 2010 ......... 1.775%
June 15, 2011 ............. 1.900%
December 15, 2011 ......... 1.900%
June 15, 2012 ............. 2.560%
December 15, 2012 ......... 2.560%
June 15, 2013 ............. 2.550%
December 15, 2013 ......... 2.550%
June 15, 2014 ............. 3.225%
December 15, 2014 ......... 3.225%
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL
PAYMENT DATE AMOUNT PAYABLE
- ----------------------------- ---------------
<S> <C>
June 15, 2015 ............. 3.380%
December 15, 2015 ......... 3.380%
June 15, 2016 ............. 3.660%
December 15, 2016 ......... 3.660%
June 15, 2017 ............. 3.780%
December 15, 2017 ......... 3.780%
June 15, 2018 ............. 4.545%
December 15, 2018 ......... 4.545%
</TABLE>
Average Number of Years that
the Securities will
be Outstanding.............. The average number of years during which
securities will be outstanding is approximately
11.9 years.
Denominations............... We issued the old securities in minimum
denominations of $100,000 or any integral
multiple of $1,000 in excess of $100,000. We will
issue the new securities in minimum denominations
of $1,000.
Ratings..................... "Baa3" by Moody's Investor Services, Inc.,
"BBB-" by Standard & Poor's Ratings Group and
"BBB" by Duff & Phelps Credit Rating Co.
Optional Redemption......... We may redeem all or any portion of the
securities at a redemption price equal to:
o 100% of the principal amount of the
securities being redeemed, plus
o accrued and unpaid interest on the
securities being redeemed, plus
o a yield maintenance premium which is based
on the rates of comparable treasury
securities plus 50 basis points.
Mandatory Redemption With
Yield Maintenance Premium... We will be obligated to redeem the securities
at par plus accrued interest to the date of
redemption, plus a yield maintenance premium, in
the following circumstances:
o if one of our subsidiaries that has assigned
its available cash flow to secure our
obligation to make payments on the securities
receives more than $15,000,000 of available
cash flow in net proceeds from one or more
financings of its project or refinancings of
the project financing debt of its project
company, we will be required to use all of
these proceeds to redeem securities;
o if an assigning subsidiary receives more
than $15,000,000 of available cash flow in
net proceeds from a sale of assets by its
project company and the sale is not in the
ordinary course of business, we will be
required to use all of these proceeds to
redeem securities;
5
<PAGE>
o if we receive more than $15,000,000 in
proceeds from the sale of all or any portion
of our interest in any assigning subsidiary
and the sale was not specifically permitted
under the indenture for the securities, we
will be required to use all of these proceeds
to redeem securities; and
o if an assigning subsidiary receives more
than $15,000,000 in proceeds from the sale of
all or any portion of its interest in any
project company and the sale was not
specifically permitted under the indenture
for the securities, we will be required to
use all of these proceeds to redeem
securities.
In each of the above cases, we will be obligated
to redeem only the amount of securities to the
extent which will cause each rating agency to
confirm that, after giving effect to the
redemption, the rating assigned to the
securities by the rating agency will be at least
as good as the higher of (a) the then-current
rating assigned to the securities by the rating
agency or (b) the initial rating assigned to the
securities by the rating agency as of the
closing date for the old securities.
Mandatory Redemption Without
Yield Maintenance Premium... We will be obligated to redeem the securities
at par plus accrued interest to the date of
redemption in the following circumstances:
o if an assigning subsidiary receives more
than $15,000,000 of available cash flow in
net proceeds related to the damage or
destruction of all or a portion of the
assigning subsidiary's project, we will be
required to use all of these proceeds to
redeem securities;
o if an assigning subsidiary receives more
than $15,000,000 of available cash flow in
net proceeds related to a governmental
authority's compulsory taking or transfer, or
the threat of a governmental authority's
compulsory taking or transfer, of the
assigning subsidiary's project, we will be
required to use all of these proceeds to
redeem securities;
o if an assigning subsidiary receives more
than $15,000,000 of available cash flow in
net proceeds related to a defect in the title
to the land on which the assigning
subsidiary's project is located, we will be
required to use all of these proceeds to
redeem securities; and
o if an assigning subsidiary receives more
than $15,000,000 of available cash flow in
net proceeds related to the termination of an
assigning subsidiary's power purchase
agreement or the amendment of an assigning
subsidiary's power purchase agreement which
reduces the amount of capacity and energy
sold under the agreement, we will be required
to use all of these proceeds to redeem
securities.
6
<PAGE>
However, in the case of a termination or an
amendment of a power purchase agreement, we will
be obligated to redeem only the amount of
securities to the extent which will cause each
rating agency to confirm that, after giving
effect to the redemption, the rating assigned to
the securities by the rating agency will be at
least as good as the higher of (a) the
then-current rating assigned to the securities
by the rating agency or (b) the initial rating
assigned to the securities by the rating agency
as of the closing date for the old securities.
Ranking of the Securities... The securities:
o are senior secured debt owed by us;
o rank equally in right of payment with our
other senior secured debt permitted under the
indenture for the securities; the amount of
other senior secured debt that we can incur
is unlimited if we satisfy the additional
debt tests under the indenture;
o share equally in the collateral with our
other senior secured debt permitted under the
indenture;
o rank senior to any of our subordinated debt
permitted under the indenture;
o are effectively subordinated to the existing
project financing debt and all other debt of
the assigning subsidiaries, SECI Holdings,
California Energy Yuma, the project companies
and the holding companies associated with the
projects; as of September 30, 1999, the
aggregate amount of this debt was $677.7
million; and
o are the only debt, other than the debt
permitted under the indenture, which we owe.
Collateral.................. The securities are secured by the following
collateral:
o all available cash flow of the assigning
subsidiaries deposited with the depositary
bank;
o a pledge of 99% of the equity interests in
Salton Sea Power Company and all of the
equity interests in CE Texas Gas LLC, the
assigning subsidiaries, other than Magma
Power Company, and California Energy Yuma
Corporation;
o upon the redemption of, or earlier release
of security interests under, Magma's 9 7/8%
promissory notes, a pledge of all of the
capital stock of Magma;
o a pledge of all of the capital stock of SECI
Holdings Inc.;
o a grant of a lien on and security interest
in the depositary accounts; and
o a grant of a lien on and security interest
in all of our other tangible and intangible
property, to the extent it is possible to
grant a lien on the property.
7
<PAGE>
Non-Recourse Obligations.... We are the only person obligated to pay
principal of, premium, if any, and interest on
the Securities. Our members, MidAmerican Energy
Holdings Company and El Paso Power Holding
Company, will not guarantee the securities or
have any obligation to make payments on the
securities. None of our or our members' officers,
directors, employees or affiliates will guarantee
the securities or have any obligation to make
payments on the securities.
Debt Service
Reserve Account............. We are required to maintain an amount on deposit
in the debt service reserve account equal on any
date to the maximum semiannual principal and
interest payment due on the securities for the
remaining term. We are permitted to satisfy this
obligation by depositing cash into the debt
service reserve account or by delivering to the
depositary bank a letter of credit provided by a
commercial bank or other financial institution
whose long-term unsecured debt obligations are
rated at least "A" by S&P and "A2" by Moody's. We
initially funded the debt service reserve account
by providing the depositary bank with a debt
service reserve letter of credit in an amount of
approximately $24 million.
Covenants................... We have agreed in the indenture for the
securities to, among other things:
o maintain our existence;
o comply with applicable laws and governmental
approvals;
o perform our obligations under the financing
documents;
o maintain the liens on the collateral in
favor of the collateral agent;
o provide the trustee, the collateral agent
and depositary bank with reasonable
inspection rights;
o pay our taxes and maintain our books and
records; and
o pledge all of Magma's capital stock within
ten days after the stock is released from the
liens securing Magma's 9 7/8% promissory
notes.
We have agreed not to, among other things:
o incur debt other than as permitted under the
indenture;
o create liens on our property other than as
permitted under the indenture;
o engage in any activities other than those
permitted by the financing documents; or
o form subsidiaries, make investments, loans
or advances or acquire the stock, obligations
or securities of any other person, other than
as permitted under the indenture.
These affirmative and negative covenants are
subject to a number of important qualifications
and exceptions set forth in the indenture.
8
<PAGE>
SUMMARY OF OUR BUSINESS
We are a special purpose Delaware limited liability company formed for the
sole purpose of issuing securities and holding the equity interests in our
subsidiaries. The following subsidiaries have assigned their available cash
flows to secure our obligation to make payments on the securities:
o Magma Power Company
o Salton Sea Power Company
o Falcon Seaboard Resources, Inc.
o Falcon Seaboard Power Corporation
o Falcon Seaboard Oil Company
o California Energy Development Corporation
o CE Texas Energy LLC
These assigning subsidiaries own equity interests in project companies
which own ten geothermal and three natural gas-fired electric generating
facilities located in California, New York, Texas and Arizona. We own 100% of
the interests in twelve of these projects. In addition, we manage, control and
have substantial equity interests in the remaining project. Substantially all
of the cash flow received by us is received indirectly from these projects.
Below is a simplified chart which illustrates both our current ownership
structure as well as the current ownership structure of each project.
9
<PAGE>
[GRAPHIC OMITTED]
- ----------
(1) The percentage of distributions from the Saranac project indirectly
beneficially owned by us varies over time.
Our subsidiaries operate all of the projects and sell substantially all of
the power produced by the projects to utility purchasers under long-term
contracts. The principal purchasers are Southern California Edison Company, New
York State Electric and Gas Corporation and Texas Utilities Energy Company,
whom we depend on for substantially all of our revenues. The operation of
geothermal projects involves drilling and maintaining geothermal wells which
produce steam that generates electricity when run through a geothermal power
plant. Gas-fired power plants burn natural gas to produce steam and generate
electricity. Following are tables describing the projects. The availability and
capacity factor figures shown in the tables are averages for 1996, 1997 and
1998.
10
<PAGE>
<TABLE>
<CAPTION>
SALTON SEA SALTON SEA SALTON SEA
PROJECT UNIT I UNIT II UNIT III
- ---------------------- --------------------- --------------------- ---------------------
<S> <C> <C> <C>
Project Company(ies) Salton Sea Salton Sea Salton Sea
Power Power Power
Generation L.P. Generation L.P. Generation L.P.
Location Imperial Imperial Imperial
Valley, CA Valley, CA Valley, CA
Capacity(1) 10 megawatts 20 megawatts 49.8 megawatts
Fuel Type Geothermal Geothermal Geothermal
Ownership Interest 100% 100% 100%
Commercial
Operation July 1987 April 1990 February 1989
Availability 96.0% 96.7% 96.0%
Capacity Factor 81.9% 119.1% 99.9%
Power Purchaser Southern Southern Southern
California California California
Edison Edison Edison
Company Company Company
Power Contract
Expiration June 2017 April 2020 February 2019
Thermal Energy Host N/A N/A N/A
Fuel Supplier N/A N/A N/A
Operator CalEnergy CalEnergy CalEnergy
Operating Operating Operating
Corporation Corporation Corporation
Outstanding Debt (2) (2) (2)
Debt Service
Coverage Ratio
Test(3) 1.4x prior to 1.4x prior to 1.4x prior to
2000/1.5 x 2000/1.5 x 2000/1.5 x
thereafter thereafter thereafter
Debt Service
Coverage Ratio(4) 1.77 1.77 1.77
<CAPTION>
SALTON SEA SALTON SEA
PROJECT UNIT IV UNIT V LEATHERS DEL RANCH
- ---------------------- --------------------- ------------------- -------------------- ---------------------
<S> <C> <C> <C> <C>
Project Company(ies) Salton Sea Salton Sea Leathers, L.P. Del Ranch, L.P.
Power Power L.L.C.
Generation L.P.
and Fish Lake
Power LLC
Location Imperial Imperial Imperial Imperial
Valley, CA Valley, CA Valley, CA Valley, CA
Capacity(1) 39.6 megawatts 49 megawatts 38 megawatts 38 megawatts
Fuel Type Geothermal Geothermal Geothermal Geothermal
Ownership Interest 100% 100% 100% 100%
Commercial
Operation May 1996 Mid-2000 January 1990 January 1989
Availability 94.5% N/A 97.2% 97.4%
Capacity Factor 114.8% N/A 115.9% 118.2%
Power Purchaser Southern Zinc facility/ Southern Southern
California California California California
Edison power exchange Edison Edison
Company Company Company
Power Contract
Expiration May 2026 N/A December 2019 December 2018
Thermal Energy Host N/A N/A N/A N/A
Fuel Supplier N/A N/A N/A N/A
Operator CalEnergy CalEnergy CalEnergy CalEnergy
Operating Operating Operating Operating
Corporation Corporation Corporation Corporation
Outstanding Debt (2) (2) (2) (2)
Debt Service
Coverage Ratio
Test(3) 1.4x prior to 1.4x prior to 1.4x prior to 1.4x prior to
2000/1.5 x 2000/1.5 x 2000/1.5 x 2000/1.5 x
thereafter thereafter thereafter thereafter
Debt Service
Coverage Ratio(4) 1.77 1.77 1.77 1.77
</TABLE>
- --------
(1) Capacity figures for Salton Sea Units I-IV and the Leathers, Del Ranch,
Elmore and Vulcan projects represent the capacity levels utilized to
calculate capacity payments under the current power purchase agreements
for these projects. Capacity figures for Salton Sea Unit V and the CE
Turbo project represent the expected capacity of each project to deliver
electricity for sale to others upon completion of construction of these
projects. Capacity figures for the Saranac, Power Resources and Yuma
projects represent the maximum quantities permitted to be sold by those
projects under their current power purchase agreements. The actual
capacity of a project at any time varies with ambient temperatures and,
in the case of the geothermal projects, reservoir and wellfield
conditions.
(2) The total debt outstanding at September 30, 1999 for Salton Sea Units I-V
and the Leathers, Del Ranch, Elmore, Vulcan and CE Turbo projects, and a
zinc facility which was financed with these projects and is owned by our
affiliates, is $597.9 million, of which $140.5 million is scheduled to be
repaid by our affiliates that own the zinc facility.
(3) Represents historical and projected debt service coverage level required
to make equity distributions under the applicable project financing
documents.
(4) Calculated as of September 30, 1999 in accordance with the applicable
project financing documents.
11
<PAGE>
<TABLE>
<CAPTION>
PROJECT ELMORE VULCAN
- ---------------------- ------------------ -------------------
<S> <C> <C>
Project Company(ies) Elmore, L.P. Vulcan/BN
Geothermal
Power
Company
Location Imperial Imperial
Valley, CA Valley, CA
Capacity(1) 38 megawatts 34 megawatts
Fuel Type Geothermal Geothermal
Ownership Interest 100% 100%
Commercial
Operation January 1989 February 1986
Availability 96.9% 95.4%
Capacity Factor 114.6% 113.5%
Power Purchaser Southern Southern
California California
Edison Edison
Company Company
Power Contract
Expiration December 2018 February 2016
Thermal Energy Host N/A N/A
Fuel Supplier N/A N/A
Operator CalEnergy CalEnergy
Operating Operating
Corporation Corporation
Outstanding Debt (2) (2)
Debt Service
Coverage Ratio
Test(3) 1.4x prior to 1.4x prior to
2000/1.5 x 2000/1.5 x
thereafter thereafter
Debt Service
Coverage Ratio(5) 1.77 1.77
<CAPTION>
PROJECT CE TURBO SARANAC POWER RESOURCES YUMA
- ---------------------- ------------------- ------------------ ------------------- ----------------
<S> <C> <C> <C> <C>
Project Company(ies) CE Turbo LLC Saranac Power Power Yuma
Partners, L.P. Resources, Inc. Cogeneration
Associates
Location Imperial Plattsburgh, Big Spring, TX Yuma, AZ
Valley, CA NY
Capacity(1) 10 megawatts 240 megawatts 200 megawatts 50 megawatts
Fuel Type Geothermal Natural Gas Natural Gas Natural Gas
Ownership Interest 100% Varies 100% 100%
Commercial
Operation Mid-2000 June 1994 June 1988 May 1994
Availability N/A 95.2% 91.2% 96.4%
Capacity Factor N/A 92.5% 79.7% 88.3%
Power Purchaser California New York State Texas Utilities San Diego Gas
power exchange Electric and Energy & Electric
Gas Company
Corporation
Power Contract
Expiration N/A June 2009 September 2003 May 2024
Thermal Energy Host N/A Georgia-Pacific Fina Oil and Queen Carpet,
Corporation/ Chemical Inc.
Tenneco Company
Packaging, Inc.
Fuel Supplier N/A Coral Energy Fina/Louis Southwest Gas
Canada (Shell) Dreyfus Corporation
Operator CalEnergy Falcon Power Falcon Power Falcon Power
Operating Operating Operating Operating
Company Company Company
Outstanding Debt (2) $183.1 million $79.8 million None
Debt Service
Coverage Ratio
Test(3) 1.4x prior to 1.2 x Varies(4) N/A
2000/1.5 x
thereafter
Debt Service
Coverage Ratio(5) 1.77 3.52 1.33 N/A
</TABLE>
- --------
(1) Capacity figures for Salton Sea Units I-IV and the Leathers, Del Ranch,
Elmore and Vulcan projects represent the capacity levels utilized to
calculate capacity payments under the current power purchase agreements
for these projects. Capacity figures for Salton Sea Unit V and the CE
Turbo project represent the expected capacity of each project to deliver
electricity for sale to others upon completion of construction of these
projects. Capacity figures for the Saranac, Power Resources and Yuma
projects represent the maximum quantities permitted to be sold by those
projects under their current power purchase agreements. The actual
capacity of a project at any time varies with ambient temperatures and,
in the case of the geothermal projects, reservoir and wellfield
conditions.
(2) The total debt outstanding at September 30, 1999 for Salton Sea Units I-V
and the Leathers, Del Ranch, Elmore, Vulcan and CE Turbo projects, and a
zinc facility which was financed with these projects and is owned by our
affiliates, is $597.9 million, of which $140.5 million is scheduled to be
paid by our affiliates that own the zinc facility.
(3) Represents historical and projected debt service coverage levels required
to make equity distributions under the applicable project financing
documents.
(4) To distribute 100% of available cash flow, the debt service coverage
ratio must be at least 1.2x. If the debt service coverage ratio is 1.17x
to 1.19x, 50% of available cash flow may be distributed. If the debt
service coverage ratio is 1.15x to 1.17x, 40% of available cash flow may
be distributed. If the debt service coverage ratio is 1.13x to 1.15x, 30%
of available cash flow may be distributed. If the debt service coverage
ratio is 1.1x to 1.13x, 20% of available cash flow may be distributed. If
the debt service coverage ratio is less than 1.1x, 10% of available cash
flow may be distributed.
(5) Calculated as of September 30, 1999 in accordance with the applicable
project financing documents.
12
<PAGE>
On December 2, 1999, our indirect subsidiary, NorCon Power Partners, L.P.,
closed a series of transactions as described below in which it, among other
things, transferred the NorCon project to General Electric Capital Corporation,
the NorCon project lender. Prior to this date, NorCon had owned the NorCon
project, which is an 80 megawatt natural gas fired power project located in
North East, Pennsylvania.
In connection with the transfer, NorCon reached a settlement of its
outstanding litigation with Niagara Mohawk Power Corporation, the power
purchaser from the NorCon project. This litigation arose out of a provision in
NorCon's power purchase agreement which provided for a notional tracking
account to track the cumulative difference between the contract price and
prices based on short run costs of electricity. The power purchase agreement
provided that if the tracking account balance reflected an excess of the
contract price over the short run costs, the balance would be used to reduce
the contract price during the period of 2007 through 2017 and that NorCon would
be required to pay the remaining balance to Niagara Mohawk in 2017 at the
expiration of the power purchase agreement. Niagara Mohawk claimed in this
litigation that NorCon should be required to provide adequate assurances in the
form of a letter of credit or other form of security to ensure that NorCon
would be able to pay any amount owing by NorCon to Niagara Mohawk as a result
of the tracking account. Under the settlement, this litigation was dismissed,
Niagara Mohawk paid the amount of $125 million and this power purchase
agreement was terminated effective as of November 1, 1999.
The entire amount paid by Niagara Mohawk as described above was paid to
General Electric Capital as the project lender and Louis Dreyfus Natural Gas
Corporation, the natural gas supplier for the NorCon project. NorCon also
transferred to General Electric Capital the NorCon project and other equipment
used by the NorCon project. NorCon's funds in its bank accounts were used to
pay other outstanding NorCon obligations and otherwise were paid to an
affiliate of General Electric Capital. Additionally, NorCon assigned its
contracts, including its gas transportation agreements with National Fuel Gas
Supply Corporation and its loan agreements with General Electric Capital, to an
affiliate of General Electric Capital which assumed the obligations under these
agreements. In return, NorCon obtained a release of its obligations and
liabilities from General Electric Capital under the NorCon project financing
agreements and from Louis Dreyfus under the NorCon project natural gas sales
agreement. General Electric Capital also agreed to be responsible for other
third party claims made against NorCon related to the NorCon project. The
operation and maintenance agreement between NorCon and Falcon Power Operating
Company was also terminated. NorCon and Welch Foods, Inc., the steam purchaser
from the NorCon project, agreed to terminate their steam supply agreement
concurrently with the other transactions described above. No payment was made
by General Electric Capital to NorCon in connection with the transfer of the
project or the other related transactions.
Thus, after December 2, 1999, neither NorCon nor any of our other
subsidiaries owns an interest in the NorCon project and the primary contracts
of the NorCon project are no longer in effect or have been transferred to
General Electric Capital or its affiliates. NorCon has agreed with General
Electric Capital to cooperate with its operation of the NorCon project during a
transition period ending at the end of 1999. Otherwise, we believe that none of
our subsidiaries will have any further rights, profits or losses with respect
to the NorCon project. Because none of the amount paid by Niagara Mohawk was
available for distribution by NorCon to its owners, no portion of this amount
will be used to redeem the securities.
We will make payments on the new securities with the following available
cash flow received by our subsidiaries that have assigned their cash flows to
secure our obligation to make payments on the securities:
o with respect to any assigning subsidiary, distributions received by the
assigning subsidiary from the project company(ies) that own its
project(s), so long as these equity distributions are no longer subject
to any liens imposed by any applicable project financing document and are
delivered to the depositary bank; and
13
<PAGE>
o with respect to Magma, fees, royalties and other payments received by
Magma to the extent not otherwise required to be used for Magma project
costs or otherwise under any project financing document or project
document.
The structure of the transaction described in this prospectus has been
designed to pool and cross-collateralize the available cash flow of the
assigning subsidiaries from the projects. A chart depicting the transaction
structure is shown below.
[GRAPHIC OMITTED]
There are a number of risks to the repayment of the new securities which are
described below starting on page 15 of this prospectus.
14
<PAGE>
RISK FACTORS
You should carefully consider the following factors before deciding to
tender your old securities in the exchange offer.
YOUR FAILURE TO EXCHANGE YOUR OLD SECURITIES FOR NEW SECURITIES COULD RESULT IN
YOUR HOLDING ILLIQUID SECURITIES WHICH CANNOT BE RESOLD UNLESS YOU REGISTER
THEM UNDER THE SECURITIES ACT OR FIND AN EXEMPTION FROM REGISTRATION.
The old securities 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 by use
of an exemption from the registration requirements of the Securities Act and
applicable state securities laws. If you do not exchange your unregistered old
securities for registered new securities in the exchange offer, you will not be
able to resell, offer to resell or otherwise transfer the old securities unless
they are registered under the Securities Act or unless you resell them, offer
to resell them 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 will no longer be under an obligation to
register the old securities under the Securities Act except in the limited
circumstances provided under the registration rights agreement between us and
the initial purchasers of the old securities. In addition, to the extent that
old securities are tendered for exchange and accepted in the exchange offer,
the trading market for the untendered and tendered but unaccepted old
securities could be illiquid.
YOU WILL NOT HAVE ANY RECOURSE TO THE ASSETS OF THE PROJECT COMPANIES OR THE
ASSETS OF MIDAMERICAN OR EL PASO POWER.
You will have recourse only to us and the collateral described in this
prospectus. None of our shareholders or affiliates, including MidAmerican, El
Paso Power and the project companies, or any of our shareholders' or
affiliates' officers, directors or employees will guarantee our obligation to
make payments on the securities or be liable in any other way for the payment
of the securities. The assigning subsidiaries have only assigned their
available cash flow to secure our obligation to make payments on the
securities, and have not issued guarantees of our payment obligations. If we
are unable to make payments on the securities and you foreclose on the
collateral which secures the securities, the proceeds that you receive from the
sale may not be sufficient to fully repay your securities.
OUR ABILITY TO MAKE PAYMENTS ON THE SECURITIES IS DEPENDENT ON THE ASSIGNING
SUBSIDIARIES' RECEIPT OF EQUITY DISTRIBUTIONS FROM THE PROJECT COMPANIES, WHICH
IS IN TURN DEPENDENT ON EVENTS WHICH ARE BEYOND OUR CONTROL.
We were formed for the purpose of issuing the securities and owning our
subsidiaries. We do not have any operations. Accordingly, the sole source of
repayment of the securities is the available cash flow of our subsidiaries that
have assigned their available cash flows to secure our obligation to make
payments on the securities. The assigning subsidiaries' sources of available
cash flow are limited. Salton Sea Power, Falcon Seaboard Resources, Falcon
Seaboard Power, Falcon Seaboard Oil, California Energy Development and CE Texas
Energy conduct no business other than owning direct and indirect interests in
their project companies. Magma conducts no material business other than owning
its equity interests in the Imperial Valley project companies and providing
administrative and operation services and real estate rights to the Imperial
Valley project companies. Falcon Power Operating conducts no business other
than providing operation and maintenance services for the Saranac, Power
Resources and Yuma projects. CE Texas Gas conducts no business other than
procuring natural gas for the Power Resources Project. In addition, the project
financing documents entered into by the project companies in connection with
the development and construction of their projects place limitations on the
ability of the project companies to make distributions to the assigning
subsidiaries. For example, if there is a default under a project financing
document, the project company would not be permitted to make distributions to
the relevant assigning subsidiary. A default could result from the making of an
untrue representation by the project company or the failure of the project
company to satisfy a covenant. Finally, if a assigning subsidiary were to be
found to be bankrupt, the assignment of the assigning subsidiary's cash flow to
the secured parties would not be considered a lien that would continue if
effect following the bankruptcy.
15
<PAGE>
THE PROJECT LENDERS MUST MAKE PAYMENTS ON DEBT INCURRED BY THEM BEFORE MAKING
EQUITY DISTRIBUTIONS TO THE ASSIGNING SUBSIDIARIES.
The project companies other than Yuma paid for a portion of the costs of
constructing their projects with loans from banks and proceeds from the sale of
bonds. As of September 30, 1999, the aggregate amount of this debt was
approximately $959.2 million. The project companies must make regular payments
on this debt prior to making distributions to the assigning subsidiaries. Any
additional debt incurred by the project companies would also in all likelihood
have to be paid before distributions could occur. Accordingly, the existence of
debt at the project company level reduces the amount of distributions that can
be made to the assigning subsidiaries and, in turn, the amount of funds
available to make payments on the securities. In addition, if there was a
default under the documents evidencing the project company level debt, the
lenders of the debt could foreclose on the collateral securing the debt, which
could include the project company's project. If this were to occur, we would
lose an important source of funds to use to make payments on the securities.
WE CANNOT PREDICT THE REVENUES FROM THE SALE OF ELECTRICITY UNDER THE POWER
PURCHASE AGREEMENTS OR IN THE COMPETITIVE POWER MARKETS AND THE AMOUNT OF THESE
REVENUES MAY BE LOWER THAN AS SHOWN IN THE INDEPENDENT ENGINEER'S PROJECTIONS.
Other than the Salton Sea Unit I power purchase agreements, the energy
payments under the power purchase agreements for the operating Imperial Valley
projects depend, or will in the future depend, at least in part, on the cost
that Southern California Edison avoids by purchasing energy from the Imperial
Valley projects instead of obtaining the energy from other sources. The energy
payments under the Yuma power purchase agreement are dependent on the cost that
San Diego Gas & Electric avoids by purchasing energy from the Yuma project
instead of obtaining the energy from other sources. Estimates of Southern
California Edison's and San Diego Gas & Electric's avoided costs vary
substantially and we cannot predict the level of payments to be made in the
future under these power purchase agreements. These future payments may be
lower than as contemplated by the projections. Accordingly, there may be less
funds available for repayment of the securities than as shown in the
projections.
Although approximately one-third of the net electrical output of Salton
Sea Unit V is expected to be sold under a contract for use by the zinc
facility, neither Salton Sea Unit V nor the CE Turbo project currently has any
material long-term power sales agreement for the rest of their capacity. The
strategy for Salton Sea Unit V and the CE Turbo project is to sell output not
needed by the zinc facility in short term transactions through the California
power exchange or in other transactions from time to time as may be found to be
more advantageous than those conducted through the California power exchange.
The California power exchange was recently created to establish markets for the
sale of power on a daily and an hourly basis. Thus, California power exchange
prices are expected to have the characteristics of short term spot prices and
to fluctuate from time to time in a manner that cannot be predicted with
accuracy and is not within our control or the control of any other person. The
projections use California power exchange prices. These estimates may turn out
to be wrong and the California power exchange prices may actually be lower than
as shown in the projections. If this is the case, there will be less funds
available to make payments on the securities than is shown in the projections.
SOME OF THE POWER PURCHASE AGREEMENTS FOR THE PROJECTS WILL EXPIRE BEFORE THE
MATURITY DATE FOR THE SECURITIES AND THE PRICES AT WHICH THE POWER FROM THE
AFFECTED PROJECTS CAN BE SOLD AFTER EXPIRATION MAY BE LOWER THAN THE PRICES
UNDER THE POWER PURCHASE AGREEMENTS.
The initial terms of the power purchase agreements for Salton Sea Unit I
and the Power Resources, Saranac and Vulcan projects end in 2017, 2003, 2009
and 2016, respectively, and we cannot assure you that the terms of these power
purchase agreements will be extended beyond the initial terms. The revenues of
the Power Resources and Vulcan projects and Salton Sea Unit I represented 28%,
5% and 2% of total sales of electricity and steam, respectively, for the nine
months ended September 30, 1999. Saranac is accounted for as an equity
investment and our share of its earnings
16
<PAGE>
comprise 95% of the equity earnings in subsidiaries for the nine months ended
September 30, 1999. Upon termination or expiration of a power purchase
agreements, the affected project company may make "spot" sales to the
competitive market, enter into one or more replacement power purchase
agreements or sell power through a combination of these approaches. In any of
these cases, we cannot assure you that net revenues generated from market sales
or replacement power purchase agreements will not be lower than the revenues
contemplated by the projections. If the revenues are lower, there will be less
funds available to make payments on the securities than as shown in the
projections.
THE PROCEEDS RECEIVED UNDER THE PROJECT COMPANIES' INSURANCE POLICIES MAY NOT
BE SUFFICIENT TO COVER ALL LOSSES AND THE INSURANCE COVERAGE FOR THE PROJECTS
MAY NOT BE AVAILABLE IN THE FUTURE ON COMMERCIALLY REASONABLE TERMS.
The operation of the projects involves many risks, including the breakdown
or failure of power generating equipment, pipelines, transmission lines or
other equipment or processes, fuel interruption, performance below expected
levels of output or efficiency, operator error and catastrophic events
including fires, earthquakes or explosions. The occurrence of any of these
events could significantly reduce or eliminate revenues generated by a project
or significantly increase the expenses of a project, thereby reducing the funds
available to make distributions to the assigning subsidiaries and,
consequently, reducing the funds available to make payments on the securities.
The projects companies currently possess property, business interruption,
catastrophic and general liability insurance. However, this comprehensive
insurance coverage may not be available in the future at commercially
reasonable costs or terms and the amounts for which the project companies are
or will be insured may not cover all potential losses.
THE PROJECT COMPANIES RELY ON A LIMITED NUMBER OF CUSTOMERS AND SUPPLIERS.
Each project depends on a single or limited number of companies to
purchase electricity or thermal energy, to supply water, to supply gas, to
transport gas, to dispose of wastes or to deliver electricity. For example,
each of the eight operating Imperial Valley projects relies on a power purchase
agreement with Southern California Edison for all of its revenues. The failure
of any power purchaser, thermal energy purchaser, water or gas supplier, gas
transporter, transmitting utility or other project participant to fulfill its
contractual obligations could increase the expenditures of or decrease the
revenues earned by the affected project company. This would, in turn, decrease
the amounts available for distribution to the assigning subsidiaries and, as a
result, decrease the funds available to make payments on the securities.
THE CONSTRUCTION OF THE NEW PROJECTS MAY BE DELAYED AND MAY COST MORE THAN WE
EXPECTED.
Although eleven of the projects have been operating for a number of years,
Salton Sea Unit V and the CE Turbo project are under construction according to
the terms of engineering, procurement and construction contracts. These new
projects are subject to risks associated with the construction of power plants
including risks of delays in completion, cost overruns and failures of the
construction contractors to perform in accordance with contract terms. Any
material unremedied delay in or unsatisfactory completion of the new projects
could hurt the affected project companies' results of operations. This would,
in turn, decrease the amounts available for distribution to the assigning
subsidiaries and, as a result decrease the funds available to make payments on
the securities.
THE AVAILABLE GEOTHERMAL RESOURCES MAY NOT BE SUFFICIENT TO OPERATE THE
GEOTHERMAL PROJECTS FOR THE ENTIRE TERM OF THE SECURITIES AND THE USE OF
GEOTHERMAL FUEL IN THESE PROJECTS MAY RESULT IN SIGNIFICANT COSTS WHICH ARE NOT
WITHIN OUR CONTROL.
Salton Sea Units I-V and the Leathers, Del Ranch, Elmore, Vulcan and CE
Turbo projects are geothermal power projects. The revenues of these geothermal
projects represented 66% of our total sales of electricity and steam for the
nine months ended September 30, 1999. 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,
17
<PAGE>
including dry holes and uncontrolled releases. Because of the geological
complexities of geothermal reservoirs, the geographic area and sustainable
output of the reservoirs can only be estimated and cannot be definitively
established. There is, accordingly, a risk of an unexpected decline in the
capacity of geothermal wells and a risk of geothermal reservoirs not being
sufficient for sustained production of electricity by the Imperial Valley
projects at the expected levels.
In addition, both the cost of operations and the operating performance of
the Imperial Valley projects may be hurt by a variety of operating factors.
Production and injection wells can require frequent maintenance or replacement.
Corrosion caused by high-temperature and high-salinity geothermal fluids may
require the replacement or repair of equipment, vessels or pipelines. New
production and injection wells may be required for the maintenance of current
operating levels, thereby requiring substantial capital expenditures.
THE PROJECT COMPANIES' BUSINESSES ARE SUBJECT TO A LARGE NUMBER OF REGULATIONS
AND PERMITTING REQUIREMENTS AND MAY BE HURT BY CHANGES IN THESE REGULATIONS AND
REQUIREMENTS.
The project companies are subject to a number of environmental laws and
regulations affecting many aspects of their present and future operations.
These laws and regulations generally require the project companies to obtain
and comply with a wide variety of licenses, permits and other approvals. The
project companies are also subject to environmental and energy regulations that
both public officials and private individuals may seek to enforce. We cannot
assure you that existing regulations will not be revised or that new
regulations will not be adopted or become applicable to the project companies
which could have an adverse impact on their operations.
The structure of federal and state energy regulations is currently
undergoing change and has in the past, and may in the future, be the subject of
various challenges, initiatives and restructuring proposals by utilities and
other electric industry participants. The implementation of regulatory changes
in response to these challenges, initiatives and restructuring proposals could
result in the imposition of more comprehensive or stringent requirements on the
project companies, electric utilities and other electric industry participants,
which would result in increased compliance costs and could otherwise have an
adverse effect on:
o the results of the project companies' operations;
o the project companies' ability to make distributions to the
assigning subsidiaries; or
o the operations and financial condition of electric utilities
(including the utilities which have entered into power
purchase agreements with the project companies) and other
industry participants.
THERE IS A PENDING LAWSUIT RELATED TO THE SARANAC PROJECT, WHICH MAY HURT THE
REVENUES OF SARANAC IF ADVERSELY DETERMINED.
New York State Electric and Gas has filed a complaint in federal court
challenging the implementation of the Public Utility Regulatory Policies Act of
1978 by the Federal Energy Regulatory Commission and the New York State Public
Service Commission and claiming that the prices in the Saranac power purchase
agreement exceed the prices mandated by the Public Utility Regulatory Policies
Act. The Public Service Commission also filed a related cross-claim against
FERC making similar assertions. We believe that New York State Electric and
Gas's and the Public Service Commission's claims are without merit because,
among other things, these claims were unanimously denied by FERC in earlier
proceedings which found that (1) New York State Electric and Gas's challenge to
the regulatory scheme was grossly untimely, (2) the Saranac power purchase
agreement was exempt from further regulatory review and (3) the rates payable
under the Saranac power purchase agreement were consistent with the Public
Utility Regulatory Policies Act and FERC regulations. If, however, New York
State Electric and Gas were successful in reducing the rates payable under the
Saranac power purchase agreement or in obtaining any restitution, this rate
reduction or restitution payment could reduce the revenues of Saranac. This
reduction would result in decreased distributions made to Falcon Seaboard
Resources, which would mean less funds available to make payments on the bonds.
18
<PAGE>
IT IS POSSIBLE THAT THE ASSIGNING SUBSIDIARIES' ASSIGNMENT OF THEIR AVAILABLE
CASH FLOW COULD BE SUBORDINATED OR DECLARED UNENFORCEABLE IN A BANKRUPTCY OR
SIMILAR PROCEEDING.
We distributed a substantial portion of the proceeds from the sale of the
old securities to MidAmerican. The portion of the proceeds from the sale which
we contributed to each assigning subsidiary was less than the amount of
available cash flow assigned by each assigning subsidiary to secure our
obligations with respect to the securities. It is possible that a creditor of a
assigning subsidiary could make a claim, under federal or state fraudulent
conveyance laws, that the security holders' claims under the assigning
subsidiary security agreement should be subordinated or not enforced or that
payments thereunder (including payments to the security holders) should be
recovered.
In order to prevail on this type of claim, a claimant would have to
demonstrate that:
o either:
o the obligations incurred under the assigning subsidiary security
agreement were not incurred in good faith; or
o that any assigning subsidiary did not receive fair consideration for
its assignment of available cash flow; and
o that any assigning subsidiary:
o was insolvent at the time it entered into the assigning subsidiary
security agreement; or
o at any time did not have and will not have sufficient capital for
carrying on its business or was not and will not be able to pay its
debts as they mature.
WE HAVE RELIED ON PROJECTIONS OF THE FUTURE PERFORMANCE OF THE PROJECTS IN
ASSESSING OUR ABILITY TO MAKE PAYMENTS ON THE SECURITIES. THESE PROJECTIONS,
WHICH WERE NOT VERIFIED BY OUR ACCOUNTANTS, ARE BASED ON ASSUMPTIONS WHICH MAY
PROVE TO BE INCORRECT.
In order to assess our ability to make payments on the securities, we
engaged independent engineers to prepare reports containing, among other
things, projections of the distributions to us from the projects. R.W. Beck,
Inc. prepared a report which contains projections of distributions from the
natural gas projects and Fluor Daniel, Inc. prepared a report which contains
projections of distributions from the Imperial Valley geothermal projects.
Fluor Daniel also prepared a report which contains projections of the
consolidated distributions from all of the projects. A summary of these
independent engineers' reports and other third-party reports appears later in
this prospectus. The reports in their entirety are attached as appendices to
this prospectus. All projections of future operations and the economic results
of the projections included in the independent engineers' reports have been
prepared or confirmed by Fluor Daniel and R.W. Beck. Deloitte & Touche LLP, our
independent auditors, have neither examined nor compiled the projections and,
accordingly, do not express an opinion or any other form of assurance with
respect to the projections. The reports were prepared prior to our offering of
the old securities and have not been updated since that time.
For purposes of preparing the projections, assumptions were made, of
necessity, with respect to general business and economic conditions, the
revenues the project companies will earn in their respective businesses, the
amount of available cash flow the assigning subsidiaries will receive and
several other matters that are not within the control of the assigning
subsidiaries and the outcome of which cannot be predicted by us, the assigning
subsidiaries, Fluor Daniel, R.W. Beck or any other person with any certainty or
accuracy. These assumptions include the following:
o Fluor Daniel did not undertake an independent review with all
regulatory agencies which could have jurisdiction over, or interests
pertaining to, the geothermal projects;
o R.W. Beck assumed that all licenses, permits and approvals necessary to
operate the natural gas projects have been obtained or will be obtained
in a timely manner.
19
<PAGE>
o R.W. Beck assumed that the project contracts for the natural gas
projects will be fully enforceable in accordance with their terms;
o R.W. Beck assumed that the operators of the natural gas projects will
operate those projects in a sound and businesslike manner in accordance
with good engineering practice;
o R.W. Beck assumed that proposed restructuring of the electric utility
industry will not significantly impact the projected electricity revenues
of the natural gas projects.
We believe that these assumptions were reasonable for purposes of
preparing the projections. These assumptions are, however, inherently subject
to significant uncertainties and actual results may differ, perhaps materially,
from those assumed. Following is a discussion of how assumptions which later
prove to be incorrect may cause the results of operations of the project
companies to be less favorable than as shown in the projections.
As described above in this discussion of the risks associated with an
investment in the securities, the project companies are subject to a number of
environmental and energy regulations and must obtain and comply with
environmental and energy permits and licenses. Fluor Daniel did not undertake
an independent review with all regulatory agencies that might have jurisdiction
over the geothermal projects and R.W. Beck assumed that all of these permits
and licenses have been obtained or will be obtained in a timely fashion. If the
projects are subject to new or additional regulations or if the project
companies fail to obtain or maintain any required permits or licenses, the
actual results of operations of the project companies may be less favorable
than as contemplated in the projections.
We also describe above a lawsuit filed by New York State Electric and Gas
which challenges the implementation of the Public Utilities Regulatory Policies
Act and claims that the price under the Saranac power purchase agreement should
be reduced. R.W. Beck assumed that the project contracts will be fully
enforceable in accordance with their terms. If New York State Electric and Gas
prevails in its lawsuit, the revenues earned by Saranac may decrease and the
results of operations of Saranac may be less favorable than as contemplated in
the projections.
One of the other risks described above is that damage to the projects
could decrease the revenues earned by the affected projects, and that insurance
proceeds may not be sufficient to fully cover the losses. R.W. Beck assumes
that the operators of the natural gas projects will operate the projects in a
sound and businesslike manner in accordance with good engineering practice. If
the operators fail to do so and their failure results in damage to the
projects, the revenues earned by the projects could decrease. Further, the
damage may not be fully covered by insurance proceeds. Thus, the results of
operations of the affected projects may be lower than as contemplated in the
projections.
We also discuss in this risk factors section, and in other places in this
prospectus, the possibility that the projects may be affected by restructuring
of the electric utility industry. R.W. Beck assumed that proposed restructuring
of the electric utility industry will not significantly impact the projected
electricity revenues of the natural gas projects. However, future regulations
implemented in connection with a restructuring of the industry could increase
the operating costs incurred by the projects or reduce market prices for
electricity by increasing competition. Accordingly, if a restructuring of the
electric utility industry were to have these effects on the projects, the
results of operations of these projects could be less favorable than as
contemplated in the projections.
If, as described above, the actual results of operations of the project
companies are less favorable than those shown in the projections because the
assumptions used in formulating the projections prove to be incorrect, the
available cash flow of the assigning subsidiaries would be decreased. This
decrease would have an adverse effect on our ability to make payments on the
securities.
WE WILL NOT RECEIVE ANY DISTRIBUTIONS FROM THE NORCON PROJECT.
At the time of the issuance of the initial securities in March 1999, our
indirect subsidiary owned an interest in the NorCon project, an 80 megawatt
natural gas fired power project located in North East, Pennsylvania, which sold
electricity to Niagara Mohawk and steam to Welch Foods. However, as described
above, on December 2, 1999, NorCon closed a series of transactions in which it
transferred
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its interest in the NorCon project, terminated the Niagara Mohawk power
purchase agreement and the Welch Foods agreement and disposed of its other
rights and interests related to the NorCon project. Accordingly, we do not
expect to receive any distributions from the NorCon project in the future and
none of these amounts will be available to make payments of principal of and
interest on the securities. We believe that these transactions will not
materially affect our ability to make payments on the securities because
distributions from the NorCon project have not been and were not expected to be
material even absent these transactions. Our share of its earnings comprise
less than 5% of the equity earnings in subsidiaries for the nine months ended
September 30, 1999. Similarly, the projections reflect zero distributions from
the NorCon project.
THERE IS NO EXISTING MARKET FOR THE NEW SECURITIES AND WE CANNOT ASSURE YOU
THAT AN ACTIVE TRADING MARKET WILL DEVELOP.
We are offering the new securities to the holders of the old securities.
There is no existing market for the new securities and we cannot assure you
that a market will develop. If a market for the new securities were to develop,
future trading prices would depend on many factors, including prevailing
interest rates, the operating results of the project companies and the market
for similar securities. We do not intend to apply for listing or quotation of
the new securities on any securities exchange or stock market. As a result, it
may be difficult for you to find a buyer for your securities at the time you
want to sell them, and even if you found a buyer, you might not get the price
you want.
THIS PROSPECTUS CONTAINS FORWARD-LOOKING STATEMENTS THAT ARE DEPENDENT ON
CIRCUMSTANCES AND EVENTS WHICH MAY BE OUTSIDE OF OUR CONTROL.
Some of the statements contained in this prospectus are forward-looking
statements that are dependent on circumstances and events that may be outside
of our control. We identify these statements by using words like "expect,"
"believe," "anticipate," "estimate" and "projected" and similar expressions.
The forward-looking statements in this prospectus involve known and unknown
risks, uncertainties and other important factors that could cause our actual
results, performance or achievements, or the results, performance or
achievements of our affiliates, or industry results, to differ materially from
any future results, performance or achievements expressed or implied by the
forward-looking statements.
These risks, uncertainties and other important factors include:
o general economic and business conditions in the United States;
o governmental, statutory, regulatory or administrative initiatives
affecting us, the assigning subsidiaries, the project companies, the
projects or the U.S. electricity industry;
o weather effects on sales and revenues;
o general industry trends; competition;
o fuel and power costs and availability;
o changes in business strategy, development plans or vendor
relationships;
o fuel transportation; availability, term and deployment of capital;
o availability of qualified personnel; and
o changes in, or the failure or inability to comply with, governmental
regulation, including industry deregulation and restructuring,
environmental and tax regulations and legislation.
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THE EXCHANGE OFFER
BACKGROUND INFORMATION REGARDING THE EXCHANGE OFFER
We originally sold the outstanding 7.416% Senior Secured Bonds Due
December 15, 2018 on March 2, 1999 in a transaction exempt from the
registration requirements of the Securities Act. Credit Suisse First Boston
Corporation and Goldman, Sachs & Co., as the initial purchasers, subsequently
resold the notes to qualified institutional buyers in reliance on Rule 144A and
under Regulation S under the Securities Act. As of the date of this prospectus,
$400 million aggregate principal amount of unregistered bonds are outstanding.
We entered into an exchange and registration rights agreement with Credit
Suisse First Boston Corporation and Goldman, Sachs & Co. under which we agreed
that we would, at our own cost, do the following:
o use our reasonable best efforts to cause the registration statement,
of which this prospectus is a part, relating to the exchange offer to
be declared effective by the Securities and Exchange Commission by
November 27, 1999;
o keep the exchange offer open for a period of not less than the shorter
of:
(1) the period ending when the last of the remaining old securities is
tendered into the exchange offer, and
(2) 30 days from the date notice is mailed to holders of the old
securities; and
o maintain the registration statement continuously effective for a
period of not less than the longer of:
(1) the period ending upon consummation of the exchange offer, and
(2) 120 days after effectiveness of the registration statement,
subject to extension.
However, in the event that all resales of new securities covered by the
registration statement have been made, the registration statement need
not remain continuously effective.
YOUR ABILITY TO RESELL THE NEW SECURITIES
Based on no-action letters issued by the staff of the Securities and
Exchange Commission to third parties, we believe that a holder of old
securities who exchanges old securities for new securities in the exchange
offer generally may offer the new securities for resale, sell the new
securities and otherwise transfer the new securities without further
registration under the Securities Act and without delivery of a prospectus that
satisfies the requirements of Section 10 of the Securities Act. This does not
apply, however, to a holder who is an affiliate of ours within the meaning of
Rule 405 of the Securities Act. We also believe that a holder may offer, sell
or transfer the new securities only if the holder acquires the new securities
in the ordinary course of its business and is not participating, does not
intend to participate and has no arrangement or understanding with any person
to participate in a distribution of the new securities.
Any holder of old securities using the exchange offer to participate in a
distribution of new securities cannot rely on the no-action letters referred to
above. This category of holders includes a broker-dealer that acquired old
securities directly from us, but not as a result of market-making activities or
other trading activities. Consequently, this type of holder must comply with
the registration and prospectus delivery requirements of the Securities Act in
the absence of an exemption from these requirements.
Each broker-dealer that receives new securities for its own account in
exchange for old securities, where the old securities were acquired by the
broker-dealer as a result of market-making activities or other trading
activities, may be a statutory underwriter and must acknowledge that it will
deliver a prospectus meeting the requirements of the Securities Act in
connection with the resale of new
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securities received in exchange for old securities. The letter of transmittal
(which accompanies this prospectus) states that by so acknowledging and by
delivering a prospectus, a participating broker-dealer will not be deemed to
admit that it is an underwriter within the meaning of the Securities Act. A
participating broker-dealer may use this prospectus, as it may be amended from
time to time, in connection with resales of new securities it receives in
exchange for old securities in the exchange offer. We will make this prospectus
available to any participating broker-dealer in connection with any resale of
this kind for a period of 30 days after the expiration date of the exchange
offer.
REPRESENTATIONS AND ACKNOWLEDGEMENTS THAT YOU MUST MAKE IN ORDER TO EXCHANGE
YOUR OLD SECURITIES FOR NEW SECURITIES
Each holder of the old securities who wishes to exchange old securities
for new securities in the exchange offer will be required to represent and
acknowledge, for the holder and for each beneficial owner of the old
securities, whether or not the beneficial owner is the holder, in the letter of
transmittal that:
o the new securities to be acquired by the holder and each beneficial
owner, if any, are being acquired in the ordinary course of business,
o neither the holder nor any beneficial owner is an affiliate, as
defined in Rule 405 of the Securities Act, of ours or any of our
subsidiaries,
o any person participating in the exchange offer with the intention or
purpose of distributing new securities received in exchange for old
securities, including a broker-dealer that acquired old securities
directly from us, but not as a result of market-making activities or
other trading activities, cannot rely on the no-action letters
referenced above and must comply with the registration and prospectus
delivery requirements of the Securities Act in connection with a
secondary resale of the new securities,
o if the holder is not a broker-dealer, the holder and each beneficial
owner, if any, are not participating, do not intend to participate and
have no arrangement or understanding with any person to participate in
any distribution of the new securities received in exchange for old
securities, and
o if the holder is a broker-dealer that will receive new securities for
the holder's own account in exchange for old securities, the old
securities to be so exchanged were acquired by the holder as a result
of market-making or other trading activities and the holder will
deliver a prospectus meeting the requirements of the Securities Act in
connection with any resale of the new securities received in the
exchange offer. However, by so representing and acknowledging and by
delivering a prospectus, the holder will not be deemed to admit that
it is an underwriter within the meaning of the Securities Act.
SITUATIONS IN WHICH WE WILL BE REQUIRED TO FILE A SHELF REGISTRATION STATEMENT
If applicable law or interpretations of the staff of the Securities and
Exchange Commission are changed so that the new securities received by holders
who make all of the above representations in the letter of transmittal are not
or would not be, upon receipt, transferable by each holder without restriction
under the Securities Act, we will, at our cost:
o file a shelf registration statement covering resales of the old
securities,
o use our reasonable best efforts to cause the shelf registration
statement to be declared effective under the Securities Act on or
prior to November 27, 1999, and
o use our reasonable best efforts to keep effective the shelf
registration statement until the earlier of three years after March 2,
1998, subject to exceptions, or the time when all of the applicable
old securities are no longer outstanding.
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We may postpone or suspend the filing or the effectiveness of any shelf
registration statement if the postponement or suspension is taken by us in good
faith and for valid business reasons. We will, if and when we file the shelf
registration statement, provide to each holder of the old securities copies of
the prospectus which is a part of the shelf registration statement, notify each
holder when the shelf registration statement has become effective and take
other actions as are required to permit unrestricted resales of the old
securities.
THE INTEREST RATE ON THE OLD SECURITIES IS INCREASED FROM AND AFTER NOVEMBER
27, 1999 BECAUSE A REGISTRATION STATEMENT WAS NOT DECLARED EFFECTIVE BY
NOVEMBER 27, 1999
As neither the exchange offer registration statement nor a shelf
registration statement was declared effective by November 27, 1999, the
interest rate on the old securities was increased by 0.50% per annum from and
after November 27, 1999 until the exchange offer registration statement or the
shelf registration statement is declared effective. Upon consummation of the
exchange offer, holders of old securities will not be entitled to any increase
in the rate of interest on the old securities, but the old securities will
still be governed by the indenture under which the old securities were issued.
GENERAL TERMS OF THE EXCHANGE OFFER
We hereby offer, upon the terms and subject to the conditions set forth in
this prospectus and in the accompanying letter of transmittal, to exchange new
securities for a like aggregate principal amount of old securities properly
tendered on or prior to the expiration date and not properly withdrawn in
accordance with the procedures described below. We will issue, promptly after
the expiration date, the new securities in exchange for a like principal amount
of outstanding old securities tendered and accepted in connection with the
exchange offer. You may tender your old securities in whole or in part in a
principal amount of $1,000 and integral multiples thereof, provided that if any
old securities are tendered for exchange in part, the untendered principal
amount of the old securities must be $100,000 or any integral multiple of
$1,000 in excess of $100,000.
The exchange offer is not conditioned upon any minimum number of old
securities being tendered. As of the date of this prospectus, $400,000,000
aggregate principal amount of the old securities is outstanding.
If any tendered old securities are not accepted for exchange because of an
invalid tender or any other reason, certificates for any unaccepted old
securities will be returned, without expense to the tendering holder promptly
after the expiration 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 the exchange of old securities. We will pay all charges and expenses, other
than applicable taxes described below, in connection with the exchange offer.
Neither we nor our board of directors makes any recommendation to you as
to whether to tender or refrain from tendering all or any portion of your old
securities in the exchange offer. In addition, no one has been authorized to
make this type of recommendation. You must make your own decision whether to
tender in the exchange offer and, if you do tender, the aggregate amount of old
securities to tender. In making these decisions, you should read this
prospectus and the letter of transmittal and consult with your advisers. You
should make the decision whether to tender based on your own financial position
and requirements.
THE EXPIRATION DATE FOR THE EXCHANGE OFFER AND OUR ABILITY TO EXTEND THE
EXPIRATION DATE
The exchange offer expires on the expiration date. The term "expiration
date" means 5:00 p.m., New York City time, on , 2000, unless we in our
sole discretion extend the period during which the exchange offer is open. If
we do so, the term "expiration date" will mean the latest time and date to
which the exchange offer is extended. We may extend the exchange offer at any
time and from time to time by giving oral or written notice to the exchange
agent and by timely public
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announcement. Without limiting the manner in which we may choose to make any
public announcement and subject to applicable law, we will have no obligation
to publish, advertise or otherwise communicate any public announcement other
than by issuing a release to an appropriate news agency. During any extension
of the exchange offer, all old securities previously tendered in the exchange
offer will remain subject to the exchange offer.
WE CAN WAIVE CONDITIONS TO THE EXCHANGE OFFER AND AMEND THE EXCHANGE OFFER IN
OTHER WAYS
We reserve the right (1) to delay accepting any old securities, to extend
the exchange offer or to terminate the exchange offer and not accept old
securities not previously accepted for any reason, including if any of the
conditions to the exchange offer described below are not satisfied and are not
waived by us, or (2) to amend the terms of the exchange offer in any manner,
whether prior to or after the tender of any of the old securities. If any
delay, extension, termination or amendment occurs, we will give oral or written
notice to the exchange agent and will either cause a public announcement or
give notice to the holders of the securities as promptly as practicable. If the
delay, extension, termination or amendment is material, we will be required to
file a post-effective amendment to the registration statement of which this
prospectus is a part.
If (1) we waive any material condition to the exchange offer or amend the
exchange offer in any other material respect and (2) the exchange offer is
scheduled to expire at any time earlier than the expiration of a period ending
on the fifth business day after the date that notice of the waiver or amendment
is first published, sent or given, then the exchange offer will be extended
until the expiration of the five business day period.
THE PROCEDURES YOU MUST FOLLOW IN ORDER TO TENDER YOUR OLD SECURITIES
THE ITEMS YOU MUST SUBMIT IN ORDER TO TENDER YOUR OLD SECURITIES
To tender in the exchange offer, you must (1) complete, sign and date the
letter of transmittal, or a facsimile of the letter, (2) have the signatures
thereon guaranteed if required by the letter of transmittal and (3) mail or
otherwise deliver the letter of transmittal, together with any other required
documents or an agent's message in case of book-entry delivery as described
below, to the exchange agent prior to the expiration date. In addition, either
o certificates for the old securities being tendered must be received by
the exchange agent along with the letter of transmittal on or prior to
the expiration date,
o a timely confirmation of a book-entry transfer of the old securities,
if this procedure is available, into the exchange agent's account at
The Depository Trust Company by the procedure for book-entry transfer
described below, along with the letter of transmittal, must be
received by the exchange agent on or prior to the expiration date, or
o you must comply with the guaranteed delivery procedures described
below.
THE METHOD OF DELIVERY OF CERTIFICATES, THE LETTER OF TRANSMITTAL AND ALL
OTHER REQUIRED DOCUMENTS IS AT YOUR OPTION AND SOLE RISK. IF YOU DELIVER BY
MAIL, WE RECOMMEND REGISTERED MAIL (RETURN RECEIPT REQUESTED AND PROPERLY
INSURED) OR AN OVERNIGHT DELIVERY SERVICE. IN ALL CASES, YOU SHOULD ALLOW
SUFFICIENT TIME TO ENSURE TIMELY DELIVERY. NO LETTERS OF TRANSMITTAL OR OLD
SECURITIES SHOULD BE SENT TO US.
SPECIAL CIRCUMSTANCES THAT MAY APPLY TO YOUR TENDER
To be tendered effectively, the old securities, letter of transmittal and
all other required documents, or, in the case of a participant in The
Depository Trust Company, an agent's message must be received by the exchange
agent prior to 5:00 p.m., New York City time, on the expiration date. Except in
the case of a participant in The Depository Trust Company who transfers
securities by an agent's message, delivery of all documents must be made to the
exchange agent at its address set forth on the back of this prospectus. You may
also request your respective broker, dealer, commercial bank, trust company or
nominee to effect your tender for you.
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Your tender of old securities will constitute an agreement between you and
us in accordance with the terms and subject to the conditions set forth in the
prospectus and in the letter of transmittal. If you tender less than all of
your old securities, you should fill in the amount of old securities being
tendered in the appropriate box on the letter of transmittal. The entire amount
of old securities delivered to the exchange agent will be deemed to have been
tendered unless you indicate otherwise.
Only a holder of old securities may tender the old securities in the
exchange offer. The term "holder" with respect to the exchange offer means any
person in whose name old securities are registered on our books or any other
person who has obtained a properly completed bond power from the registered
holder.
Any beneficial owner whose old securities are registered in the name of a
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender should contact the registered holder promptly and instruct the
registered holder to tender on his behalf. If the beneficial owner wishes to
tender on his own behalf, the beneficial owner must, prior to completing and
executing the letter of transmittal and delivering his old securities, either
make appropriate arrangements to register ownership of the old securities in
the beneficial owner's name or obtain a properly completed bond power from the
registered holder. The transfer of registered ownership may take considerable
time.
Signatures on a letter of transmittal or a notice of withdrawal, as the
case may be, must be guaranteed by a firm (an "eligible institution") that is a
member of a recognized signature guarantee medallion program within the meaning
of Rule 17Ad-15 under the Exchange Act, unless the old securities tendered with
the letter are tendered (1) by a registered holder who has not completed the
box entitled "Special Issuance Instructions" or "Special Delivery Instructions"
on the letter of transmittal or (2) for the account of an eligible institution.
In the event that 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 the
registered holder of any old securities listed in the letter, the old
securities must be endorsed or accompanied by bond powers and a proxy which
authorizes that person to tender the old securities on behalf of the registered
holder, in each case as the name of the registered holder appears on the old
securities. If the letter of transmittal or any old securities 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, the signer should so indicate when signing, and unless
waived by us, evidence satisfactory to us of their authority to so act must be
submitted with the letter of transmittal.
OUR RIGHTS IN CONNECTION WITH THE TENDERING PROCEDURES
All questions as to the validity, form, eligibility (including time of
receipt) and withdrawal of the tendered old securities will be determined by us
in our sole discretion, which determination will be final and binding. We
reserve the absolute right to reject any and all old securities not properly
tendered or any old securities which, if accepted by us, would be unlawful. We
also reserve the right to waive any irregularities or conditions of tender as
to particular old securities. Our interpretation of the terms and conditions of
the exchange offer (including the instructions in the letter of transmittal)
will be final and binding on all parties. Unless waived, any defects or
irregularities in connection with tenders of old securities must be cured
within a time period determined by us. Neither we, the exchange agent or any
other person will be under any duty to give notification of defects or
irregularities with respect to tenders of old securities, nor will we or any of
them incur any liability for failure to give notification. Tenders of old
securities will not be deemed to have been made until any irregularities have
been cured or waived. Any old securities received by the exchange agent that
are not properly tendered, and which have defects or irregularities which have
not been timely cured or waived, will be returned without cost to the holder by
the exchange agent as soon as practicable following the expiration date.
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In addition, we reserve the right in our sole discretion (1) to purchase
or make offers for any old securities that remain outstanding subsequent to the
expiration date or to terminate the exchange offer, and (2) to the extent
permitted by applicable law, to purchase old securities in the open market, in
privately negotiated transactions or otherwise. We have no present plan to
acquire any old securities which are not tendered in the exchange offer. The
terms of any purchases or offers could differ from the terms of the exchange
offer.
YOU MAY BE ABLE TO USE THE DEPOSITORY TRUST COMPANY IN CONNECTION WITH YOUR
TENDER
The exchange agent will make a request to establish an account with
respect to the old securities at The Depository Trust Company for purposes of
the exchange offer within two business days after the date of this prospectus.
Any financial institution that is a participant in The Depository Trust Company
may book-entry deliver old securities by causing The Depository Trust Company
to transfer the old securities into the exchange agent's account at The
Depository Trust Company in accordance with The Depository Trust Company's
procedures for transfer on or prior to the expiration date. If you are a
participant in The Depository Trust Company and transfer your old securities by
an agent's message, you do not need to transmit the letter of transmittal to
the exchange agent to consummate your exchange.
The term "agent's message" means a message transmitted through electronic
means by The Depository Trust Company to and received by the exchange agent and
forming a part of a book-entry confirmation, which states that The Depository
Trust Company has received an express acknowledgment from the participant in
The Depository Trust Company tendering the securities that the participant has
received and agrees to be bound by the letter of transmittal and/or the notice
of guaranteed delivery discussed below, where applicable.
YOUR ABILITY TO TENDER BY PROVIDING A NOTICE OF GUARANTEED DELIVERY
If you would like to tender your old securities, and (1) your old
securities are not immediately available, (2) time will not permit your old
securities or other required documents to reach the exchange agent before the
expiration date, or (3) the procedure for book-entry transfer cannot be
completed on a timely basis, your tender may still be effected if:
o the tender is made through an eligible institution;
o on or prior to the expiration date, the exchange agent received from
the eligible institution a properly completed and duly executed letter
of transmittal (or in the case of a participant in The Depository
Trust Company, an agent's message) and notice of guaranteed delivery,
substantially in the form provided by us (or, in the case of a
participant in The Depository Trust Company, by an agent's message),
setting forth your name and address and the amount of old securities
tendered, stating that the tender is being made thereby and
guaranteeing that within three New York Stock Exchange trading days
after the date of execution of the notice of guaranteed delivery, the
certificates for all physically tendered old securities, in proper
form for transfer, 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
o the certificates for all physically tendered old securities, in proper
form for transfer, or a book-entry confirmation, as the case may be,
and any other documents required by the letter of transmittal are
received by the exchange agent within three New York Stock Exchange
trading days after the date of execution of the notice of guaranteed
delivery.
A tender will be deemed to have been received as of the date when your
properly completed and duly signed letter of transmittal accompanied by your
old securities is received by the exchange agent, or if you are a participant
in The Depository Trust Company, as of the date when an agent's message has
been received by the exchange agent. Issuances of new securities in exchange
for old securities tendered by a notice of guaranteed delivery by an eligible
institution will be made only against deposit of the letter of transmittal (and
any other required documents) and the tendered old securities.
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TERMS AND CONDITIONS OF THE LETTER OF TRANSMITTAL THAT YOU MAY BE REQUIRED TO
SUBMIT WITH YOUR TENDERED SECURITIES
The letter of transmittal contains the following terms and conditions,
which are part of the exchange offer:
o If you tender your old securities for exchange, you exchange, assign
and transfer the old securities to us and irrevocably constitute and
appoint the exchange agent as your agent and attorney-in-fact to cause
the old securities to be assigned, transferred and exchanged.
o You represent and warrant that you have full power and authority to
tender, exchange, assign and transfer the old securities and to
acquire new securities issuable upon the exchange of the tendered old
securities, and that, when the same are accepted for exchange, we will
acquire good and unencumbered title to the tendered old securities,
free and clear of all liens, restrictions, charges and encumbrances
and not subject to any adverse claim.
o You also warrant that you will, upon request, execute and deliver any
additional documents deemed by us to be necessary or desirable to
complete the exchange, assignment and transfer of tendered old
securities.
o You agree that acceptance of any tendered old securities by us and the
issuance of new securities in exchange therefor will constitute
performance in full of our obligations under the registration rights
agreement and that we will have no further obligations or liabilities
thereunder.
o All authority conferred by you will survive your death or incapacity
and your obligations will be binding upon your heirs, legal
representatives. successors, assigns, executors and administrators.
By tendering old securities, you certify that (1) you are not an
"affiliate" of ours within the meaning of Rule 405 under the Securities Act,
that you are not a broker-dealer that owns old securities acquired directly
from us, that you are acquiring the new securities offered hereby in the
ordinary course of your business and that you have no arrangement with any
person to participate in the distribution of the new securities or (2) you are
an "affiliate" of ours or of an initial purchaser and that you will comply with
the registration and prospectus delivery requirements of the securities Act to
the extent applicable to you. Each broker-dealer that receives new securities
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
the new securities.
YOU MAY WITHDRAW YOUR TENDER
Old securities tendered in the exchange offer may be withdrawn at any time
prior to 5:00 p.m. New York City time, on the expiration date. For a withdrawal
to be effective, a written, telegraphic, telex or facsimile transmission notice
of withdrawal must be timely received by the exchange agent at its address set
forth on the back of this prospectus. Any notice of withdrawal must specify the
name of the person having tendered the old securities to be withdrawn, identify
the old securities to be withdrawn, specify the name in which the old
securities are registered if different from that of the withdrawing holder,
accompanied by evidence satisfactory to us that the person withdrawing the
tender has succeeded to the beneficial ownership of the old securities being
withdrawn. If certificates for old securities have been delivered or otherwise
identified to the exchange agent, then, prior to the release of the
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 the holder is an
eligible institution. If old securities have been tendered by using the
procedure for book-entry transfer described above, any notice of withdrawal
must specify the name and number of the account at The Depository Trust Company
to be credited with the withdrawn old securities and otherwise comply with the
Depository Trust Company's procedures. If any old securities are tendered for
exchange but are not exchanged for any reason, or if any old securities are
submitted for a greater principal amount than the holder desires to exchange,
the
28
<PAGE>
unaccepted or nonexchanged old securities will be returned to the holder
without cost to the holder as soon as practicable after withdrawal, rejection
of tender, termination of the exchange offer or submission of nonexchanged old
securities.
IF YOU WITHDRAW YOUR TENDER, YOU MAY RETENDER YOUR OLD SECURITIES PRIOR TO THE
EXPIRATION DATE
Withdrawals of tenders of old securities may not be rescinded. Old
securities properly withdrawn will not be deemed validly tendered for purposes
of the exchange offer, but may be retendered at any subsequent time on or prior
to the expiration date by following any of the procedures described above.
All questions as to the validity, form and eligibility (including time of
receipt) of withdrawal notices will be determined by us in our sole discretion,
and our determination will be final and binding on all parties. Neither we, any
affiliates or assigns of ours, the exchange agent nor any other person will be
under any duty to give any notification of any irregularities in any notice of
withdrawal or incur any liability for failure to give any notification.
ACCEPTANCE OF OLD SECURITIES AND DELIVERY OF NEW SECURITIES
Upon the terms and subject to the conditions of the exchange offer, we
will exchange, and will issue to the exchange agent, new securities for old
securities validly tendered and not withdrawn promptly after the expiration
date. For the purposes of the exchange offer, we will be deemed to have
accepted for exchange validly tendered old securities when and if we have given
oral or written notice of acceptance to the exchange agent. The exchange agent
will act as agent for the tendering holders of old securities for the purposes
of receiving new securities from us and causing the old securities to be
assigned, transferred and exchanged. Upon the terms and subject to the
conditions of the exchange offer, delivery of new securities to be issued in
exchange for accepted old securities will be made by the exchange agent only
after timely receipt by the exchange agent of certificates for the old
securities or a timely book-entry confirmation of the old securities into the
exchange agent's account at The Depository Trust Company, a properly completed
and duly executed letter of transmittal and all other required documents, or,
in the case of a book-entry delivery, an agent's message.
SITUATIONS IN WHICH WE WILL NOT BE REQUIRED TO EFFECT THE EXCHANGE OFFER
Notwithstanding any other provisions of the exchange offer, or any
extension of the exchange offer, we will not be required to accept for
exchange, or to exchange, any old securities for any new securities, and, as
described below, may terminate the exchange offer (whether or not any old
securities have already been accepted for exchange) or may waive any conditions
to or amend the exchange offer, if any of the following conditions has occurred
or exists or has not been satisfied:
o the exchange offer, or the making of any exchange by a holder,
violates any applicable law or any applicable interpretation of the
staff of the Securities and Exchange Commission;
o in our reasonable judgment there is be threatened, instituted or
pending any action or proceeding before, or any injunction, order or
decree has been issued by, any court or governmental agency or other
governmental regulatory or administrative agency or commission, (1)
seeking to restrain or prohibit the making or consummation of the
exchange offer or any other transaction contemplated by the exchange
offer, (2) assessing or seeking any damages as a result of the
exchange offer or any other transaction contemplated by the exchange
offer, or (3) resulting in a material delay in our ability to accept
for exchange or exchange some or all of the old securities in the
exchange offer;
o any statute, rule, regulation, order or injunction is sought,
proposed, introduced, enacted, promulgated or deemed applicable to the
exchange offer or any of the transactions contemplated by the exchange
offer by any government or governmental authority, domestic or
foreign, or any action will have been taken, proposed or threatened by
any government, governmental authority, agency or court, domestic or
foreign, that in our reasonable judgment
29
<PAGE>
might directly or indirectly result in any of the consequences
referred to in clauses (1), (2) or (3) immediately above or, in our
reasonable judgment, might result in the holders of new securities
having obligations with respect to resales and transfers of new
securities which are greater than those described in the
interpretations of the staff of the Securities and Exchange Commission
referred to in this prospectus, or would otherwise make it inadvisable
to proceed with the exchange offer;
o there will have occurred (1) any general suspension of trading in, or
general limitation on prices for, securities on the New York Stock
Exchange, (2) a declaration of a banking moratorium or any suspension
of payments in respect of banks in the United States or any limitation
by any governmental agency or authority that adversely affects the
extension of credit to us, or (3) a commencement of a war, armed
hostilities or other similar international calamity directly or
indirectly involving the United States, or, in the case any of the
foregoing exists at the time of commencement of the exchange offer, a
material acceleration or worsening of the event; or
o a material adverse change will have occurred or be threatened in our
business, condition (financial or otherwise), operations, stock
ownership or prospects.
The foregoing conditions are for our sole benefit and may be asserted by
us with respect to all or any portion of the exchange offer regardless of the
circumstances (including any action or inaction by us) giving rise to the
condition or may be waived by us in whole or in part at any time or from time
to time in our sole discretion. Our failure at any time to exercise any of the
foregoing rights will not be deemed a waiver of these rights, and each right
will be deemed an ongoing right which may be asserted at any time or from time
to time. In addition, we have reserved the right, notwithstanding the
satisfaction of each of the foregoing conditions, to amend the exchange offer.
Any determination by us concerning the fulfillment or non-fulfillment of any
conditions will be final and binding upon all parties.
In addition, we will not accept for exchange any old securities tendered
and no new securities will be issued in exchange for any old securities, if at
the time any stop order will be threatened or in effect with respect to (1) the
registration statement of which this prospectus constitutes a part or (2) the
qualification of the indenture under the Trust Indenture Act of 1939.
THE PERSON ACTING AS EXCHANGE AGENT FOR THE EXCHANGE OFFER
Chase Manhattan Bank and Trust Company, National Association, has been
appointed as the exchange agent for the exchange offer. Chase Manhattan Bank
and Trust Company, National Association, also acts as trustee under the
indenture.
Delivery of letters of transmittal and any other required documents and
questions, requests for assistance and requests for additional copies of this
prospectus or the letter of transmittal, should be directed to the exchange
agent at its address and numbers set forth on the back of this prospectus.
Except in the case of a participant in The Depository Trust Company who
transfers securities by an agent's message, delivery to an address other than
as set forth in this prospectus, or transmissions of instructions via a
facsimile or telex number other than to the exchange agent as set forth in this
prospectus, will not constitute a valid delivery.
THE FEES AND EXPENSES WE WILL PAY IN CONNECTION WITH THE EXCHANGE OFFER
We have not retained any dealer-manager or similar agent in connection
with the exchange offer and will not make any payments to brokers, dealers or
others for soliciting acceptances of the exchange offer. We will, however, pay
the exchange agent reasonable and customary fees for its services and will
reimburse it for reasonable out-of-pocket expenses in connection therewith. We
will also pay brokerage houses and other custodians, nominees and fiduciaries
the reasonable out-of-pocket expenses incurred by them in forwarding copies of
this prospectus and related documents to the beneficial owners of old
securities, and in handling tenders for their customers. The
30
<PAGE>
expenses to be incurred in connection with the exchange offer, including the
fees and expenses of the exchange agent and printing, accounting and legal
fees, will be paid by us and are estimated at approximately $250,000.
YOU MAY BE REQUIRED TO PAY TRANSFER TAXES IN CONNECTION WITH YOUR TENDER
Holders who tender their old securities for exchange will not be obligated
to pay any transfer taxes in connection therewith. If, however, new securities
are to be delivered to, or are to be issued in the name of, any person other
than a registered holder of the old securities tendered, or if a transfer tax
is imposed for any reason other than the exchange of old securities in
connection with the exchange offer, then the amount of transfer taxes (whether
imposed on the registered holder or any other persons) will be payable by the
tendering holder. If satisfactory evidence of payment of the taxes or exemption
therefrom is not submitted with the letter of transmittal, the amount of
transfer taxes will be billed directly to the tendering holder.
NO ONE ELSE HAS BEEN AUTHORIZED TO PROVIDE YOU WITH INFORMATION REGARDING THE
EXCHANGE OFFER
No person has been authorized to give any information or to make any
representations in connection with the exchange offer other than those
contained in this prospectus. If so given or made, the information or
representations should not be relied upon as having been authorized by us.
Neither the delivery of this prospectus nor any exchange made under this
prospectus will, under any circumstances, create any implication that there has
been no change in our affairs since the respective dates as of which
information is given in this prospectus.
The exchange offer is not being made to (nor will tenders be accepted from
or on behalf of) holders of old securities in any jurisdiction in which the
making or acceptance of the exchange offer would not be in compliance with the
laws of the jurisdiction. However, we may, at our discretion, take any action
as we may deem necessary to make the exchange offer in the affected
jurisdiction and extend the exchange offer to holders of old securities in the
affected jurisdiction. In any jurisdiction that has securities laws or blue sky
laws which require the exchange offer to be made by a licensed broker or
dealer, the exchange offer is being made on behalf of us by one or more
registered brokers or dealers which are licensed under the laws of the
jurisdiction.
YOU WILL NOT HAVE APPRAISAL RIGHTS
Holders of old securities will not have dissenters' rights or appraisal
rights in connection with the exchange offer.
THE FEDERAL INCOME TAX CONSEQUENCES OF YOUR EXCHANGE
The exchange of old securities for new securities will not be a taxable
exchange for federal income tax purposes, and holders will not recognize any
taxable gain or loss or any interest income as a result of the exchange.
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<PAGE>
CAPITALIZATION
(IN THOUSANDS)
The following table sets forth our capitalization as of September 30,
1999. This table should be read in conjunction with our consolidated financial
statements and the notes to the consolidated financial statements appearing
elsewhere in this prospectus.
<TABLE>
<CAPTION>
SEPTEMBER 30, 1999
-------------------
INDEBTEDNESS:
<S> <C>
Parent company debt:
Old securities ......................... $ 400,000
Subsidiary and project debt(1):
Project loan ........................... 79,828
Salton Sea notes and bonds(2) .......... 597,898
----------
Total consolidated indebtedness ......... 1,077,726
----------
Members' equity ........................... 379,467
----------
Total capitalization .................... $1,457,193
==========
</TABLE>
- ----------
(1) Represents debt for which the repayment obligation is at the project or
subsidiary level.
(2) Subject to the terms and conditions of the guarantee, MidAmerican has
guaranteed the payment by the zinc guarantors of a specified portion of
the scheduled debt service, in an amount up to the current principal
amount of $140,520 and associated interest.
32
<PAGE>
SELECTED FINANCIAL DATA
(IN THOUSANDS)
The selected data presented below as of September 30, 1999 and for the
nine months ended September 30, 1999 and 1998 are derived from our unaudited
consolidated financial statements which reflect all adjustments necessary in
the opinion of our management for a fair presentation of the data and which are
included elsewhere in this prospectus. The selected data presented below as of
December 31, 1998 and 1997 and for the years ended December 31, 1998, 1997 and
1996 are derived from our audited consolidated financial statements. The
consolidated financial statements reflect the consolidated financial statements
of Magma and subsidiaries (excluding wholly-owned subsidiaries retained by
MidAmerican), Falcon Seaboard Resources and subsidiaries and Yuma Cogeneration,
each a wholly-owned subsidiary of MidAmerican. The consolidated financial
statements present our financial position, results of our operations and our
cash flows as if we were a separate legal entity for all periods presented.
These consolidated financial statements and auditors' report thereon are
included elsewhere in this prospectus. The selected data presented below as of
December 31, 1996 and 1995 and for the year ended December 31, 1995 are derived
from our unaudited consolidated financial statements and reflect all
adjustments necessary in the opinion of our management for a fair presentation
of the data. The selected data presented below as of December 31, 1994 and for
the year then ended are derived from the audited consolidated financial
statements of Magma and its subsidiaries which were not under MidAmerican
control prior to February 24, 1995 ("predecessor" to CE Generation).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
PREDECESSOR SUCCESSOR
------------- -------------------------------------------------------
1994 1995 (1) 1996 (2) 1997 1998
------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Sales of electricity and thermal energy ........... $ 158,374 $ 179,393 $ 281,307 $ 381,458 $ 395,560
Equity earnings in subsidiaries ................... -- -- 4,263 14,542 10,732
Interest and Other income ......................... 32,508 37,789 19,273 11,138 29,883
Total revenue ..................................... 190,882 217,182 304,843 407,138 436,175
Plant operations, general and
administrative, royalty and other expenses ....... 96,047 70,458 97,748 124,353 119,055
Depreciation and amortization ..................... 23,985 47,044 72,533 88,504 96,818
Interest expense, net of capitalized interest ..... 12,469 60,201 72,864 80,907 74,306
Provision for income taxes ........................ 19,832 10,348 15,487 43,378 52,218
Income before minority interest and
extraordinary item ............................... 38,549 29,131 46,211 69,996 93,778
Minority interest ................................. -- 4,091 -- -- --
Extraordinary item (3) ............................ -- -- -- -- --
Net income ........................................ 38,549 25,040 46,211 69,996 93,778
OTHER DATA:
Capital expenditures .............................. 58,045 93,944 90,734 21,676 46,222
Cash flows from operating activities .............. 72,968 69,234 118,700 158,732 154,363
Cash flows from investing activities .............. (30,846) (763,971) (304,977) 17,404 (130,685)
Cash flows from financing activities .............. (36,085) 732,879 168,941 (173,944) (21,588)
EBITDA (4) ........................................ 94,835 146,724 207,095 282,785 317,120
Ratio of EBITDA to fixed charges (4)(5) .......... 7.20 2.22 2.67 3.50 4.25
Ratio of earnings to fixed charges (5) ........... 5.38 1.51 1.79 2.52 3.04
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------
1998 1999
----------- -----------
<S> <C> <C>
STATEMENT OF OPERATIONS DATA:
Sales of electricity and thermal energy ........... $ 293,485 $ 231,613
Equity earnings in subsidiaries ................... 8,635 17,718
Interest and Other income ......................... 21,823 17,665
Total revenue ..................................... 323,943 266,996
Plant operations, general and
administrative, royalty and other expenses ....... 87,914 88,181
Depreciation and amortization ..................... 71,901 43,400
Interest expense, net of capitalized interest ..... 54,784 55,729
Provision for income taxes ........................ 39,364 30,520
Income before minority interest and
extraordinary item ............................... 69,980 49,166
Minority interest ................................. -- --
Extraordinary item (3) ............................ -- (17,478)
Net income ........................................ 69,980 31,688
OTHER DATA:
Capital expenditures .............................. 28,471 119,322
Cash flows from operating activities .............. 113,855 155,414
Cash flows from investing activities .............. (16,040) (30,359)
Cash flows from financing activities .............. (51,299) (66,848)
EBITDA (4) ........................................ 236,029 178,815
Ratio of EBITDA to fixed charges (4)(5) ........... 4.31 3.06
Ratio of earnings to fixed charges (5) ............ 3.09 2.41
</TABLE>
(footnotes on following page)
33
<PAGE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
PREDECESSOR SUCCESSOR
------------- -------------------------------------------------------
1994 1995 (1) 1996 (2) 1997 1998
------------- ------------- ------------- ------------- -------------
BALANCE SHEET DATA:
<S> <C> <C> <C> <C> <C>
Cash, restricted cash and investments ........... $113,428 $ 108,368 $ 43,422 $ 30,591 $ 154,327
Properties, plants, contracts and equipment,
net ............................................ 438,862 724,763 990,285 932,207 893,492
Note receivable from related party .............. -- -- -- -- 140,520
Total assets .................................... 623,486 1,149,858 1,611,087 1,560,874 1,782,385
Project loans, including current portion ........ 179,546 54,707 114,571 103,334 90,529
Salton Sea notes and bonds, including current
portion ........................................ -- 452,088 538,982 448,754 626,816
Senior Secured Bonds ............................ -- -- -- -- --
Notes payable to related party .................. -- 248,292 247,812 247,812 247,681
Total liabilities ............................... 233,670 916,433 1,156,184 1,096,734 1,245,438
Net investments and advances (members'
equity at September 30, 1999) .................. 389,816 233,425 454,903 464,140 536,947
<CAPTION>
AS OF
SEPTEMBER 30,
--------------
1999
--------------
BALANCE SHEET DATA:
<S> <C>
Cash, restricted cash and investments ........... $ 136,792
Properties, plants, contracts and equipment,
net ............................................ 982,258
Note receivable from related party .............. 140,520
Total assets .................................... 1,779,382
Project loans, including current portion ........ 79,828
Salton Sea notes and bonds, including current
portion ........................................ 597,898
Senior Secured Bonds ............................ 400,000
Notes payable to related party .................. --
Total liabilities ............................... 1,399,915
Net investments and advances (members'
equity at September 30, 1999) .................. 379,467
</TABLE>
- ----------
(1) Reflects the acquisition of approximately 51% of Magma Power Company on
January 10, 1995, and the remaining 49% on February 24, 1995. Includes
the results of operations of Magma Power Company from January 10, 1995
through December 31, 1995 adjusted for CE Generation's percentage
ownership during that time period.
(2) Reflects the acquisition of the remaining 50% of the Elmore, Vulcan, Del
Ranch and Leathers projects on April 17, 1996 and the acquisition of
Falcon Seaboard Resources on August 7, 1996.
(3) The extraordinary item recognized in the nine months ended September 30,
1999 reflects the early redemption of substantially all of the
outstanding 9 7/8% Limited Recourse Senior Secured Notes Due 2003.
(4) EBITDA means earnings before interest, taxes, depreciation and
amortization. EBITDA does not represent cash flows as defined by
generally accepted accounting principles (GAAP) and does not necessarily
indicate that cash flows are sufficient to fund all of a company's cash
needs. EBITDA is presented because we believe it is a widely accepted
financial indicator of a company's ability to incur and service debt.
EBITDA should not be construed as an alternative to either (1) operating
income (determined in accordance with GAAP) or (2) cash flow from
operating activities (determined in accordance with GAAP). EBITDA, as
defined, may differ from EBITDA as defined in similar offerings and, as
such, may not be comparable.
(5) For purposes of computing historical ratios of earnings to fixed charges,
earnings are divided by fixed charges. "Earnings" represent the aggregate
of (a) our pre-tax income, and (b) fixed charges, less capitalized
interest. "Fixed charges" represent interest (whether expensed or
capitalized), amortization of deferred financing and bank fees, and the
portion of rentals considered to be representative of the interest factor
(one-third of lease payments) and preferred stock dividend requirements
of majority subsidiaries.
34
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars and Shares in Thousands, Except Per Share Amounts)
The following is management's discussion and analysis of significant
factors which have affected our financial condition and results of operations
during the periods included in the accompanying statements of operations. Our
actual results in the future could differ significantly from our historical
results.
BUSINESS
MidAmerican Energy Holdings Company (formerly CalEnergy Company, Inc.)
completed a strategic restructuring in conjunction with its acquisition of MHC
Inc. (formerly MidAmerican Energy Holdings Company) in which MidAmerican's
common stock interests in Magma Power Company, Falcon Seaboard Resources, Inc.
and California Energy Development Corporation, and their subsidiaries (which
own the geothermal and natural gas-fired combined cycle cogeneration facilities
described below), were contributed by MidAmerican to us. This restructuring was
completed in February 1999.
Our consolidated financial statements reflect the consolidated financial
statements of Magma Power Company and subsidiaries (excluding wholly-owned
subsidiaries retained by MidAmerican), Falcon Seaboard Resources, Inc. and
subsidiaries and Yuma Cogeneration Associates, each a wholly-owned subsidiary.
The consolidated financial statements present our financial position, results
of operations and cash flows as if we were a separate legal entity for all
periods presented. Our basis in assets and liabilities have been carried over
from MidAmerican. All material intercompany transactions and balances have been
eliminated in consolidation.
We are engaged in the independent power business. The following table sets
out information concerning our projects:
<TABLE>
<CAPTION>
COMMERCIAL
PROJECT FUEL OPERATION CAPACITY LOCATION
- ------------------ ------------ ----------- ---------- -------------
<S> <C> <C> <C> <C>
Vulcan Geothermal 1986 34 MW California
Del Ranch Geothermal 1989 38 MW California
Elmore Geothermal 1989 38 MW California
Leathers Geothermal 1990 38 MW California
Salton Sea I Geothermal 1987 10 MW California
Salton Sea II Geothermal 1990 20 MW California
Salton Sea III Geothermal 1989 49.8 MW California
Salton Sea IV Geothermal 1996 39.6 MW California
Salton Sea V Geothermal 2000 49 MW California
CE Turbo Geothermal 2000 10 MW California
Power Resources Gas 1988 200 MW Texas
Yuma Gas 1994 50 MW Arizona
Saranac Gas 1994 240 MW New York
Norcon Gas 1992 80 MW Pennsylvania
</TABLE>
Vulcan, Del Ranch, Elmore, Leathers and CE Turbo are referred to as the
Partnership Projects. Salton Sea I, II, III, IV and V are referred to as the
Salton Sea Projects. The Partnership Projects and the Salton Sea Projects are
collectively referred to as the Imperial Valley Projects. Power Resources,
Yuma, Norcon and Saranac are referred to as the Gas Projects.
ACQUISITIONS
In April 1996, one of the three predecessor businesses combined in our
formation completed the buy-out of approximately $70,000 of its partner's
interests in four electric generating plants in
35
<PAGE>
Southern California, resulting in sole ownership of the Imperial Valley
projects. In August 1996, another one of the predecessor businesses acquired
Falcon Seaboard Resources, Inc. for approximately $226,000, thereby acquiring
significant ownership in 520 megawatts of natural gas-fired electric production
facilities located in New York, Texas and Pennsylvania and a related gas
transmission pipeline.
POWER GENERATION PROJECTS
The capacity factor for a particular project is determined by dividing
total quantity of electricity sold by the product of the project's capacity and
the total hours in the year. The capacity factors for Vulcan, Hoch (Del Ranch),
Elmore and Leathers plants are based on capacity amounts of 34, 38, 38 and 38
net megawatts, respectively. The capacity factors for Salton Sea Unit I, Salton
Sea Unit II, Salton Sea Unit III and Salton Sea Unit IV are based on capacity
amounts of 10, 20, 49.8 and 39.6 net megawatts, respectively. The capacity
factors for the Saranac, Power Resources, NorCon and Yuma plants are based on
capacity amounts of 240, 200, 80 and 50 net megawatts, respectively. Each
plant, except NorCon, possesses an operating margin which allows for production
in excess of the amount listed above. Utilization of this operating margin is
based upon a variety of factors and can be expected to vary throughout the year
under normal operating conditions. The amount of revenues received by these
projects is affected by the extent to which they are able to operate and
generate electricity. Accordingly, the capacity and capacity factor figures
provide information on operating performance that has affected the revenues
received by these projects.
Imperial Valley Projects--The current partnership projects sell all
electricity generated by the respective plants under four long-term standard
offer no. 4 agreements between the partnership projects and Southern California
Edison Company. These standard offer no. 4 agreements provide for capacity
payments, capacity bonus payments and energy payments. Southern California
Edison makes fixed annual capacity and capacity bonus payments to the
partnership projects to the extent that capacity factors exceed benchmarks set
forth in the agreements. The price for capacity and capacity bonus payments is
fixed for the life of the standard offer no. 4 agreements. Energy is sold at
increasing scheduled rates for the first ten years after firm operation and
thereafter at rates based on the cost that Southern California Edison avoids by
purchasing energy from the Imperial Valley projects instead of obtaining the
energy from other sources. We explain how Southern California Edison's avoided
cost of energy is expected to be determined under the heading "Description of
Principal Project Contracts--Imperial Valley Projects--Sale and Transmission of
Power--Standard Terms of SO4 Agreements--Fluctuating Energy Payments."
The California power exchange is a nonprofit public benefit corporation
formed under California law to provide a competitive marketplace where buyers
and sellers of power, including utilities, end-use customers, independent power
producers and power marketers, complete wholesale trades through an electronic
auction. The California power exchange currently operates two markets: (1) a
day ahead market which is comprised of twenty-four separate concurrent auctions
for each hour of the following day; and (2) an hour ahead market for each hour
of each day for which bids are due two hours before each hour. In each market,
the California power exchange receives bids from buyers and sellers and, based
on the bids, establishes the market clearing price for each hour and schedules
deliveries from sellers whose bids did not exceed the market clearing price to
buyers whose bids were not less than the market clearing price. All trades are
executed at the market clearing price.
The scheduled energy price periods of the partnership projects' long-term
agreements extended until February 1996, December 1998 and December 1998 for
each of the Vulcan, Del Ranch and Elmore projects, respectively, and extend
until December 1999 for the Leathers project. The Del Ranch and Elmore
projects' agreement provided for energy rates of 14.6 cents per kilowatt-hour
in 1998. The Leathers project's standard offer no. 4 agreement provided for an
energy rate of 14.6 cents per kilowatt-hour in 1998 and provides for an energy
rate of 15.6 cents per kilowatt-hour in 1999. The weighted average energy rate
for all of the partnership projects agreements was 11.7 cents per kilowatt-hour
in 1998 and 6.4 cents per kilowatt-hour for the nine months ended September 30,
1999.
36
<PAGE>
Salton Sea Unit I sells electricity to Southern California Edison under a
30-year negotiated power purchase agreement, which provides for capacity and
energy payments. The energy payment is calculated using a base price which is
subject to quarterly adjustments based on a basket of indices. The time period
weighted average energy payment for Salton Sea Unit I was 5.4 cents per
kilowatt-hour during 1998 and 5.3 cents per kilowatt-hour for the nine months
ended September 30, 1999. As the Salton Sea Unit I power purchase agreement is
not a standard offer no. 4 agreement, the energy payments do not revert to
payments based on the cost that Southern California Energy avoids by purchasing
energy from Salton Sea Unit I instead of obtaining the energy from other
sources. The capacity payment is approximately $1,100 per annum.
Salton Sea Unit II and Salton Sea Unit III sell electricity to Southern
California Edison under 30-year modified standard offer no. 4 agreements that
provide for capacity payments, capacity bonus payments and energy payments. The
price for contract capacity and contract capacity bonus payments is fixed for
the life of the modified standard offer no. 4 agreements. The energy payments
for each of the first ten year periods, which periods expire in April 2000 and
February 1999, respectively, are levelized at a time period weighted average of
10.6 cents per kilowatt-hour and 9.8 cents per kilowatt-hour for Salton Sea
Unit II and Salton Sea Unit III, respectively. Thereafter, the monthly energy
payments will be based on the cost that Southern California Energy avoids by
purchasing energy from Salton Sea Unit II or III instead of obtaining the
energy from other sources. For Salton Sea Unit II only, Southern California
Edison is entitled to receive, at no cost, 5% of all energy delivered in excess
of 80% of contract capacity through September 30, 2004. The annual capacity and
bonus payments for Salton Sea Unit II and Salton Sea Unit III are approximately
$3,300 and $9,700, respectively.
Salton Sea Unit IV sells electricity to Southern California Edison under a
modified standard offer no. 4 agreement which provides for contract capacity
payments on 34 megawatts of capacity at two different rates based on the
respective contract capacities deemed attributable to the original Salton Sea
Unit I power purchase agreement option (20 megawatts) and to the original Fish
Lake power purchase agreement (14 megawatts). The capacity payment price for
the 20 megawatts portion adjusts quarterly based upon specified indices and the
capacity payment price for the 14 megawatts portion is a fixed levelized rate.
The energy payment (for deliveries up to a rate of 39.6 megawatts) is at a
fixed rate for 55.6% of the total energy delivered by Salton Sea Unit IV and is
based on an energy payment schedule for 44.4% of the total energy delivered by
Salton Sea Unit IV. The contract has a 30-year term but Southern California
Edison is not required to purchase the 20 megawatts of capacity and energy
originally attributable to the Salton Sea Unit I power purchase agreement
option after September 30, 2017, the original termination date of the Salton
Sea Unit I power purchase agreement.
For the years ended December 31, 1998, 1997 and 1996, Southern California
Edison's average price paid for energy was 3.0 cents, 3.3 cents and 2.5 cents
per kilowatt-hour, respectively, which is substantially below the contract
energy prices earned for the year ended December 31, 1998. We cannot predict
the likely level of energy prices under the standard offer no. 4 agreements and
the modified standard offer no. 4 agreements at the expiration of the scheduled
payment periods. The revenues generated by each of the projects operating under
standard offer no. 4 agreements will decline significantly after the expiration
of the respective scheduled payment periods. Revenues for the Vulcan Project
decreased from $41,335 in the year ended December 31, 1995 to $16,968 in the
year ended December 31, 1996 after the end of the contract energy price period
in February 1996. Revenues for the Del Ranch Project decreased from $43,717 in
the nine months ended September 30, 1998 to $15,301 in the nine months ended
September 30, 1999 after the end of the contract energy price period in
December 1998. Revenues for the Elmore Project decreased from $40,886 in the
nine months ended September 30, 1998 to $14,912 in the nine months ended
September 30, 1999 after the end of the contract energy price period in
December 1998. If the Leathers Project received avoided cost energy rates in
1999 rather than the contract energy prices, revenues would have decreased from
$47,333 to $15,074 in the nine months ended September 30, 1999.
Natural Gas Projects--The Saranac project sells electricity to New York
State Electric and Gas Corporation under a 15-year negotiated power purchase
agreement, which provides for capacity and
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energy payments. Capacity payments, which in 1998 total 2.3 cents per
kilowatt-hour, are received for electricity produced during "peak hours" as
defined in the Saranac power purchase agreement and escalate at approximately
4.1% annually for the remaining term of the contract. Energy payments, which
averaged 6.7 cents per kilowatt-hour in 1998, escalate at approximately 4.4%
annually for the remaining term of the Saranac power purchase agreement. The
Saranac power purchase agreement expires in June of 2009.
The Power Resources project sells electricity to Texas Utilities Electric
Company under a 15 year negotiated power purchase agreement, which provides for
capacity and energy payments. Capacity payments and energy payments, which in
1998 are $3,138 per month and 3.0 cents per kilowatt-hour, respectively, and in
1999 are $3,248 per month and 3.1 cents per kilowatt-hour, respectively,
escalate at 3.5% annually for the remaining term of the Power Resources power
purchase agreement. The Power Resources power purchase agreement expires in
September 2003.
The NorCon project sells electricity to Niagara Mohawk Power Corporation
under a 25-year negotiated power purchase agreement which provides for energy
payments calculated using an adjusting formula based on Niagara Mohawk's
ongoing tariff price and the cost that Niagara Mohawk avoids in the long-run by
purchasing energy from the NorCon project instead of obtaining the energy from
other sources. The NorCon power purchase agreement term extends through
December 2017.
The Yuma project sells electricity to San Diego Gas & Electric Company
under a 30-year power purchase agreement. The energy is sold at a price based
on the cost that San Diego Gas & Electric avoids by purchasing energy from the
Yuma project instead of obtaining the energy from other sources and the
capacity is sold to San Diego Gas & Electric at a fixed price for the life of
the power purchase agreement. The power is delivered to San Diego Gas &
Electric over transmission lines constructed and owned by Arizona Public
Service Company.
RESULTS OF OPERATIONS, NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
Sales of electricity and steam decreased to $231,613 for the nine months
ended September 30, 1999 from $293,485 for the nine months ended September 30,
1998, a 21.1% decrease. This decrease was primarily a result of the expiration
of the fixed price periods for the Elmore and Del Ranch projects and for Salton
Sea Unit III. These periods ended in December 1998, December 1998 and February
1999, respectively.
The following operating data represents the aggregate capacity and
electricity production of the Imperial Valley projects:
<TABLE>
<CAPTION>
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 1999 SEPTEMBER 30, 1998
-------------------- -------------------
<S> <C> <C>
Overall capacity factor ........................ 97.3% 96.4%
Kilowatt-hours produced (in thousands) ......... 1,704,500 1,689,600
Capacity (net megawatts) (average) ............. 267.4 267.4
</TABLE>
The following operating data represents the aggregate capacity and
electricity production of the natural gas projects:
<TABLE>
<CAPTION>
NINE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 1999 SEPTEMBER 30, 1998
-------------------- -------------------
<S> <C> <C>
Overall capacity factor ........................ 86.5% 79.5%
Kilowatt-hours produced (in thousands) ......... 3,260,600 2,969,840
Capacity (net megawatts) (average) ............. 570 570
</TABLE>
The overall capacity factor of the natural gas projects reflects the
effect of contractual curtailments. The capacity factors adjusted for these
contractual curtailments are 96.64% and 91.60% for the nine months ended
September 30, 1999 and 1998, respectively. The overall increased capacity
factor of the natural gas projects reflects the impact of the January 1998 ice
storm at Saranac. The plant was down for approximately two months in the first
quarter of 1998.
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<PAGE>
The increase in equity earnings of subsidiaries for the nine months ended
September 30, 1999 to $17,718 from $8,635 for the nine months ended September
30, 1998 represents the negative impact of the January 1998 ice storm at
Saranac.
Interest and other income decreased to $17,665 for the nine months ended
September 30, 1999 from $21,823 for the nine months ended September 30, 1998.
This decrease was primarily due to reduced royalty income at the Imperial
Valley projects.
Plant operating expenses increased marginally for the nine months ended
September 30, 1999 to $84,848 from $84,100 for the nine months ended September
30, 1998. These costs include operating, maintenance, resource, fuel and other
plant operating expenses and the stability of these costs from period to period
reflect the maturity of plant operations.
General and administrative expenses decreased for the nine months ended
September 30, 1999 to $3,333 from $3,814 for the same period in 1998, a 12.6%
decrease. These costs include administrative services provided to us, including
executive, financial, legal, tax and other corporate functions. The decrease
reflects reduced corporate allocations to us due to a reduction in services
provided.
Depreciation and amortization decreased to $43,400 for the nine months
ended September 30, 1999 from $71,901 for the nine months ended September 30,
1998, a 39.6% decrease. The decrease was primarily due to reduced step up
depreciation after the end of the fixed price periods for the Del Ranch, Elmore
and Salton Sea Unit III projects as a result of greater value being assigned to
the scheduled price periods for the contracts relating to these projects at the
time of acquisition. The scheduled price periods for the contracts relating to
Del Ranch and Elmore expired in December 1998, with the Salton Sea III
scheduled price period terminating in February 1999.
Interest expense, less amounts capitalized, increased for the nine months
ended September 30, 1999 to $55,729 from $54,784 for the nine months ended
September 30, 1998, an increase of 1.7%. The increase was primarily due to
increased indebtedness from the issuances of the old securities in 1999.
The provision for income taxes decreased to $30,520 for the nine months
ended September 30, 1999 from $39,364 for the nine months ended September 30,
1998. The effective tax rate was 38.3% and 36% for the nine months ended
September 30, 1999 and 1998, respectively. The changes from year to year in the
effective rate are due primarily to the generation of energy tax credits and
depletion deductions.
RESULTS OF OPERATIONS, THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Sales of electricity and steam increased to $395,560 in the year ended
December 31, 1998 from $381,458 in the year ended December 31, 1997, a 3.7%
increase. This increase was primarily due to an increase in electricity
production at the Imperial Valley projects.
Sales of electricity and steam increased to $381,458 in the year ended
December 31, 1997 from $281,307 in the year ended December 31, 1996, a 35.6%
increase. This increase was due to the acquisition of Falcon Seaboard Resources
and the partnership interest in the Imperial Valley projects, as well as the
commencement of operations at Salton Sea Unit IV.
The following operating data represents the aggregate capacity and
electricity production of the Imperial Valley projects:
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Overall capacity factor ..................... 98.2% 99.2% 98.9%
Kilowatt-hours produced (in thousands) 2,299,400 2,323,800 2,179,200
Capacity (net megawatts) (average) .......... 267.4 267.4 251.0*
</TABLE>
----------
* Weighted average for the commencement of operations at Salton Sea Unit
IV in 1996.
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<PAGE>
The following operating data represents the aggregate capacity and
electricity production of the natural gas projects:
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Overall capacity factor ..................... 81.6% 84.3% 84.2%
Kilowatt-hours produced (in thousands) 4,072,620 4,211,030 4,216,800
Capacity (net megawatts) (average) .......... 570 570 570
</TABLE>
The overall capacity factor of the natural gas projects reflects the
effect of contractual curtailments. The capacity factors adjusted for these
contractual curtailments are 92.2%, 95.7% and 93.2% for 1998, 1997 and 1996,
respectively. The decrease in the overall capacity factor was due to lower
electricity production at Saranac due to severe winter snow and ice storms
which caused transmission curtailment, as well as a turbine overhaul at Power
Resources.
The decrease in equity earnings of subsidiaries in 1998 to $10,732 from
$14,542 in 1997 was primarily due to lower electricity production at Saranac
due to severe winter snow and ice storms which caused transmission
curtailments. The increase in equity earnings of subsidiaries in 1997 to
$14,542 from $4,263 in 1996 was primarily due to the acquisition of Falcon
Seaboard Resources in August 1996.
Interest and other income increased to $29,883 in the year ended December
31, 1998 from $11,138 in the year ended December 31, 1997. This increase was
primarily due to interest earned on higher cash balances as a result of the
issuance of Salton Sea Funding Corporation bonds in October 1998 and the
amortization of deferred income of $6,920, related to a settlement with respect
to our rights to receive payments in connection with our assignment to East
Mesa of power purchase contracts, power project facilities and geothermal
resource rights, which was received in 1998 and recognized as income through
the remainder of East Mesa's contract energy price period in June 1999.
Interest and other income decreased to $11,138 in the year ended December 31,
1997 from $19,273 in the year ended December 31, 1996, a 42.2% decrease. The
decrease is primarily attributable to lower cash balances and the fact we are
no longer recognizing management fee income as a result of the Imperial Valley
partnership interest acquisition in April 1996. Magma management services
income decreased by $5,311 as a result of this income being eliminated in
consolidation.
Plant operating expenses decreased in 1998 to $114,092 from $119,973 in
1997, a 4.9% decrease. The decrease was primarily due to operating
efficiencies. Operating expenses increased in 1997 to $119,973 from $94,245 in
1996, a 27.3% increase. This increase is primarily a result of the acquisitions
of Falcon Seaboard Resources and the Imperial Valley partnership interest as
well as the commencement of operations at Salton Sea Unit IV.
General and administrative expenses increased to $4,963 in the year ended
December 31, 1998 from $4,380 in the year ended December 31, 1997. General and
administrative expenses increased to $4,380 in the year ended December 31, 1997
from $3,503 in the year ended December 31, 1996. These costs include
administrative services provided to us, including executive, financial, legal,
tax and other corporate functions. The increases reflect increased bank service
charges relating to increased indebtedness.
Depreciation and amortization increased to $96,818 in 1998 from $88,504 in
1997, a 9.4% increase. The increase was due primarily to a modification of the
amortization method used to amortize the fair value adjustments associated with
the scheduled price periods of the four plants acquired in the Imperial Valley.
We modified our amortization method from the weighted average of the scheduled
price periods of the four plants to the scheduled price periods of each
individual plant. The impact of this modification was to increase amortization
expense by $7.5 million in 1998 compared with 1997. This change will not have
significant impact on future periods as the scheduled price period terminates in
1999. Depreciation and amortization increased to $88,504 in 1997 from $72,533 in
1996, a 22.0% increase. This increase is a result of the acquisitions of Falcon
Seaboard Resources and the Imperial Valley partnership interest as well as the
commencement of operations at Salton Sea Unit IV.
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<PAGE>
Interest expense, less amounts capitalized, decreased in 1998 to $74,306
from $80,907 in 1997, a decrease of 8.2%. Lower interest expense resulted from
the paydown of the Salton Sea Funding Corporation and Power Resources debt
offset by Salton Sea Funding Corporation's Series F issuance in October 1998.
Interest expense increased in 1997 to $80,907 from $72,864 in 1996, a 11.0%
increase. Higher interest expense for 1996 is primarily due to higher interest
expense on the Salton Sea Funding Corporation notes and bonds.
The provision for income taxes increased to $52,218 in 1998 from $43,378
in 1997 and $15,487 in 1996. The effective tax rate was 35.8%, 38.3% and 25.1%
in 1998, 1997 and 1996, respectively. The changes from year to year in the
effective rate are due primarily to the generation of energy tax credits and
depletion deductions.
LIQUIDITY AND CAPITAL RESOURCES
Cash and cash equivalents were $83,981 at September 30, 1999 as compared
to $25,774 at December 31, 1998. In addition, restricted cash was $52,811 and
$128,553 at September 30, 1999 and December 31, 1998, respectively. The
decrease in restricted cash was primarily due to the use of the proceeds from
issuance of Salton Sea Funding Corporation bonds for the construction of Salton
Sea Unit IV and the CE Turbo project and the construction of upgrades to the
brine facilities at some of the Imperial Valley projects.
We believe that existing cash and cash generated by operating activities
will be sufficient to finance capital expenditures and make scheduled repayment
of debt for the foreseeable future.
On March 2, 1999, we closed the sale of $400,000 aggregate principal
amount of old securities. The proceeds were used to repay Magma's 9 7/8% note
payable to MidAmerican of $200,000 and Yuma's note payable to MidAmerican of
$47,681. The remaining amount represented a distribution to MidAmerican in
return for MidAmerican's contribution of common stock and partnership interests
in geothermal and natural gas-fired combined cycle cogeneration facilities to
create us in MidAmerican's strategic restructuring which was completed in
February, 1999. These payments to MidAmerican were accounted as repayments of
notes payable to a related party and as an equity distribution to MidAmerican.
The securities are senior secured debt which rank equally in right of
payment with our other senior secured debt permitted under the indenture for
the securities, share equally in the collateral with our other senior secured
debt permitted under the indenture for the securities, and rank senior to any
of our subordinated debt permitted under the indenture for the securities.
These securities are effectively subordinated to the existing project financing
debt and all other debt of our consolidated subsidiaries.
The securities are secured by the following collateral:
o all available cash flow of our subsidiaries that have assigned their
available cash flows to secure our obligation to make payments on the
securities;
o a pledge of 99% of the equity interests in Salton Sea Power Company
and all of the equity interests in CE Texas Gas LLC, the assigning
subsidiaries (other than Magma Power Company) and California Energy
Yuma Corporation;
o upon the redemption of, or earlier release of security interests
under, Magma's 9 7/8% promissory notes, a pledge of all of the capital
stock of Magma;
o a pledge of all of the capital stock of SECI Holdings Inc.;
o a grant of a lien on and security interest in the depositary accounts;
and
o a grant of a lien on and security interest in all of our other
tangible and intangible property.
Scheduled principal payments on the securities commence on June 15, 2000,
and are payable thereafter through December 15, 2018, in varying semi-annual
payments ranging from approximately $5,000 to $18,000. The maximum annual
principal payment obligation during the period is approximately $36,000 in
2018.
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<PAGE>
Salton Sea Power L.L.C., one of our indirect wholly-owned subsidiaries, is
constructing Salton Sea Unit V. Salton Sea Unit V will be a 49 net megawatt
geothermal power plant which will sell approximately one-third of its net
output to the zinc facility, which will be retained by MidAmerican. The
remainder will be sold through the California power exchange.
Salton Sea Unit V is being constructed under an engineering, procurement
and construction contract by Stone & Webster Engineering Corporation. Salton
Sea Unit V is scheduled to commence commercial operation in mid-2000. Total
project costs of Salton Sea Unit V are expected to be approximately $119,067
which will be funded by $76,281 of debt from Salton Sea Funding Corporation and
$42,786 from equity contributions. Salton Sea Power has incurred approximately
$61,300 of these costs through September 30, 1999.
CE Turbo LLC, one of our indirect wholly-owned subsidiaries, is
constructing the CE Turbo project. The CE Turbo project will have a capacity of
10 net megawatts. The net output of the CE Turbo project will be sold to the
zinc facility or sold through the California power exchange.
The partnership projects are upgrading the geothermal brine processing
facilities at the Vulcan and Del Ranch projects with the region 2 brine
facilities construction.
The CE Turbo project and the region 2 brine facilities construction are
being constructed by Stone & Webster under an engineering, procurement and
construction contract. The obligations of Stone & Webster are guaranteed by
Stone & Webster, Incorporated. The CE Turbo project is scheduled to commence
initial operations in early-2000 and the region 2 brine facilities construction
is scheduled to be completed in early-2000. Total project costs for both the CE
Turbo project and the region 2 brine facilities construction are expected to be
approximately $63,747 which will be funded by $55,602 of debt from Salton Sea
Funding Corporation and $8,145 from equity contributions. CE Turbo has incurred
approximately $29,700 of these costs through September 30, 1999.
The net revenues, equity distributions and royalties from the partnership
projects are used to pay principal and interest payments on outstanding senior
secured bonds issued by the Salton Sea Funding Corporation, the final series of
which is scheduled to mature in November 2018. The Salton Sea Funding
Corporation debt is guaranteed by subsidiaries of Magma and secured by the
capital stock of the Salton Sea Funding Corporation. The proceeds of the Salton
Sea Funding Corporation debt were loaned by the Salton Sea Funding Corporation
under loan agreements and notes to subsidiaries of Magma and used for
construction of Salton Sea Unit V and the CE Turbo project, refinancing of
indebtedness and other purposes. Debt service on the Imperial Valley loans is
used to repay debt service on the Salton Sea Funding Corporation Debt. The
Imperial Valley loans and the guarantees of the Salton Sea Funding Corporation
debt are secured by substantially all of the assets of the guarantors,
including the Imperial Valley projects, and by the equity interests in the
guarantors.
The proceeds of Series F of the Salton Sea Funding Corporation debt are
being used in part to construct the zinc facility, and the direct and indirect
owners of the zinc facility are among the guarantors of the Salton Sea Funding
Corporation debt. MidAmerican has guaranteed the payment by the zinc guarantors
of a specified portion of the scheduled debt service on the Imperial Valley
loans described in the preceding paragraph, including the current principal
amount of $140,520 and associated interest.
On December 2, 1999, our indirect subsidiary, NorCon Power Partners, L.P.,
reached agreement with Niagara Mohawk Power Corporation to dismiss the
outstanding litigation between NorCon and Niagara Mohawk. At the same time,
NorCon transferred the NorCon project to General Electric Corporation and
entered into agreements with third parties to terminate some of NorCon's
contracts and to assign the rest of its contracts to a subsidiary of General
Electric Capital. General Electric Capital also agreed to be responsible for
other third party claims made against NorCon related to the NorCon project.
Thus, after December 2, 1999, neither NorCon nor any of our other subsidiaries
owns an interest in the NorCon project and the NorCon project contracts are no
longer in effect or have been assigned to third parties.
As our share of NorCon's earnings comprise less than 5% of the equity
earnings in subsidiaries for the nine months ended September 30, 1999 and our
share of NorCon's net assets is less than 1% of
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<PAGE>
the equity investments at September 30, 1999, the transfer of the NorCon
project to General Electric Capital is not expected to have any significant
impact on our results of operations, financial condition or liquidity.
YEAR 2000 ISSUES
What is generally known as the year 2000 computer issue arose because many
existing computer programs and embedded systems use only the last two digits to
refer to a year. Therefore, those computer programs do not properly distinguish
between a year that begins with "20" instead of "19". If not corrected, many
computer applications could fail or create erroneous results. The failure to
correct a material year 2000 item could result in an interruption in, or a
failure of, normal business activities or operations including the generation
of electricity. These failures could materially and adversely affect our
results of operations, liquidity and financial condition.
We have commenced, for all of our information systems, a year 2000 date
conversion project to address all necessary code changes, testing and
implementation in order to resolve the year 2000 issue. We created a year 2000
project team to identify, assess and correct all of our information technology
and non-information technology systems, as well as identify and assess systems
and equipment provided by other organizations. We have identified and assessed
substantially all of our information technology and non-information technology
systems as well as third party systems, which resulted in a list of 454 items
for review. A detailed review identified approximately 71% of these systems
with potential year 2000 issues because they have a date/time function. Of
these systems, approximately 34% were considered business critical systems. We
have substantially completed the process of repairing or replacing those
systems which were not year 2000 compliant.
Total year 2000 expenditures, for both repairing or replacing
non-compliant systems, were $344. We are not aware of any additional material
costs needed to be incurred to bring all of our systems into compliance,
however, we cannot assure you that additional costs will not be incurred.
In addition to our own information systems, the year 2000 issue also
creates uncertainty for us from potential issues with third parties with whom
we deal on transactions. As a result, year 2000 readiness of suppliers,
vendors, service providers or customers could impact our operations. We are
assessing the readiness of these constituent entities and the impacts on those
entities that rely upon our services. The vendor review process identified 54
third party vendors requiring assessment. Approximately 72% of those vendors
were identified as being critical to the business. We have substantially
completed the assessment of these vendors and no vendor risks to the business
have been identified. If we subsequently determine that these vendors put our
business at risk because of a lack of preparation, alternate vendors are secured
or other measures are put into place to provide the necessary goods and
services, however, we are unable to determine at this time whether the
consequences of year 2000 failures of third parties will have a material impact
on our results of operations, liquidity or financial condition.
A contingency plan identifying credible worst-case scenarios has been
developed. The contingency plan is comprised of both mitigation and recovery
aspects. Mitigation entails planning to reduce the impact of unresolved year
2000 problems, and recovery entails planning to restore services in the event
that year 2000 problems occur. The contingency plan contains various worst-case
scenarios, which include loss of internal and external voice and data
communications, loss of natural gas supply, transmission control, along with
numerous other scenarios, none of which is expected to be reasonably likely to
occur.
As of the date of this prospectus we have not experienced any material year
2000 issues.
INFLATION
Inflation has not had a significant impact on our cost structure.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, which established accounting and reporting
standards for derivative instruments
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<PAGE>
and for hedging activities. It requires that an entity recognize all derivatives
as either assets or liabilities in the statement of financial position and
measure those instruments at fair value. This statement is effective for all
fiscal quarters of fiscal years beginning after June 15, 2000. We have has not
yet determined the impact of this accounting pronouncement.
PENDING ACCOUNTING POLICY CHANGES
In 2000, we will change our method of accounting for major maintenance
costs from the accrual method to the deferral method pending any change in
current authoritative guidance. As of September 30, 1999, the cumulative effect
of this change would result in a one-time increase in net income of
approximately $9,700. We do not expect the continuing impact of this change to
have a material impact on our results of operations.
INTEREST RATE RISK
The following discussion of our exposure to various market risks contains
"forward-looking statements" that involve risks and uncertainties. These
projected results have been prepared utilizing assumptions considered
reasonable in the circumstances and in light of information currently available
to us. Actual results could differ materially from those projected in the
forward-looking information.
At December 31, 1998, we had a fixed-rate long-term debt (excluding note
payable to related party) of $626,816 in principal amount and having a fair
value of $646,397. These instruments are fixed-rate and therefore do not expose
us to the risk of earnings loss due to changes in market interest rates.
However, the fair value of these instruments would decrease by approximately
$35,000 if interest rates were to increase by 10% from their levels at December
31, 1998. In general, a decrease in fair value would impact earnings and cash
flows only if we were to reacquire all or a portion of these instruments prior
to their maturity.
At December 31, 1998, we had floating-rate obligations of $90,529 which
exposes us to the risk of increased interest expense in the event of increases
in short-term interest rates. We have entered into interest rate swap
agreements for the purpose of completely offsetting these interest rate
fluctuations. The interest rate differential is reflected as an adjustment to
interest expense over the life of the instruments. At December 31, 1998, these
interest rate swaps had an aggregate notional amount of $90,529, which we could
terminate at a cost of approximately $9,904. A decrease of 10% in the December
31, 1998 level of interest rates would increase the cost of terminating the
swaps by approximately $1,528. These termination costs would impact our
earnings and cash flows only if all or a portion of the swap instruments were
terminated prior to their expiration.
At September 30, 1999, the $400,000 of old securities had a fair value of
$363,419. However, the fair value would decrease by approximately $28,000 if
interest rates were to increase by 10% from their levels at September 30, 1999.
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<PAGE>
OUR BUSINESS AND THE BUSINESS OF THE ASSIGNING SUBSIDIARIES
OUR BUSINESS
We were formed as a special purpose Delaware limited liability company on
February 8, 1999. We were created to own our subsidiaries in order to
facilitate the transfer of a 50% interest in those subsidiaries to El Paso
Power Holding Company, a subsidiary of El Paso Energy Corporation. MidAmerican
Energy Holdings Company determined to sell 50% of its interest in us and our
subsidiaries in order to facilitate MidAmerican's acquisition of MHC Inc. In
August 1998, MidAmerican, which was then known as CalEnergy Company, Inc.,
announced its intention to acquire MHC Inc. (then known as MidAmerican Energy
Holdings Company). As MHC Inc. owned an electric utility, MidAmerican Energy
Company, MidAmerican was required to divest a portion of its ownership
interests in our power projects in order to permit those projects to maintain
their status as qualifying facilities under the Public Utilities Regulatory
Policies Act of 1978. This law requires that a non-electric utility own at
least 50% of a qualifying facility. The sale to El Paso Power, which does not
own an electric utility, was intended to permit our power projects to satisfy
this ownership requirement. By maintaining qualifying facility status, our
power projects are entitled to an exemption from federal and state utility
regulation under the Public Utilities Regulatory Policies Act and are able to
maintain compliance with the provisions of their current power purchase
agreements which require that they be qualifying facilities during the term of
those agreements.
On March 3, 1999, El Paso Power acquired 50% of MidAmerican's ownership
interests in us for approximately $245 million in cash plus $6.5 million in
contingent payments and the assumption of $23.5 million in obligations to make
equity contributions for the construction of Salton Sea Unit V and the CE Turbo
project. Our limited liability company operating agreement provides that
MidAmerican and El Paso Power each are entitled to appoint 50% of the directors
and are entitled to 50% of the distributions that we make.
MidAmerican agreed to provide administrative services, including
accounting, legal, personnel and cash management services, to us under an
administrative services agreement. MidAmerican is reimbursed for its actual
costs and expenses of providing the services. El Paso Power agreed to provide
power marketing and fuel management services to us in return for reimbursement
of its actual costs and expenses of providing the services. These agreements
each have an initial term of one year and then continue from year to year until
terminated by either party. We also entered into an agreement with MidAmerican
and El Paso to provide us with a right of first refusal to participate in the
development of any future geothermal power projects or combined geothermal
power and mineral recovery projects proposed by MidAmerican in the area of the
geothermal reservoir that currently supplies geothermal resources to the
Imperial Valley projects in return for the payment of a royalty to MidAmerican.
If we elect not to participate, the agreement gives MidAmerican the right to
develop the new project upon a showing that there are sufficient geothermal
resources for both the new project and our existing projects.
Our business activities will be limited to issuing the securities and
other debt as permitted under the indenture for the securities, holding the
equity interests in the assigning subsidiaries and related activities, and any
other activities which could not reasonably be expected to result in a material
adverse effect and which the rating agencies confirm in writing will not result
in a ratings downgrade. The only funds available to us to pay principal of,
premium (if any) and interest on the securities will be the available cash flow
received by the assigning subsidiaries and amounts on deposit in the debt
service reserve account.
OUR MEMBERS
MidAmerican. MidAmerican is a fast-growing global energy company with an
increasingly diversified portfolio of regulated and non-regulated assets. The
focus of MidAmerican has evolved over time from development and acquisition
activities in the domestic and international power generation markets to
strategic electric and gas utility acquisitions, with a particular emphasis on
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<PAGE>
investment-grade countries including the United States, the United Kingdom,
Australia, Canada, New Zealand and the countries of Western Europe. This focus
has provided MidAmerican with increased scale, skill, revenue diversity, credit
quality, quality of cash flows and additional growth opportunities associated
with each of the acquired businesses. MidAmerican's investments in related
activities, including producing gas fields, gas reserves and advanced utility
information systems, are primarily intended to support and augment the
profitability of its existing core businesses.
MidAmerican, headquartered in Des Moines, Iowa, has approximately 9,800
employees and is the largest publicly traded company in Iowa. Through its
retail utility subsidiaries, MidAmerican Energy Company in the United States
and Northern Electric plc in the United Kingdom, MidAmerican provides electric
service to 2.2 million customers and natural gas service to 1.2 million
customers worldwide. Through CalEnergy Generation, MidAmerican's independent
power production and non-regulated business subsidiary, and MidAmerican
Energy's utility operations, MidAmerican manages and owns interests in
approximately 8,300 net megawatts of diversified power generation facilities in
operation, construction and development. MidAmerican is the successor of
CalEnergy Company, Inc.
On October 25, 1999, MidAmerican announced that an investor group
comprised of Berkshire Hathaway Inc., Walter Scott, Jr. and David L. Sokol had
reached agreement to acquire MidAmerican for $35.05 per share in cash. The
purchase price together with the assumption of debt represents a total
enterprise value of approximately $9 billion. Upon completion of the
transaction, which is expected to occur by April 2000, MidAmerican would become
a privately owned company with publicly traded fixed income securities.
El Paso Power and El Paso Energy. El Paso Power is a wholly-owned
subsidiary of El Paso Energy. With over $10 billion in assets, El Paso Energy
provides energy solutions through its strategic business units: Tennessee Gas
Pipeline Company, El Paso Natural Gas Company, El Paso Field Services Company,
El Paso Power Services Company, El Paso Merchant Energy Company, and El Paso
Energy International Company. El Paso Energy owns the nation's only integrated
coast-to-coast natural gas pipeline system and has operations in natural gas
transmission, gas gathering and processing, power generation, energy marketing
and international energy infrastructure development.
THE ASSIGNING SUBSIDIARIES AND THE PROJECTS
The Assigning Subsidiaries. Each subsidiary that has assigned its
available cash flow to secure our obligation to make payments on the securities
owns an interest in one or more project companies. Below is a list showing
those project companies and other entities in which each assigning subsidiary
owns an interest.
o MAGMA: Salton Sea Power Generation L.P., Fish Lake Power LLC, Salton
Sea Power L.L.C., Vulcan Power Company, CalEnergy Operating
Corporation, Vulcan/BN Geothermal Power Company, Leathers, L.P.,
Del Ranch, L.P., Elmore, L.P., CE Turbo LLC, Salton Sea Royalty
LLC, Magma Land Company I and Imperial Magma LLC.
o SALTON SEA POWER: Salton Sea Power Generation L.P.
o FALCON SEABOARD RESOURCES: Saranac Power Partners, L.P., Power
Resources, Inc., NorCon Power Partners, LP, Falcon
Power Operating Company and CE Texas Gas LLC.
o FALCON SEABOARD POWER: Saranac, NorCon and Falcon Power Operating.
o FALCON SEABOARD OIL: Power Resources, Inc.
o CALIFORNIA ENERGY DEVELOPMENT: Yuma Cogeneration Associates.
o CE TEXAS ENERGY LLC: CE Texas Gas.
Magma and some of its subsidiaries provide administrative and other
services and the use of various real properties to the geothermal projects.
Falcon Power Operating, a wholly-owned
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subsidiary of Falcon Seaboard Power, provides operation and maintenance
services to the natural gas projects. CE Texas Gas, a wholly-owned subsidiary
of CE Texas Energy, provides natural gas for some of the natural gas projects.
The business of each of Salton Sea Power, Falcon Seaboard Resources,
Falcon Seaboard Power, Falcon Seaboard Oil, California Energy Development and
CE Texas Energy consists solely of holding its equity interest in the related
project companies. Substantially all of the business of Magma consists of
holding its equity interests in the geothermal projects and providing the
services to the geothermal projects described above. The business of each of
Falcon Power Operating and CE Texas Gas consists solely of providing the goods
and services to the natural gas projects described above. The assigning
subsidiaries' cash flow is derived solely from the activities described in this
paragraph. Each project company's business consists solely of the ownership and
operation of one or more projects or, in the case of Falcon Power Operating and
CE Texas Gas, the provision of the goods and services described above, and its
sole source of revenues consists of revenues derived from the operation of its
project(s) or the provision of goods and services.
The Projects. The following list describes each project and names the
project company that owns the project.
o SALTON SEA UNIT I: A 10 megawatt geothermal power plant owned by Salton
Sea Power Generation.
o SALTON SEA UNIT II: A 20 megawatt geothermal power plant owned by
Salton Sea Power Generation.
o SALTON SEA UNIT III: A 49.8 megawatt geothermal power plant owned by
Salton Sea Power Generation.
o SALTON SEA UNIT IV: A 39.6 megawatt geothermal power plant owned by
Salton Sea Power Generation and Fish Lake Power.
o SALTON SEA UNIT V: A 49 megawatt geothermal power plant under
construction owned by Power LLC.
o VULCAN PROJECT: A 34 megawatt geothermal power plant owned by Vulcan.
o ELMORE PROJECT: A 38 megawatt geothermal power plant owned by Elmore.
o LEATHERS PROJECT: A 38 megawatt geothermal power plant owned by
Leathers.
o DEL RANCH PROJECT: A 38 megawatt geothermal power plant owned by Del
Ranch.
o CE TURBO PROJECT: A 10 megawatt geothermal power plant under
construction owned by CE Turbo.
o SARANAC PROJECT: A 240 megawatt natural gas-fired combined cycle
cogeneration power plant owned by Saranac.
o POWER RESOURCES PROJECT: A 200 megawatt natural gas-fired combined
cycle cogeneration power plant owned by Power
Resources.
o YUMA PROJECT: A 50 megawatt natural gas-fired combined cycle
cogeneration power plant owned by Yuma Cogeneration.
Each project, other than Salton Sea Unit V and the CE Turbo project, meets
the requirements promulgated under the Public Utility Regulatory Policies Act
of 1978 to be a qualifying facility. Salton Sea Unit V and the CE Turbo project
are expected to be qualifying facilities when they commence operation. The
geothermal projects are designed to generate electricity and the natural gas
projects are designed to generate both electric energy and thermal energy. The
projects' actual outputs of electric energy and, where applicable, thermal
energy vary based on their design and the requirements of the power purchase
agreements and, where applicable, the thermal energy agreements of the
projects. The geothermal projects generate (or, in the case of Salton Sea Unit
V and the CE Turbo project, will generate) electricity from geothermal energy
and the other projects use natural gas as their primary source of fuel.
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Below are tables illustrating annual availability and annual capacity
factors for each of the projects other than Salton Sea Unit V and the CE Turbo
project. The annual availability figures are determined by dividing the sum of
the hours in which the project is operating (plus the hours the project is
available to operate but did not, due to a request by the power purchaser that
the project not operate) by the total hours in the year. The capacity factor
figures are determined by dividing total quantity of electricity sold (plus
electricity that would have been sold but was not due to a request by the power
purchaser not to operate where compensation is paid for the curtailment) by the
product of the project's capacity and the total hours in the year. These
factors provide information regarding the historical operating performance of
the projects. The amount of revenues received by these projects is affected by
the extent to which they are able to operate and generate electricity.
Accordingly, the availability factors and capacity factors provide information
on aspects of operating performance that have affected the revenues received by
these projects.
ANNUAL AVAILABILITY
<TABLE>
<CAPTION>
PROJECT AVERAGE 1998 1997 1996 1995 1994
- -------------------------------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Salton Sea Unit I .............. 96.3% 97.3% 97.3% 93.5% 93.7% 99.8%
Salton Sea Unit II ............. 97.0% 98.3% 98.4% 93.4% 95.2% 99.6%
Salton Sea Unit III ............ 96.1% 95.4% 98.1% 94.6% 92.7% 99.5%
Salton Sea Unit IV(1) .......... 94.5% 96.0% 95.9% 91.7% -- --
Vulcan ......................... 96.5% 96.1% 91.8% 98.3% 98.7% 97.6%
Leathers ....................... 97.3% 96.0% 99.1% 96.5% 97.4% 97.7%
Del Ranch ...................... 97.2% 98.4% 95.0% 98.8% 95.6% 98.4%
Elmore ......................... 96.8% 95.8% 99.0% 96.0% 98.5% 94.8%
Saranac ........................ 95.0% 92.8% 97.7% 95.2% 98.4% 90.7%
Power Resources ................ 92.4% 93.7% 91.2% 88.7% 97.4% 91.0%
Yuma ........................... 96.8% 96.0% 96.2% 97.0% 97.8% --
</TABLE>
ANNUAL CAPACITY FACTOR
<TABLE>
<CAPTION>
PROJECT AVERAGE 1998 1997 1996 1995 1994
- -------------------------------- --------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Salton Sea Unit I .............. 75.3% 90.2% 84.1% 71.3% 65.1% 65.8%
Salton Sea Unit II ............. 117.0% 120.7% 122.3% 114.4% 112.7% 114.9%
Salton Sea Unit III ............ 99.6% 99.8% 101.9% 98.1% 95.5% 102.6%
Salton Sea Unit IV(1) .......... 114.8% 111.6% 114.3% 118.6% -- --
Vulcan ......................... 117.0% 109.6% 108.6% 122.3% 126.7% 117.8%
Leathers ....................... 115.9% 114.9% 119.4% 113.5% 116.7% 114.9%
Del Ranch ...................... 117.9% 119.8% 114.9% 120.0% 115.8% 119.2%
Elmore ......................... 115.4% 111.5% 116.2% 116.1% 117.8% 115.6%
Saranac ........................ 92.4% 85.4% 95.0% 97.0% 95.1% 89.4%
Power Resources ................ 80.9% 82.3% 79.7% 77.0% 85.9% 79.5%
Yuma ........................... 89.0% 93.0% 85.3% 86.5% 91.0% --
</TABLE>
- ----------
(1) Began operations in May 1996; figures are annualized based on seven
months of operation.
INSURANCE
The project companies are required under the project financing documents
and project documents to maintain insurance coverages relating to their
interests in the projects. These coverages are consistent with those normally
carried by companies engaged in similar businesses. The coverages are currently
provided under a corporate umbrella program which includes liability insurance
and all-risk
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insurance covering physical loss or damage to the projects. This all-risk
insurance covers replacement value of all real and personal property including
losses from boiler and machinery breakdowns and the perils of earthquake and
flood, subject to sublimits, and business interruption. The current program
also covers the assigning subsidiaries, California Energy Yuma and SECI
Holdings to the extent applicable to their respective businesses. The project
financing documents typically require that most insurance proceeds be paid to
the applicable collateral agent for use in accordance with the terms of those
documents.
The lenders and trustees under the project financing documents also have
the benefit of title insurance with respect to the applicable projects.
EMPLOYEES
CalEnergy Operating and Falcon Power Operating currently employ 166 and 75
people full-time, respectively. Neither we nor Magma, Salton Sea Power, Falcon
Seaboard Resources, Falcon Seaboard Power, Falcon Seaboard Oil, California
Energy Development, CE Texas Energy or CE Texas Gas currently has any
employees.
LITIGATION
In addition to the proceedings described in the "Risk Factors" section of
this prospectus, some of the projects are currently parties to various minor
items of litigation, none of which, if determined adversely, would have a
material adverse effect on those projects.
REGULATORY MATTERS
FEDERAL ENERGY REGULATIONS
Qualifying Facility Status Under the Public Utility Regulatory Policies
Act. Qualifying facility status under the Public Utility Regulatory Policies
Act provides two primary benefits. First, regulations under the Public Utility
Regulatory Policies Act exempt qualifying facilities from the Public Utility
Holding Company Act of 1935, most provisions of the Federal Power Act and state
laws concerning rates of electric utilities and the financial and
organizational regulation of electric utilities. Second, regulations
promulgated under the Public Utility Regulatory Policies Act require that
electric utilities purchase electricity generated by qualifying facilities,
construction of which commenced on or after November 9, 1978, at a price based
on the cost that the purchasing utility avoids by purchasing energy from
qualifying facilities instead of obtaining the energy from other sources.
Order 888. In the Spring of 1996, FERC issued a landmark decision, known
as Order No. 888, designed to bring competition to the wholesale power market.
Order No. 888 required all public utilities that own, control or operate
transmission facilities used in interstate commerce to file non-discriminatory,
open access transmission tariffs (so-called "pro forma tariffs") with FERC. The
directive was intended to preclude utilities from using their ownership of
transmission facilities to favor their own generation in the marketplace. To
prevent this result, Order No. 888 required these utilities to "functionally
unbundle" all new wholesale generation and transmission service. Specifically,
the utilities were required to:
o separate the operations of their wholesale marketing arm and their
transmission provider arm, and quote separate prices for wholesale
generation and transmission service;
o take wholesale (and unbundled retail) transmission under their own pro
forma tariff; and
o provide and rely upon same time access to transmission information via
postings on so-called OASIS sites on the Internet.
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<PAGE>
STATE ENERGY REGULATIONS
The structure of state energy regulation of independent power producers is
now undergoing change and may change in the future. Below are some of the
recent developments in the states in which the projects are located or sell
power. Restructuring that promotes access to customers may provide
opportunities for the projects to sell power when the terms of their power
purchase agreements expire.
California (Imperial Valley Projects; Yuma). In December 1995, the
California Public Utilities Commission adopted a comprehensive plan for
restructuring California's electric industry. In August 1996, the California
Legislature approved, and on September 23, 1996 Governor Wilson signed into
law, comprehensive electric industry restructuring legislation, referred to in
this prospectus as AB 1890, which confirmed and enlarged upon the plan adopted
by the California Public Utilities Commission. California electric industry
restructuring includes, among other things, the creation of an independent
system operator and the California power exchange, direct access and retail
competition for all customers which became effective in 1998.
AB 1890 outlines a methodology which establishes energy pricing for those
generators who are paid rates based on the cost that the purchasing utility
avoids by purchasing energy from a qualifying facility instead of obtaining the
energy from other sources. Initially, the pricing is based on a 12-month
average of recent, pre-1996, avoided-cost based energy prices paid by a utility
to non-utility generators and is indexed to an appropriate gas price measure.
In the future, pricing will be based on the clearing price paid by the
California power exchange when the California Public Utilities Commission has
issued an order determining that the California power exchange is functioning
properly for purposes of determining the cost that utilities avoid by
purchasing energy from qualifying facilities instead of obtaining the energy
from other sources. In July 1999, the coordinating commissioner established a
procedural schedule that contemplated the issuance of this order by June 2000.
The California power exchange is a nonprofit public benefit corporation
formed to provide a competitive marketplace where buyers and sellers of power,
including utilities, end-use customers, independent power producers and power
marketers, complete wholesale trades through an electronic auction. The
California power exchange currently operates two markets: (1) a day ahead
market which is comprised of twenty-four separate concurrent auctions for each
hour of the following day; and (2) a market for each hour of each day for which
bids are due two hours before each hour. In each market, the California power
exchange receives bids from buyers and sellers and, based on the bids,
establishes the market clearing price for each hour and schedules deliveries
from sellers whose bids did not exceed the market clearing price to buyers
whose bids were not less than the market clearing price. All trades are
executed at the market clearing price.
New York (Saranac Project). In response to a mandate from the New York
State Public Service Commission, on January 31, 1997 the eight members of the
New York power pool, consisting of 7 public utilities and the New York Power
Authority, made filings with FERC evidencing their plan to restructure the
electric generation and distribution markets in New York State. Under the plan,
the New York power pool will be replaced with an independent system operator, a
New York State Reliability Council to establish reliability standards for the
competitive retail market, and the New York Power Exchange, a coordinated
bid-price market which will provide both a day-ahead market as well as a
competitive real-time spot market. In addition to these systemic changes, the
New York deregulation plan requires each of the New York independent public
utilities to generate its own plan for lowering prices, increasing competition
and introducing retail choice in their regions. New York State Electric and Gas
Corporation has obtained New York State Public Service Commission approval of
its restructuring plan.
Texas (Power Resources Project). In June 1999, the Texas legislature
approved a comprehensive plan for restructuring Texas' electric industry. The
plan, known as SB 7, which became effective on September 1, 1999, calls for
customer choice to be fully implemented in Texas by 2004. Currently, the Public
Utility Regulatory Act of 1995 authorizes the Public Utility Commission to
regulate the electricity market and ensure that only one electric energy
provider serves each area of the state.
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Among other things, SB 7 amends Public Utility Regulatory Act by deregulating
the electricity generation market and permitting selected electricity providers
to compete for customers who choose their electricity supplier in competitive
areas. SB 7 also authorizes the Commission to develop and promulgate customer
protection rules during and after a transition to a competitive market. The
Commission has not yet issued its rules implementing SB 7.
Arizona (Yuma Project). The Arizona legislature enacted House Bill 2663,
under which retail competition in electric generation was to begin no later
than December 31, 1998 for at least 20% of Arizona's 1995 retail load, with
full retail competition expected prior to December 31, 2000. On January 5,
1999, however, the Arizona Corporation Commission voted to stay the
implementation of its HB 2663's electric competition rules, pending additional
public hearings. The Commission indicated that additional time was necessary to
fine-tune the process and rules. In April, the Commission proposed new
comprehensive retail competition and stranded cost rules to provide retail
access to all customers by January 1, 2001.
FINANCIAL INCENTIVES FOR IMPERIAL VALLEY PROJECTS
Salton Sea Power L.L.C. and CE Turbo LLC also expect to receive incentive
payments from the State of California's New Renewable Resources Account for
energy sold by Salton Sea Unit V or the CE Turbo project through the Imperial
Irrigation District's transmission system during the first five years of
operation of each of these projects. The California Energy Commission has
selected Salton Sea Unit V to receive incentive payments from the New Renewable
Resources Account in an amount equal to $0.0124 per kilowatt-hour of energy
produced, up to $25,548,364.80 altogether, for the first five years of
operation. The Energy Commission has selected the CE Turbo project to receive
incentive payments from the New Renewable Resources Account in an amount equal
to $0.0134 per kilowatt-hour of energy produced, up to $5,751,816 altogether,
for the first five years of operation. The amount of the incentive payments for
the fourth and fifth years of operation of a project will be reduced by 25% if
the actual generation from the project over the first three years of operation
averages less than 85% of the estimated annual generation of the project
(412,070,400 kilowatt-hours for Salton Sea Unit V and 85,848,000 kilowatt-hours
for the CE Turbo project). In order for a project to remain eligible for
incentive payments, the project must continue to satisfy specified eligibility
criteria (including ownership and fuel use criteria) and the project must
timely satisfy specified milestones, including completion of construction of
the project by January 1, 2002.
The State of California has also established financial incentives for
existing renewable energy power projects which are available in the 1998-2001
time period. Projects must meet specified eligibility requirements, including
date of initial operation, ownership and fuel use criteria. Each of the
operating Imperial Valley projects other than Salton Sea Unit I and Salton Sea
Unit IV will become eligible for this program upon expiration of the fixed
price period in its power purchase agreement. The program provides geothermal
plants with a monthly amount per kilowatt-hour of power sold equal to the
lowest of (1) $0.01/kilowatt-hour, (2) $0.03/kilowatt-hour minus a calculated
market clearing price and (3) a specified amount of funds available for the
month divided by eligible generation. The Imperial Valley projects have already
begun receiving payments under this program.
ENVIRONMENTAL MATTERS
Each of the projects is subject to environmental laws and regulations at
the federal, state and local levels in connection with the development,
ownership and operation of the projects. These environmental laws and
regulations generally require that a wide variety of permits and other
approvals be obtained for the construction and operation of an energy-producing
facility and that the facility then operate in compliance with these permits
and approvals. Failure to operate the facility in compliance with applicable
laws, permits and approvals could result in the levy of fines or curtailment of
project operations by regulatory agencies.
We believe that each of the project companies is in compliance in all
material respects with all applicable environmental regulatory requirements and
that maintaining compliance with current
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<PAGE>
governmental requirements will not require a material increase in capital
expenditures or materially affect any of the project company's financial
condition or results of operations. It is possible, however, that future
developments, including more stringent requirements of environmental laws and
their enforcement policies, could affect the costs of compliance and the manner
in which the project companies conduct their business.
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OUR MANAGEMENT
OUR DIRECTORS AND EXECUTIVE OFFICERS
Below are our current executive directors and officers and their positions
with us:
<TABLE>
<CAPTION>
EXECUTIVE OFFICER POSITION
- --------------------------------- ------------------------------------------------
<S> <C>
Robert S. Silberman .......... Director, President and Chief Operating Officer
Brian K. Hankel .............. Vice President and Treasurer
Douglas L. Anderson .......... Director, Vice President and General Counsel
Richard P. Johnston .......... Vice President and Commercial Officer
Patrick J. Goodman ........... Director
Larry Kellerman .............. Director
John L. Harrison ............. Director
Steven M. Pike ............... Director
</TABLE>
ROBERT S. SILBERMAN, 40, President and Chief Operating Officer of us and
each assigning subsidiary. Mr. Silberman joined MidAmerican in 1995. Prior to
that, Mr. Silberman served as Executive Assistant to the Chairman and Chief
Executive Officer of International Paper Company from 1993 to 1995, as Director
of Project Finance and Implementation for the Ogden Corporation from 1986 to
1989 and as a Project Manager in Business Development for Allied-Signal, Inc.
from 1984 to 1985. He has also served as the Assistant Secretary of the Army
for the United States Department of Defense.
BRIAN K. HANKEL, 36, Vice President and Treasurer of MidAmerican, us and
each assigning subsidiary. Mr. Hankel joined MidAmerican in February 1992 as
Treasury Analyst and served in that position to December 1995. Mr. Hankel was
appointed Assistant Treasurer in January 1996 and was appointed Treasurer in
January 1997. Prior to joining MidAmerican, Mr. Hankel was a Money Position
Analyst at FirsTier Bank of Lincoln from 1988 to 1992 and Senior Credit Analyst
at FirsTier from 1987 to 1988.
DOUGLAS L. ANDERSON, 40, Vice President and General Counsel of CalEnergy
Generation, us and each assigning subsidiary. Mr. Anderson joined MidAmerican
in February 1993. From 1990 to 1993, Mr. Anderson was a business attorney with
Fraser, Stryker, Vaughn, Meusey, Olson, Boyer & Cloch, P.C. in Omaha. From 1987
through 1989, Mr. Anderson was a principal in the firm Anderson & Anderson.
Prior to that, from 1985 to 1987, he was an attorney with Foster, Swift,
Collins & Coey, P.C. in Lansing, Michigan.
RICHARD P. JOHNSTON, 43, Vice President and Commercial Officer of us and
Director of Operations for El Paso Energy International. Mr. Johnston joined El
Paso Energy in 1997 and was assigned to our management team at our founding in
March of 1999. In his 21 years of experience in power generation engineering
and management, Mr. Johnston has held positions directing Plant Operations and
Maintenance, Asset Management and Project Development in both the Domestic and
International Markets for ESI Energy, a Florida Power & Light subsidiary, from
1993 to 1997, and previously for The AES Corp., based in Arlington, VA, and
Westinghouse, based in Orlando, FL. Mr. Johnston has extensive experience in
hands-on management of the operations and maintenance of oil and gas-fired
combustion turbines, coal, biomass, geothermal and solar independent power,
including all aspects of construction management, mobilization and start-up.
PATRICK J. GOODMAN, 33, Senior Vice President and Chief Financial Officer
of MidAmerican and a director of us and each assigning subsidiary. Mr. Goodman
joined MidAmerican in June 1995 and served as Manager of Consolidation
Accounting until September 1996 when he was promoted to Controller. Prior to
joining MidAmerican, Mr. Goodman was a financial manager for National Indemnity
Co. from 1993 to 1995 and a certified public accountant at Coopers & Lybrand
from 1989 to 1993.
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LARRY KELLERMAN, 44, President of El Paso Power Services Company and a
director of us. Mr. Kellerman joined El Paso Energy in February 1998. Prior to
joining El Paso Energy, he was President of Citizens Power, where he initiated
Citizens' activities in the power marketing field in 1988, when Citizens was
the initial power marketer granted FERC authorization. From 1982 through 1988,
Mr. Kellerman was General Manager of Power Marketing and Power Supply for
Portland General Electric. From 1979 through 1982, Mr. Kellerman was Financial
Analyst and Power Contract Negotiator with Southern California Edison, where he
negotiated some of the first Public Utility Regulatory Policies Act qualifying
facility contracts in the nation.
JOHN L. HARRISON, 40, Senior Managing Director and Chief Financial Officer
of El Paso Merchant Energy and a director of us. Mr. Harrison joined El Paso
Energy in June 1996. Prior to joining El Paso Energy, Mr. Harrison was a
partner with Coopers & Lybrand LLP for five years.
STEVEN M. PIKE, 38, Vice President Structured Transactions of El Paso
Power Services Company and a director of us. Mr. Pike joined El Paso Energy in
April of 1998. Prior to joining El Paso Energy, Mr. Pike was Vice President
Risk Management for Enerz, a wholly-owned trading subsidiary of Zeigler Coal
Holding Company, and Director of Strategic Planning for Zeigler Coal Holding
Company from 1995 to 1998, and Director of Energy Development for Kennecott
Corporation from 1995 to 1996. Mr. Pike began his career with Niagara Mohawk
Power Corporation and held a number of positions in power system transmission
operations and generation dispatch planning, power contracting, fuel supply,
fossil and hydro generation planning, and strategic planning from 1983 to 1995.
Our directors and executive officers do not receive any compensation for
serving in these positions.
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OWNERSHIP OF OUR MEMBERSHIP INTERESTS
Fifty percent of our membership interests are owned by MidAmerican and the
other 50% are owned by El Paso Power. If the two owners of our membership
interests are unable to reach agreement on budgeting or other material
operational matters, the prior year's budget (adjusted for inflation) and
operational practices will be continued until agreement is reached. As of
September 30, 1999, our total capitalization was $1,457 million. There is no
public trading market for our membership interests. None of our directors or
executive officers beneficially own any of our equity interests. MidAmerican's
common stock is publicly traded on the New York, Pacific and London Stock
Exchanges. El Paso Power is owned indirectly by El Paso Energy. El Paso
Energy's common stock is publicly traded on the New York Stock Exchange.
OUR RELATIONSHIPS AND RELATED TRANSACTIONS
OUR RELATIONSHIPS WITH SUPPLIERS AND SERVICE PROVIDERS
The Imperial Valley projects' geothermal power plants are indirectly
wholly-owned and operated by Magma or subsidiaries of Magma. Land surface
rights for, and geothermal fluid supplying, these facilities is provided from
Magma's (or a subsidiary's) geothermal resource holdings in the Salton Sea
Known Geothermal Resource Area.
The Saranac project, the Power Resources project and the NorCon project
are indirectly partially- or wholly-owned by Falcon Seaboard Resources and are
operated and maintained by Falcon Power Operating, a wholly-owned subsidiary of
Falcon Seaboard Resources. Falcon Power Operating is entitled to reimbursements
and fees in exchange for providing operation and maintenance services. In
addition CE Texas Gas, a wholly-owned indirect subsidiary of Falcon Seaboard
Resources, procures natural gas for the Power Resources project.
OUR RELATIONSHIP WITH MIDAMERICAN AND EL PASO ENERGY CORPORATION
We are 50% owned by MidAmerican and 50% owned by El Paso Power. Our
activities are restricted by the terms of the indenture for the securities to
(1) ownership of our subsidiaries and related activities, (2) acting as issuer
of securities and other indebtedness as permitted under the indenture and
related activities and (3) other activities which could not reasonably be
expected to result in a material adverse effect so long as the rating agencies
confirm that these activities will not result in a downgrade of their ratings
of the securities. We and each of the assigning subsidiaries have been
organized and are operated as legal entities separate and apart from
MidAmerican, El Paso Energy and their other affiliates, and, accordingly, our
assets and the assets of the assigning subsidiaries will not be generally
available to satisfy the obligations of MidAmerican, El Paso Energy or any of
their other affiliates. However, our and the assigning subsidiaries'
unrestricted cash and other assets which are available for distribution may,
subject to applicable law and the terms of our and the assigning subsidiaries'
financing arrangements, be advanced, loaned, paid as dividends or otherwise
distributed or contributed to MidAmerican, El Paso Energy or their affiliates.
The securities are non-recourse to MidAmerican and El Paso Energy.
In connection with El Paso Power's acquisition of 50% of our interests,
MidAmerican entered into an administrative services agreement with us and El
Paso Power entered into a power marketing services agreement and a fuel
management services agreement with us. We reimburse MidAmerican and El Paso
Power for the actual costs and expenses of performing their obligations under
these agreements. These agreements each have an initial term of one year and
then continue from year to year until terminated by either party.
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REPORTS OF THIRD PARTY CONSULTANTS
OVERVIEW OF THE THIRD PARTY CONSULTANTS' REPORTS
We have included as appendices to this prospectus reports of third party
consultants in order to provide investors with important information regarding
the projects which is not included elsewhere in this prospectus. These reports
include the following:
o A report by Fluor Daniel, attached as Appendix C to this prospectus,
which reviews the geothermal projects and includes, among other things:
(1) an assessment of the historical and current operating performance of
Salton Sea Units I-IV and the Elmore, Del Ranch, Vulcan and Leathers
projects;
(2) a review of the design and technology for Salton Sea Unit V and the
CE Turbo project;
(3) an assessment of the capability of the participants in the geothermal
projects, including the construction contractor for Salton Sea Unit V
and the CE Turbo project;
(4) a determination of the reasonableness of the budgeted construction
costs for Salton Sea Unit V and the CE Turbo project;
(5) a discussion of the environmental permits required for the geothermal
projects and the compliance by the projects with these permits; and
(6) projections of the distributions to us from the geothermal projects
(which utilize the price projections prepared by Henwood Energy
Services, Inc. in the report attached as Appendix D to this
prospectus).
o A report by R.W. Beck, attached as Appendix B to this prospectus, which
reviews the natural gas projects and includes, among other things:
(1) an assessment of the historical and current operating performance of
Saranac, Power Resources, NorCon and Yuma projects;
(2) a review of the technology used in the natural gas projects;
(3) an assessment of the available supply of natural gas for the natural
gas projects;
(4) a discussion of the operation and maintenance procedures used at the
natural gas projects;
(5) an estimate of the useful lives of the natural gas projects;
(6) a discussion of the environmental permits required for the natural
gas projects and the compliance by the projects with these permits;
and
(7) projections of the distributions from the natural gas projects.
o Another report by Fluor Daniel, attached as Appendix A to this
prospectus, which contains projections of the consolidated distributions
from all of the projects based on the reports found in Appendices B and
C.
o A report by Henwood Energy Services, Inc., attached as Appendix D to
this prospectus, which reviews the California electricity market and
contains, among other things:
(1) an overview of the California wholesale electricity market;
(2) a forecast of the average prices for electricity in the California
market; and
(3) an assessment of the geothermal projects' ability to compete in the
California market.
o A report by GeothermEx, Inc., attached as Appendix E to this
prospectus, which assesses the sufficiency of the geothermal resources
available to be used for the production of electricity in the geothermal
projects.
56
<PAGE>
CONCLUSIONS REACHED BY THE THIRD PARTY CONSULTANTS
The third party consultants present the conclusions of their findings in
their reports. This section summarizes the principal conclusions reached by the
consultants. Additional conclusions, and the detailed discussions of how the
conclusions were reached, are contained in the reports.
Fluor Daniel reached the following conclusions, among others, in its
report regarding the geothermal projects:
o Salton Sea Units I-IV and the Vulcan, Del Ranch, Elmore and Leathers
projects use commercially proven technology and are operated in
accordance with recognized electric utility industry practices.
o The principal participants in the geothermal projects possess the
necessary experience to successfully fulfill their project obligations.
o The technology upon which Salton Sea Unit V and the CE Turbo project
are based is proven and reliable.
o Based upon a review of the construction contracts for Salton Sea Unit V
and the CE Turbo project, the capital cost budgets appear adequate for
the facilities provided under the contracts.
o The reviewed records show that no environmental notices of violation
for air emissions, wastewater or solid/hazardous waste have been filed
against the operating geothermal projects in the last two years.
o All discretionary environmental permit approvals have been received for
the proposed new construction.
o The assumptions underlying the economic/financial model appear to be
reasonable, and the projected operating results reasonably represent CE
Generation's future financial profile.
o Projected operating and maintenance costs and capital expenditures for
major maintenance projects appear to be reasonable and representative of
the planned operations of the geothermal projects.
o The financial projections, based on the base case assumptions
recommended by CE Generation, appear to be reasonable and indicate that
revenues should be adequate to pay operation and maintenance expenses and
provide cash flow for debt service and distributions.
R.W. Beck reached the following conclusions, among others, in its report
regarding the natural gas projects:
o The natural gas projects utilize sound technology and proven methods of
electric and thermal generation and have been designed and constructed in
accordance with generally accepted industry practices.
o Each of the Power Resources, Saranac and Yuma projects possesses
sufficient contracted natural gas commodity supply to meet the
requirements of its power purchase agreement and the contracted natural
gas transportation capacity for each of these projects is adequate to
reliably deliver the natural gas supply requirements.
o If the operators operate the Power Resources, Saranac and Yuma projects
in accordance with generally accepted industry practices, these projects
should have useful lives extending through the final maturity date of the
securities.
o All of the major permits and approvals required to operate the natural
gas projects have been or are currently in the process of being obtained.
o Based on the historical performance, operation and maintenance
practices and observed conditions of the Power Resources, Saranac and
Yuma projects, these projects should be capable of achieving the average
annual availabilities, net electrical capabilities, capacity factors,
steam supply requirements and heat rates assumed in the natural gas
projections.
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Fluor Daniel reached the following conclusions, among others, in its
report regarding the consolidated distributions from the projects:
o The consolidated financial model accurately represents the results of
the four project-specific models contained in Fluor Daniel's report on
the geothermal projects and R.W. Beck's report on the natural gas
projects.
o The consolidated financial model that is based on the base case
assumptions recommended by CE Generation and R.W. Beck indicates that
revenues appear to be adequate to provide sufficient cash flow for debt
service, with base case debt service coverage ratios calculated from 1999
through 2018 of 2.59x minimum and 3.08x average.
o The financial projections remain stable across a defined range of
sensitivities and avoided cost assumptions.
Henwood reached the following conclusions, among others, in its report
regarding the California electricity market:
o All of the geothermal projects and the Yuma project will be low cost
producers in all years of the study.
o The annual average operating cost of the geothermal projects in 2005 is
$17.5 per megawatt-hour.
o The annual average operating costs of the geothermal projects and the
Yuma project, in dollars per megawatt-hour, are below the annual average
California power exchange prices.
o The California power exchange price will be greater than or equal to
$20.3 per megawatt-hour in 96 percent of all hours in 2005. This means
that the geothermal projects and the Yuma project, with an average
operating cost of $17.5 per megawatt-hour, will be below the California
power exchange price.
o The base case forecast indicates that the California power exchange
clearing price will increase from $28.3 per megawatt-hour in 1999 to
$50.3 per megawatt-hour by 2018 in nominal dollars, which translates into
an average annual rate of increase of 3.1 percent over that period.
GeothermEx reached the following conclusions, among others, in its report
regarding the geothermal resources for the geothermal projects:
o The Salton Sea Known Geothermal Resource Area of Imperial Valley,
California is highly productive and wells have historically behaved
favorably with minimal flow rate or pressure declines.
o The additional production fluid needed for Salton Sea Unit V will be
supplied from existing wellhead capacity and the nominal additional
production fluid needed for the CE Turbo project can be supplied by spare
capacity at existing wells.
o Numerical simulation studies undertaken to date forecast acceptable
well behavior for the existing and planned level of power generation.
Well behavior has historically been consistent with results predicted by
earlier simulation models; therefore, future well behavior is expected to
be adequate to support the geothermal projects.
o The recoverable geothermal energy reserves from the reservoir are more
than sufficient to support existing projects and the planned additional
increments of capacity resulting in a total capacity of 326.4 megawatts.
GeothermEx estimates that 1,200 megawatts of reserves are available
within the portion of the Salton Sea Known Geothermal Resource Area of
Imperial Valley dedicated to the geothermal projects.
o The budget for wellfield costs is reasonable and should allow the
geothermal projects to achieve the forecasted levels of electrical
generation.
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ASSUMPTIONS MADE BY THE CONSULTANTS IN PREPARING THEIR REPORTS
The third party reports contain a number of assumptions and qualifications
made by the consultants. This section describes the primary assumptions and
qualifications. Additional assumptions and qualifications are described in the
reports.
The following assumptions and qualifications, among others, are contained
in Fluor Daniel's report regarding the geothermal projects:
o Fluor Daniel's inspection of the existing geothermal operations were
limited to visits of personnel on July 24, 1998 and February 9, 1999.
o Fluor Daniel did not undertake an independent review with all
regulatory agencies which could under any circumstances have jurisdiction
over, or interests pertaining to, the geothermal projects.
The following assumptions and qualifications, among others, are contained
in R.W. Beck's report regarding the natural gas projects:
o R.W. Beck made no determination as to the validity and enforceability
of any contract, agreement, rule or regulation applicable to the natural
gas projects and their operations. R.W. Beck assumed that all of these
contracts, agreements, rules and regulations will be fully enforceable in
accordance with their terms and that all parties will comply with the
provisions of their respective agreements.
o R.W. Beck's review of the design of the natural gas projects was based
on information provided by CE Generation and our visual observations
during our site visits.
o R.W. Beck assumed that the operators will maintain the natural gas
projects in accordance with good engineering practice, will perform all
required major maintenance in a timely manner, and will not operate the
equipment to cause it to exceed the equipment manufacturers' recommended
maximum ratings.
o R.W. Beck assumed that the operators will employ qualified and
competent personnel and will generally operate the natural gas projects
in a sound and businesslike manner.
o R.W. Beck assumed that the natural gas projects will identify and
implement solutions to the year 2000 problem in a manner which will not
impact the projected net revenues of the natural gas projects.
o R.W. Beck assumed that inspections, overhauls, repairs and
modifications are planned for and conducted in accordance with
manufacturers' recommendations, and with special regard for the need to
monitor operating parameters to identify early signs of potential
problems.
o R.W. Beck assumed that proposed restructuring of the electric utility
industry will not significantly impact the projected electricity revenues
of the Power Resources, Saranac and Yuma projects.
o R.W. Beck assumed that all licenses, permits and approvals and permit
modifications necessary to operate the natural gas projects have been, or
will be, obtained on a timely basis and any changes in required licenses,
permits and approvals will not require reduced operation of, or increased
costs to, the natural gas projects.
o R.W. Beck assumed that the consumer price index and general inflation,
used variously to escalate various revenues and expenses, will increase
at an average annual rate of 2.7 percent.
o R.W. Beck assumed that the Yuma natural gas contracts will be extended
at pricing provisions equal to the current agreements through the term of
the securities.
o R.W. Beck assumed that the non-fuel operating and maintenance expenses,
including the cost of major maintenance, will be consistent with the
information provided by CE Generation, and will increase thereafter at
the assumed change in the general inflation rate, except as noted
otherwise in R.W. Beck's report.
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o R.W. Beck assumed that there will be no additional capital improvements
to the Power Resources, Saranac and Yuma projects other than those
assumed in the projections.
o R.W. Beck assumed that there will be no distributions made to CE
Generation from the natural gas projects after the expiration of the
respective power purchase agreement.
o R.W. Beck assumed that there will be no distributions made to CE
Generation from the NorCon Project.
o R.W. Beck assumed that a full year of revenues from the Yuma project
will be available to pay the debt service on the securities in 2018, as
estimated by CE Generation.
Fluor Daniel stated in its report regarding the consolidated distributions
from all of the projects that it did not undertake an independent review with
all regulatory agencies which could under any circumstances have jurisdiction
over, or interests pertaining to, the projects.
The following assumptions and qualifications, among others, are contained
in Henwood's report regarding the California electricity market:
o Henwood assumed that the California electricity market would be fully
competitive by 2005.
o Henwood included only announced retirements in its estimate of the
number of generating units to be retired.
o Henwood assumed that gas-fired combined cycle units and gas-fired
combustion turbines will be added as needed to meet the projected
increase in customer demand over the forecast period.
o Henwood assumed that inflation would be 2.5%.
o Henwood assumed that peak demand and energy requirements would increase
at less than 2% per year.
o Henwood assumed that fixed and variable operation and maintenance costs
would escalate with inflation.
o Henwood's gas price forecast was developed based on the price of gas
futures contracts for the 1999 period and estimates of gas transportation
costs associated with moving gas from the relevant gas basin to the power
plant.
o Henwood used spot coal prices to simulate the economic operation of
coal plants.
GeothermEx does not list any specific assumptions in its report regarding
the geothermal resources for the geothermal projects.
INFORMATION OBTAINED FROM OUTSIDE SOURCES AND RELATIONSHIPS TO OTHER
CONSULTANTS.
Fluor Daniel obtained the following information from outside sources and
other reports included in this prospectus in preparing its report regarding the
geothermal projects:
o GeothermEx assessed the adequacy, reliability, and costs of geothermal
resources and wells.
o The projected interest rates on the securities, reinvestment rates,
cost of arranging the financing and the amortization schedule of the
securities used in the debt service coverage analysis were provided to
Fluor Daniel by CE Generation.
o CE Generation provided 1998 financial statements for the CE Generation
and other cost accounting information as well as future projections of
cost, expenses, prices and other key assumptions.
o GeothermEx provided brine quantities and depletion rates.
o Henwood provided the electricity pricing forecast.
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R.W. Beck obtained the following information from outside sources and
other reports included in this prospectus in preparing its report regarding the
natural gas projects:
o The price of electricity and natural gas for the Yuma project was
estimated by Henwood.
o The cost of natural gas to the Power Resources and Saranac projects and
the cost of natural gas transportation to the Yuma project was estimated
by C.C. Pace Consulting, L.L.C.
o CE Generation provided the senior debt service requirements and
interest income for the Power Resources and Saranac project.
Fluor Daniel obtained the following information from outside sources and
other reports included in this prospectus in preparing its report regarding the
consolidated distributions from all of the projects:
o R.W. Beck provided projections for the natural gas projects as
contained in Appendix B to this prospectus.
o The projected interest rates on the securities, reinvestment rates,
cost of arranging the financing and the amortization schedule of the
securities used in the debt service coverage analysis were provided to
Fluor Daniel by GE Generation.
o CE Generation provided 1998 financial statements for the CE Generation
and other cost accounting information as well as future projections of
cost, expenses, prices and other key assumptions.
o GeothermEx provided brine quantities and depletion rates.
o Henwood provided the electricity pricing forecast as contained in
Appendix D to this prospectus.
Henwood did not list any specific information obtained from outside
sources and other reports included in this prospectus in its report regarding
the California electricity markets.
GeothermEx obtained the following information from outside sources in
preparing its report regarding the geothermal resources for the geothermal
projects:
o CE Generation provided projection and injection histories from the
California Division of Oil, Gas and Geothermal Resources.
o CE Generation provided chemical analysis and information on the
drilling and logging of recent wells.
o CE Generation provided budget information for future wellfield
expenditures.
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SUMMARY DESCRIPTION OF PRINCIPAL PROJECT CONTRACTS
The following discussion includes a summary of all material terms of the
contracts related to the projects and the business of the assigning
subsidiaries and the project companies, and is not considered to be a full
statement of the terms of the contracts. We have filed the material agreements
as exhibits to the registration statement of which this prospectus is a part.
Unless otherwise stated, any reference in this prospectus to any agreement will
mean the agreement and all schedules, exhibits and attachments to the agreement
as amended, supplemented or otherwise modified and in effect as of the date of
this prospectus.
IMPERIAL VALLEY PROJECTS
Each of the Imperial Valley projects is (or, in the case of Salton Sea
Unit V and the CE Turbo project, is proposed to be) a geothermal power plant
located at the Salton Sea Known Geothermal Resource Area in Imperial Valley,
California. Below is a chart illustrating the commercial structure of the
Imperial Valley projects.
[GRAPHIC OMITTED]
SALE AND TRANSMISSION OF POWER
STANDARD TERMS OF SO4 AGREEMENTS
All of the power purchase agreements for the operating Imperial Valley
projects are standard offer no. 4 (or SO4) agreements, except the Salton Sea
Unit I power purchase agreement and the Salton Sea Unit IV power purchase
agreement. Although these SO4 agreements differ in some respects from the
standard SO4 agreement, many of the provisions are the same as those found in
the SO4 agreement. Below is a summary of the material terms and provisions
contained in each SO4 agreement.
Term and Termination. Each of the SO4 agreements has a contract term of 30
years from the firm operation date of the project. Upon expiration of the
contract term, the SO4 agreement remains in effect until either party
terminates the agreement upon 90 days prior written notice.
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The fixed price period is the first 10 years of the contract term. The
fluctuating price period begins upon expiration of the fixed price period and
continues for the remainder of the contract term.
Power Purchase Provisions. The SO4 agreement provides for (1) capacity
payments as described below and (2) energy payments either at an annually
escalating rate or at a levelized rate for the fixed price period and energy
payments based on the cost that the purchasing utility avoids by purchasing
energy from the project instead of obtaining the energy from other sources for
the fluctuating price period.
Capacity Payments. A project will qualify for a fixed annual capacity
payment by meeting specified performance requirements during the months of June
through September of each year. The project must deliver an average
kilowatt-hour output during specified on-peak hours of each month in the
on-peak period at a rate corresponding to at least an 80% contract capacity
factor to meet its performance requirement. The contract capacity factor equals
(1) a plant's actual electricity output divided by (2) the product of the
project's contract capacity and the number of hours in the measurement period
(less applicable maintenance and curtailment hours). If a project maintains the
required 80% contract capacity factor, then Southern California Edison must pay
a fixed annual capacity payment equal to the product of the contract capacity
price set forth in the agreement and the project's contract capacity. The fixed
annual capacity payment is paid in monthly installments, and the monthly
installment may be reduced if the contract capacity factor is less than 80% for
the month. Capacity payments are weighted toward the on-peak months.
The project company is required to annually demonstrate its contract
capacity by satisfying the performance requirement. If the project company does
not do so, it may be placed on probation for up to 15 months, and, if the
project company cannot satisfy the performance requirement during the
probationary period, the contract capacity will be reduced to the greater of
(1) what has been delivered during the probationary period or (2) what can
reasonably be delivered. Additionally, failure to satisfy the performance
requirement will subject the project company to the penalties described below.
However, if the project company's failure to meet the performance requirement
is due to a forced outage or a request by Southern California Edison to reduce
delivery, Southern California Edison must continue to pay the full firm
capacity payment. If the project company is unable to provide contract capacity
due to uncontrollable forces (such as a flood or an earthquake), Southern
California Edison must continue to pay the full firm capacity payments for 90
days from the occurrence of the uncontrollable force.
Capacity Bonus Payments. Under the SO4 agreements, the project companies
are entitled to receive capacity bonus payments in an on-peak month if the
relevant project operates at least at an 85% contract capacity factor during
the on-peak hours of the on-peak month, and qualifies in respect of non-peak
months if the contract capacity factors for all on-peak months have been at
least 85% and the project operates at a contract capacity factor of at least
85% during on-peak hours of the relevant non-peak month.
Capacity bonus payments for each month increase with the level of
kilowatt-hours delivered between the 85% and 100% contract capacity factor
levels during the month. The capacity bonus payment for each month is equal to
a percentage of the firm capacity payment based on the project's on-peak
contract capacity factor (which percentage may not exceed 18% of one-twelfth of
the firm capacity payment).
Changes in Contract Capacity. The project company may reduce contract
capacity by notice to Southern California Edison. The project company must
refund Southern California Edison an amount of money equal to the difference
between the accumulated monthly capacity payments paid by Southern California
Edison prior to the receipt of the reduction notice and the total monthly
capacity payments Southern California Edison would have paid based on the
adjusted capacity price, as well as interest at the prime rate. If the project
company fails to give notice, it can reduce contract capacity if it refunds
said amount plus a penalty equal to the product of (1) the contract capacity
being reduced, (2) the difference between the contract capacity price and the
adjusted capacity price and (3) the number of years and fractions (not less
than one year) by which the project company has been deficient in giving the
prescribed notice. If, however, the adjusted capacity price is less than the
contract capacity price, then no penalty is due.
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Energy Payments. In addition to capacity payments, each SO4 agreement
provides that Southern California Edison must make monthly energy payments
based on the number of kilowatt-hours of energy delivered by the relevant
project during the month. Energy payments are weighted toward on-peak months
and on-peak hours.
Annual Forecast Energy Payments. The Leathers SO4 agreement is an annual
forecast energy payment SO4 agreement. During the fixed price period the
project company is paid a monthly energy payment based on a schedule of the
forecast of the annual marginal cost of energy, which lists a price per
kilowatt-hour of 15.6 cents for 1999.
Levelized Energy Payments. Under the Salton Sea Unit II SO4 agreement,
during the fixed price period the energy payments are levelized to yield an
annual average of 10.6 cents per kilowatt-hour, weighted based on the relative
amounts of time to which each different price applies during the summer and
winter periods of a year. The project must deliver to Southern California
Edison at least 70% of the average annual kilowatt-hour delivered to Southern
California Edison during periods when the levelized energy payment price was
greater than the energy price in the forecast of the annual marginal cost of
energy schedule. If the project fails to satisfy this performance obligation or
fails to perform any other contract obligations during the fixed price period,
and, at that time, the net present value of the cumulative energy payments
received exceeds the net present value of what the project company would have
been paid under the annual forecast energy payment SO4 agreement, the project
company must refund the difference. The project company must post a performance
bond, guarantee, letter of credit or other security to insure payment to
Southern California Edison of any refund.
Fluctuating Energy Payments. During the fluctuating price period, all of
the project companies are paid a monthly energy payment at a rate which is
based on the cost that Southern California Edison avoids by purchasing energy
from the project instead of obtaining the energy from other sources. Southern
California Edison's avoided cost is currently determined by an approved interim
formula which adjusts historic costs by an inflation/deflation factor
representing monthly changes in the cost of natural gas at the California
border and adjustment factors based on the time of day, week and year in which
the energy is delivered. Consequently, under this methodology, energy payments
under the SO4 agreements will fluctuate based on the time of generation and
monthly changes in average fuel costs in the California energy market.
Legislation recently adopted in California establishes that the price
qualifying facilities receive as energy payments would be modified from the
current short-run avoided cost basis to the clearing price established by the
California power exchange once specified conditions are met. As the main
condition, the legislation requires that the California Public Utilities
Commission must first issue an order determining that the California power
exchange is functioning properly for the purposes of determining the short-run
avoided cost energy payments to be made to non-utility power generators.
Additionally, the project company may, upon appropriate notice to Southern
California Edison, exercise a one-time option to elect to thereafter receive
energy payments based upon the clearing price from the California power
exchange.
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In April 1995, Southern California Edison forecast its future costs
avoided by purchasing energy from qualifying power facilities instead of
obtaining it from other sources as follows:
<TABLE>
<CAPTION>
YEAR LOW MEDIAN HIGH
- -------- --------- -------- ---------
<S> <C> <C> <C>
1999 2.91 2.99 3.28
2000 3.11 3.22 3.60
2001 3.30 3.46 3.91
2002 3.42 3.59 4.13
2003 3.52 3.72 4.36
2004 3.62 3.88 4.61
2005 3.72 4.11 4.86
2006 3.83 4.31 5.16
2007 3.95 4.44 5.48
2008 4.06 4.59 5.82
2009 4.18 4.74 6.19
2010 4.31 4.89 6.59
2011 4.43 5.06 7.07
2012 4.57 5.22 7.60
2013 4.70 5.40 8.16
2014 4.84 5.58 8.76
2015 4.99 5.76 9.41
</TABLE>
The power market consultant's report (included as Appendix C to this
prospectus) also contains projections of future market prices of electricity.
Neither we nor any Imperial Valley assigning subsidiary has prepared or relied
upon any these forecasts. We and the Imperial Valley assigning subsidiaries
believe that all forecasts of energy prices are speculative in nature and that
there can be no assurance that the price paid by Southern California Edison for
energy in the future will be equal to any of the above forecasts. Southern
California Edison's actual energy price will be dependent upon, among other
factors, Southern California Edison's future fuel costs, system operation
characteristics, market prices for electricity (including California power
exchange prices) and regulatory action.
Curtailment. Southern California Edison is not required to accept or
purchase energy for a maximum of 300 hours per year during off-peak hours (1)
if the purchase would cost more than the costs Southern California Edison would
incur if it utilized energy from another source or (2) if the Southern
California Edison electric system demand would require that Southern California
Edison hydro-project water resources be spilled to reduce generation.
IMPERIAL VALLEY POWER PURCHASE AGREEMENTS
Salton Sea Unit I Power Purchase Agreement. The Salton Sea Unit I power
purchase agreement is not an SO4 agreement, although as described below it
contains many of the provisions customarily found in an SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of July 1, 1987. The contract capacity is 10 megawatts.
Capacity Payments. The capacity payment is based on a firm capacity price
which adjusts quarterly based on inflation-related indices. If Salton Sea Unit
I is able to deliver 100% of the contract capacity set forth in the agreement,
Salton Sea Unit I receives a monthly performance payment based on the then
current firm capacity price multiplied by the contract capacity and the energy
delivered from Salton Sea Unit I up to the contract capacity. Based on the
current capacity price of $127.80 per kilowatt-year, the annual maximum
capacity payment is $1,278,000. The Salton Sea Unit I power purchase agreement
does not provide for bonus capacity payments.
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If Salton Sea Unit I does not meet the performance requirement, Southern
California Edison may place the project on probation for a period not to exceed
15 months. If the performance requirement is not met during the probationary
period, Southern California Edison may derate the contract capacity.
Energy Payments. Salton Sea Unit I receives a monthly energy payment
calculated using a base price, which is subject to quarterly adjustments based
on inflation-related indices. The time period weighted average energy payment
was 5.4 cents per kilowatt-hour for the year ended December 31, 1998. As the
Salton Sea Unit I power purchase agreement is not an SO4 agreement, the energy
payments never revert to payments based on the cost that Southern California
Edison avoids by purchasing energy from Salton Sea Unit I instead of obtaining
the energy from other sources.
Salton Sea Unit II Power Purchase Agreement. Salton Sea Unit II sells
electricity to Southern California Edison under a modified SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of April 5, 1990. The contract capacity is 16.5 megawatts
during on-peak periods and 15 megawatts during mid-and off-peak periods.
Capacity Payments. Salton Sea Unit II has a contract capacity price of
$187 per kilowatt-year and, based on the contract capacity of 15 megawatts, the
annual maximum capacity payment is $2,805,000.
Energy Payments. The fixed price period for Salton Sea Unit II expires on
April 4, 2000. During the fixed price period, the energy payment is levelized
at a time weighted average of 10.6 cents per kilowatt-hour. After the fixed
price period, energy payments will be based on the cost that Southern
California Edison avoids by purchasing energy from Salton Sea Unit II instead
of obtaining the energy from other sources. For the period from April 1, 1994
through March 31, 2004, Southern California Edison is entitled to receive, at
no cost, 5% of all energy delivered in excess of contract capacity.
Salton Sea Unit III Power Purchase Agreement. Salton Sea Unit III sells
electricity to Southern California Edison under a modified SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of February 14, 1989. The contract capacity is 47.5
megawatts.
Capacity Payments. Salton Sea Unit III has a contract capacity price of
$175 per kilowatt-year and, based on the contract capacity of 47.5 megawatts,
the annual maximum capacity payment is $8,312,500.
Energy Payments. The fixed price period for Salton Sea Unit III expired on
February 13, 1999 and thus energy payments are now based on the cost that
Southern California Edison avoids by purchasing energy from Salton Sea Unit III
instead of obtaining the energy from other sources.
Salton Sea Unit IV Power Purchase Agreements. The Salton Sea Unit IV power
purchase agreement is not an SO4 agreement, although as described below it
contains many of the provisions customarily found in an SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of May 24, 1996. The contract capacity is 34 megawatts.
Capacity Payments. Through June 30, 2017, the capacity price is $121.72
per kilowatt-year plus quarterly inflation-related adjustments for 58.8% of the
contract capacity delivered by Salton Sea Unit IV. After June 30, 2017,
Southern California Edison will not be obligated to purchase this 58.8% of
capacity. Until the end of the contract term, Salton Sea Unit IV will be paid
$158 per kilowatt-year for 41.2% of the contract capacity delivered. The 1998
capacity payment was $5,010,000. Capacity bonus payments may be earned based on
the same criteria found in an SO4 agreement.
Energy Payments. Through June 30, 2017, the energy payments for 55.6% of
the total energy delivered by Salton Sea Unit IV (up to 110% of capacity) will
be calculated based on a base price of
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4.701 cents per kilowatt-hour, adjusted in accordance with inflation-related
indices. Until the end of the contract term, the energy payments for 44.4% of
the total energy delivered will be calculated according to a fixed price, based
on an energy payment schedule, for the first 10 years, Southern California
Edison's avoided cost plus a predetermined spread per kilowatt-hour for years
11 through 15 and Southern California Edison's avoided cost thereafter. After
June 30, 2017, all energy payments will be calculated as provided in the chart
below. However, Southern California Edison will not be obliged to purchase any
energy attributable to 55.6% of Salton Sea Unit IV's capacity. The energy
payments for the 44% portion of the agreement and, after June 30, 2017, all
energy delivered under the agreement, will be as follows:
<TABLE>
<CAPTION>
ENERGY PAYMENT
YEAR (CENTS/KILOWATT-HOUR) YEAR ENERGY PAYMENT (CENTS/KILOWATT-HOUR)
- -------- ----------------------- ------------ ----------------------------------------------
<S> <C> <C> <C>
1999 10.7 2006 3.5+Southern California Edison's avoided cost
2000 10.9 2007 2.9+Southern California Edison's avoided cost
2001 11.2 2008 2.2+Southern California Edison's avoided cost
2002 11.7 2009 1.2+Southern California Edison's avoided cost
2003 12.1 2010 1.0+Southern California Edison's avoided cost
2004 12.2 2011--2025 Southern California Edison's avoided cost
2005 12.4
</TABLE>
Salton Sea Unit V Power Purchase Agreement. Salton Sea Power LLC and
CalEnergy Minerals LLC, the owners of the zinc facility, have entered into a
power sales agreement whereby Power LLC has agreed to supply electricity to
Minerals LLC and Minerals LLC has agreed to purchase its electricity
requirements from Power LLC up to 49 megawatts.
Conditions Precedent. Power LLC's and Minerals LLC's obligations under the
Salton Sea Unit V power purchase agreement are subject to the prior condition
that both Salton Sea Unit V and the zinc facility are ready to commence initial
operation. If, by a specified date, the zinc facility is ready to commence
initial operation, but Salton Sea Unit V is not, Power LLC will be liable to
Minerals LLC for any resulting damages or losses. If Salton Sea Unit V is ready
to commence operations before the zinc facility, Salton Sea Unit V will be
entitled to sell its output to other customers until the zinc facility is
ready. We expect that, under these circumstances, Salton Sea Unit V would seek
to make additional short term sales of electricity through the California power
exchange or in other short term transactions.
Term. The contract term is for 25 years from the date of initial
deliveries.
Energy Payments. Power LLC will be paid a monthly energy payment equal to
the product of (1) the total quantity in kilowatt-hour of electrical energy
purchased and received by Minerals LLC during the month multiplied by (2) the
product of the California power exchange price multiplied by a percentage to
adjust for transmission losses, minus an adjustment factor based on
transmission service charges.
Elmore Power Purchase Agreement. Elmore sells electricity to Southern
California Edison under an SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of January 1, 1989. The contract capacity is 34 megawatts.
Capacity Payments. Elmore has a contract capacity price of $198 per
kilowatt-year and, based on the contract capacity of 34 megawatts, the annual
maximum capacity payment is $6,732,000.
Energy Payments. The fixed price period expired on December 31, 1998 and
thus energy payments are now based on the cost that Southern California Edison
avoids by purchasing energy from the Elmore project instead of obtaining the
energy from other sources.
Leathers Power Purchase Agreement. Leathers sells electricity to Southern
California Edison under an SO4 agreement which is identical in all material
respects to the Elmore power purchase agreement.
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Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of January 1, 1990. The contract capacity is 34 megawatts.
Capacity Payments. Leathers has a contract capacity price of $187 per
kilowatt-year and, based on the contract capacity of 34 megawatts, the annual
maximum capacity payment is $6,358,000.
Energy Payments. The Leathers power purchase agreement is an annual
forecast energy payment SO4 agreement. The fixed price period expired on
December 31, 1999, and thus energy payments are based on the cost that Southern
California Edison avoids by purchasing energy from the Leathers project instead
of obtaining the energy from other sources.
Del Ranch Power Purchase Agreement. Del Ranch sells electricity to
Southern California Edison under an SO4 agreement which is identical in all
material respects to the Elmore power purchase agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of January 2, 1989. The contract capacity is 34 megawatts.
Capacity Payments. Del Ranch has a contract capacity price of $198 per
kilowatt-year and, based on the contract capacity of 34 megawatts, the annual
maximum capacity payment is $6,732,000.
Energy Payments. The fixed price period expired on December 31, 1998 and
thus energy payments are now based on the cost that Southern California Edison
avoids by purchasing energy from the Del Ranch project instead of obtaining the
energy from other sources.
Vulcan Power Purchase Agreement. Vulcan sells electricity to Southern
California Edison under an SO4 agreement.
Term and Contract Capacity. The contract term is for 30 years from the
firm operation date of February 10, 1986. The contract capacity is 29.5
megawatts.
Capacity Payments. Vulcan has a contract capacity price of $158 per
kilowatt-year and, based on the contract capacity of 29.5 megawatts, the annual
maximum capacity payment is $4,661,000.
Energy Payments. The fixed price period expired on February 9, 1996. As a
result, energy payments for the balance of the contract term will be based on
the cost that Southern California Edison avoids by purchasing energy from the
Vulcan project instead of obtaining the energy from other sources.
TRANSMISSION SERVICE AGREEMENTS
Salton Sea Unit I delivers electricity to Southern California Edison at
the Salton Sea Unit I site. Each of the other operating Imperial Valley
projects delivers electricity to Southern California Edison on transmission
lines owned by the Imperial Irrigation District. These transmission lines
interconnect the operating plants with Southern California Edison's
transmission system. Transmission service charges are paid monthly to the
Imperial Irrigation District under transmission service agreements. The
transmission service agreement for Salton Sea Unit II expires in 2020; for
Salton Sea Unit III in 2019; and for Salton Sea Unit IV in 2026. The
transmission service agreements for the Leathers project, the Elmore project,
the Del Ranch project and the Vulcan project expire in 2015.
Salton Sea Power LLC has entered into a transmission service agreement
with the Imperial Irrigation District for Salton Sea Unit V and CE Turbo LLC
has entered into a transmission service agreement with the Imperial Irrigation
District for the CE Turbo project. These new agreements are similar to the
transmission service agreements for the operating Imperial Valley projects and
their terms are 30 years from the date of initial service. Power LLC has also
entered into a construction agreement with the Imperial Irrigation District
which obligates the Imperial Irrigation District to construct the necessary
transmission facilities to provide the transmission and distribution services
for Salton Sea Unit V and the CE Turbo project described above.
OPERATION AND MAINTENANCE SERVICES
CalEnergy Operating Corporation provides day-to-day operation and
maintenance services for the Imperial Valley projects under long-term operation
and maintenance agreements with the Imperial
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Valley project companies. The services provided by CalEnergy Operating under
the operation and maintenance agreements include, among other services, plant
operations, development and implementation of preventive maintenance plans,
maintenance of inventory, procurement of spare parts and disposal of spent
geothermal brine. CalEnergy Operating is reimbursed by the Imperial Valley
project companies for its actual costs and expenses incurred in the provision
of services under the operation and maintenance agreements.
ADMINISTRATIVE SERVICES
Magma provides administrative, management and technical services for
Salton Sea Units I-V and the CE Turbo project under long-term administrative
services agreements with the relevant Imperial Valley project companies.
CalEnergy Operating provides administrative, management and technical services
for the Vulcan, Elmore, Del Ranch and Leathers projects under long-term
administrative services agreements with the relevant Imperial Valley project
companies. The services provided by Magma and CalEnergy Operating under the
administrative services agreements include, among other services, (1) ordinary
services such as general bookkeeping and financial accounting services, general
legal services, personnel administration and payroll services, energy marketing
services and assistance in obtaining necessary franchises and permits, and (2)
technical services such as environmental compliance services, industrial
hygiene and structural engineering. Magma and CalEnergy Operating receive an
administrative fee equal to their actual costs plus a reasonable profit and a
technical fee equal to an amount specified in the agreements. The fees received
by Magma under the administrative services agreements will be included in
Magma's available cash flow.
Magma and CalEnergy Operating used to provide services to the Imperial
Valley project companies under the administrative services agreements using
CalEnergy Operating personnel, supplemented by personnel from MidAmerican. In
connection with the divestiture of 50% of our interests to El Paso Energy, we
entered into an administrative services agreement with MidAmerican in order to
provide administrative services that have customarily been provided by
MidAmerican for the Imperial Valley projects. This agreement will provide that
MidAmerican will be paid (1) for its actual out-of-pocket costs to third
parties and (2) a separate fee for services provided by MidAmerican employees
and use of MidAmerican assets. The fee described in clause (2) will be
subordinate to payment of debt service on the securities.
SURFACE LAND USE
IMPERIAL IRRIGATION DISTRICT
Salton Sea Brine Processing and Salton Sea Power Generation entered into a
ground lease with the Imperial Irrigation District. The Imperial Irrigation
District has leased the real property on which Salton Sea Units I and II are
located, consisting of approximately 117 acres, to Salton Sea Brine Processing
and Salton Sea Power Generation for a period of 33 years. The Salton Sea Units
I and II ground lease is triple net with original base rental payments of $400
per acre per annum. Every 5 years this per acre price may be adjusted based on
changes in the consumer price index as specified in the lease. The Salton Sea
Units I and II ground lease permits improvements and construction on the leased
property to increase capacity.
MAGMA
Magma and its affiliates Imperial Magma LLC and Magma Land Company I
control the land on which the Imperial Valley projects (other than Salton Sea
Units I and II) are located through a combination of fee, leasehold and royalty
interests. The Imperial Valley project companies have entered into long-term
agreements with Magma, Imperial Magma and Magma Land to obtain the surface
rights necessary to operate their projects. The payments received by Magma,
Imperial Magma and Magma Land under the surface land use agreements will be
included in Magma's available cash flow.
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GEOTHERMAL RIGHTS
Magma and Magma Land hold rights to use underground geothermal resources
in the Imperial Valley through a combination of fee and leasehold interests.
Magma and Magma Land have granted the Imperial Valley project companies the
rights to use these resources for power production purposes at their respective
projects under long-term easement agreements. We believe that the Imperial
Valley project companies have sufficient rights to geothermal resources to
operate their projects at capacity until the final maturity date of the
securities.
CONSTRUCTION CONTRACTS
SALTON SEA UNIT V
Stone & Webster agreed to design, engineer, procure, construct, commission
and test Salton Sea Unit V for an aggregate fixed price of $91,787,000. If
Salton Sea Unit V fails to satisfy performance guarantees regarding energy
production, thermal energy production and brine temperature, Stone & Webster
must pay performance liquidated damages in accordance with the terms of the
Salton Sea Unit V construction contract. Stone & Webster will also be obligated
to pay delay liquidated damages if Salton Sea Unit V is not completed on
schedule. If Stone & Webster completes construction ahead of schedule, Salton
Sea Power LLC must pay a bonus to Stone & Webster. Stone & Webster's liability
for liquidated damages under the contract is limited to 20% of the contract
price and its aggregate liability thereunder is limited to the full contract
price. Stone & Webster's payment and performance obligations under the Salton
Sea Unit V construction contract are guaranteed by its parent, Stone & Webster,
Incorporated. Salton Sea Unit V is expected to commence commercial operation in
mid-2000.
CE TURBO PROJECT
Stone & Webster agreed to design, engineer, procure, construct, commission
and test the CE Turbo project, as well as make capital improvements to the
brine facilities at the Imperial Valley projects, for an aggregate fixed price
of $49,800,000. If the CE Turbo project fails to satisfy performance guarantees
regarding energy production, Stone & Webster must pay performance liquidated
damages in accordance with the terms of the CE Turbo construction contract.
Stone & Webster will also be obligated to pay delay liquidated damages if the
CE Turbo project is not completed on schedule and is entitled to a bonus if
construction is completed ahead of schedule. Stone & Webster's liability for
liquidated damages under the contract is limited to 20% of the contract price
and its aggregate liability thereunder is limited to the full contract price.
Stone & Webster's payment and performance obligations under the CE Turbo
construction contract are guaranteed by its parent, Stone & Webster. The CE
Turbo project is expected to commence commercial operation in mid-2000.
PROJECT COMPANY OWNERSHIP
SALTON SEA PROJECTS
Salton Sea Units I, II and III are owned by Salton Sea Power Generation,
Salton Sea Unit IV is owned by Salton Sea Power Generation and Fish Lake Power
LLC and Salton Sea Unit V is owned by Salton Sea Power LLC. Salton Sea Power
Generation is 99% owned by Salton Sea Brine Processing and 1% owned by Salton
Sea Power, which in turn is 99% owned by Magma and 1% owned by Salton Sea
Funding Corporation. Salton Sea Power also owns a 1% general partnership
interest in Salton Sea Brine Processing and Magma owns a 99% limited
partnership interest Salton Sea Brine Processing. Ninety-nine percent of the
capital stock of Fish Lake is owned by Magma, with Salton Sea Funding
Corporation owning the remaining 1%. CE Salton Sea Inc. owns 100% of the
membership interests in Power LLC. Magma owns 99% of the capital stock of CE
Salton Sea and Salton Sea Funding Corporation owns the remaining 1%. Magma owns
100% of the capital stock of Salton Sea Funding Corporation, and we own 100% of
the capital stock of Magma. Below is a chart illustrating the ownership
structure for Salton Sea Units I-V.
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[BLOCK CHART SHOWING THE OWNERSHIP STRUCTURE OF SALTON SEA UNITS I-V]
PARTNERSHIP PROJECTS
The Leathers Project is owned by Leathers, the Del Ranch project is owned
by Del Ranch, the Elmore project is owned by Elmore, the Vulcan project is
owned by Vulcan and the CE Turbo project is owned by Turbo LLC. Each of
Leathers, Del Ranch and Elmore are 40% owned by CalEnergy Operating and 10%
owned by Magma. The remaining 50% of the interests in Leathers, Del Ranch and
Elmore are owned by San Felipe Energy Company, Conejo Energy Company and Niguel
Energy Company, respectively. San Felipe, Conejo and Niguel are each
wholly-owned by CalEnergy Operating. Each of Vulcan Power Company and VPC
Geothermal LLC own a 50% interest in Vulcan. VPC Geothermal is wholly owned by
Vulcan Power. CalEnergy Operating and Vulcan Power are 99% owned by Magma and
1% owned by Salton Sea Funding Corporation. CE Salton Sea owns 100% of Turbo
LLC. Below is a chart illustrating the ownership structure for the Vulcan, Del
Ranch, Elmore, Leathers and CE Turbo projects.
[BLOCK CHART SHOWING THE OWNERSHIP STRUCTURE OF THE ELMORE, DEL RANCH, VULCAN,
LEATHERS AND CE TURBO PROJECTS]
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PROJECT FINANCING DEBT
The revenues received by the Imperial Valley project companies from the
geothermal projects and the zinc facility are used to make payments on
outstanding senior secured bonds issued by Salton Sea Funding Corporation in
multiple series. As of September 30, 1999, outstanding Imperial Valley project
financing debt totaled $597.9 million and consisted of the following:
o $33,482,000 of 6.69% Series A Senior Secured Notes due 2000;
o $104,378,000 of 7.37% Series B Senior Secured Bonds due 2005;
o $109,250,000 of 7.84% Series C Senior Secured Bonds due 2010;
o $6,825,000 of 7.02% Series D Senior Secured Bonds due 2000;
o $58,961,000 of 8.30% Series E Senior Secured Bonds due 2011; and
o $285,000,000 of 7.475% Series F Senior Secured Bonds due 2018.
Collateral; Guarantees. The proceeds of the Imperial Valley project
financing debt were loaned by Salton Sea Funding Corporation to subsidiaries of
Magma. The Imperial Valley project financing debt is secured by a pledge of the
capital stock of Salton Sea Funding Corporation and guaranteed by the Magma
subsidiaries. These loans and guarantees are secured by the following
collateral:
o an assignment of the revenues, equity distributions and royalties
received by the Magma subsidiaries;
o a lien on substantially all of the assets of the Magma subsidiaries,
including the geothermal projects and related material contracts; and
o a pledge of the equity interests in the Magma subsidiaries.
In connection with the divestiture of 50% of our interests to El Paso
Power, MidAmerican provided a guarantee to Salton Sea Funding Corporation of
the payment by the owners of the zinc facility of a portion of the principal of
and interest on the loans made to the Magma subsidiaries.
Additional Project Debt. The Imperial Valley project financing documents
permit the incurrence of the following additional project-level debt, subject
to the satisfaction of debt service coverage tests, ratings confirmations and
other conditions described in the Imperial Valley project financing documents:
o debt incurred to finance additional permitted power facilities in the
Imperial Valley region;
o debt incurred to finance capital improvements to the Imperial Valley
projects required to comply with applicable laws;
o debt incurred to finance discretionary capital improvements to the
Imperial Valley projects;
o up to $15 million of working capital debt;
o debt incurred in connection with a debt service reserve letter of
credit;
o debt incurred in connection with permitted interest rate protection
agreements;
o up to $30 million of debt incurred in connection with the development,
construction, ownership, operation, maintenance or acquisition of
permitted power facilities; and
o up to $200 million of subordinated debt from affiliates for purposes
specified in the Imperial Valley project financing documents.
Distributions. Distributions are permitted under the Imperial Valley
project financing documents upon the satisfaction of the following conditions:
o the project accounts are fully funded;
o no default or event of default has occurred and is continuing;
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o the debt service coverage ratio for the prior four fiscal quarters is
at least 1.4 to 1.0, if the distribution occurs prior to 2000, or 1.5
to 1.0, if the distribution occurs during or after 2000;
o there are sufficient geothermal resources to operate the Imperial
Valley projects at their required levels; and
o each Imperial Valley project under construction will not have failed
to be completed by its guaranteed substantial completion date (or, in
the alternative, buy-down or ratings confirmation requirements will
have been satisfied).
SELECTED FINANCIAL INFORMATION
The Imperial Valley project companies made distributions to the assigning
subsidiaries in 1996, 1997 and 1998 in the amounts of approximately $75.3
million, $146.4 million and $134.0 million, respectively.
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SARANAC PROJECT
The Saranac project is a 240 megawatt natural gas-fired combined cycle
cogeneration facility located in Plattsburgh, New York. The Saranac project is
owned by Saranac Power Partners, L.P. and commenced commercial operation in
June 1994. Below is a chart illustrating the commercial structure of the
Saranac project.
[BLOCK CHART SHOWING THE COMMERCIAL STRUCTURE OF THE SARANAC PROJECT]
SALE AND TRANSMISSION OF POWER
SARANAC POWER PURCHASE AGREEMENT
Saranac sells capacity and energy from the Saranac project to New York
State Electric and Gas under the Saranac power purchase agreement. The initial
term of the Saranac power purchase agreement expires in June 2009. The contract
capacity under the Saranac power purchase agreement is 240 megawatts. New York
State Electric and Gas's long-term debt obligations were rated "Baa1" by
Moody's and "BBB" by S&P as of January 1999.
Payments for Actual Generation. The Saranac power purchase agreement
provides for payments by New York Electric and Gas for electricity produced by
the Saranac project at fixed prices specified in a schedule set forth in the
Saranac power purchase agreement, which include both a capacity component and
an energy component. Peak-hour pricing, which applies from 7:00 a.m. to 10:00
p.m., weekdays, excluding holidays, ranges from 10.34 cents per kilowatt-hour
in 1999 to 15.82 cents per kilowatt-hour in 2009. Off-peak hour pricing ranges
from 6.09 cents per kilowatt-hour in 1999 to 9.39 cents per kilowatt-hour in
2009. New York State Electric and Gas has sought to reduce these rates on the
alleged grounds that they exceed the levels permitted under the Public Utility
Regulatory Policies Act.
Dispatch and Curtailment. By an amendment to the Saranac power purchase
agreement, New York State Electric and Gas obtained limited rights to dispatch
the Saranac project at less than full capacity, agreed to make payments in
connection with any dispatch below full capacity based on the amounts Saranac
would have received if it had delivered electricity less amounts saved as a
result of its lower level of operation, and waived curtailment rights under
FERC regulations that might otherwise be claimed to apply.
Regulatory and Other Termination Rights. New York State Electric and Gas
may terminate the Saranac power purchase agreement without liability to Saranac
if the Saranac project ceases to be a
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qualifying facility under the Public Utility Regulatory Policies Act. In the
event New York State Electric and Gas terminates the Saranac power purchase
agreement as a result of a default by Saranac, Saranac is obligated to pay New
York State Electric and Gas an amount equal to the difference between the total
amount paid by New York State Electric and Gas for electricity under the
Saranac power purchase agreement prior to the termination and the amount New
York State Electric and Gas would have paid for the electricity during the term
of the Saranac power purchase agreement at a price based on the cost that New
York State Gas and Electric avoids by purchasing energy from the Saranac
project instead of obtaining the energy from other sources, plus interest.
Saranac has secured this obligation by a mortgage on and security interest in
the Saranac project which is subordinated to the liens of the Project lenders
under the Saranac project financing documents.
Other Rights of New York State Electric and Gas. If:
o Saranac fails to operate the plant for a sufficient period of time as
to create a reasonable expectation that Saranac does not intend to
resume operation;
o a bankruptcy or foreclosure proceeding against Saranac commences;
o deficiencies in project maintenance as determined by the lenders'
independent engineer are not remedied by Saranac within the time
specified by this engineer; or
o a default occurs under Saranac's agreements with its lenders,
then New York State Electric and Gas has the right to step in and operate the
Saranac project until the circumstance giving rise to this right has been
remedied, subject to the rights of the project lenders under the Saranac
project financing documents. None of these circumstances currently exist.
INTERCONNECTION
The facilities necessary to interconnect the Saranac project to the New
York State Electric and Gas system were constructed at Saranac's expense and
are owned and maintained by New York State Electric and Gas. Under the Saranac
power purchase agreement, New York State Electric and Gas is required to
arrange for the transmission of electricity generated by the Saranac project to
the extent necessary for the operation of the New York State Electric and Gas
system. For this transmission, Saranac made payments to New York State Electric
and Gas which were approximately $5,050,000 in 1998, and which increase by 5%
each year.
SALE OF THERMAL ENERGY
Saranac sells steam to Georgia-Pacific and Tenneco Packaging under
long-term steam sales agreements. We believe these agreements will enable
Saranac to sell the minimum annual quantity of thermal energy necessary for the
Saranac project to maintain its qualifying facility status under the Public
Utility Regulatory Policies Act for the term of the Saranac power purchase
agreement.
FUEL PROCUREMENT
NATURAL GAS SUPPLY
Saranac entered into a gas sale and purchase agreement with Shell Canada
Limited which provides for the delivery of a maximum daily volume of 51,000
MMBtu of gas on a firm basis for 15 years, expiring in May 2007. The agreement
has been assigned to Coral Energy Canada, an affiliate of Shell Canada, and
guaranteed by Shell Canada. The gas supply agreement provides for an initial
gas price of $2.97 per MMBtu (1994 dollars), which escalates at 4% annually,
and Saranac must pay the unutilized firm transportation costs incurred by Coral
Energy if Saranac does not take the maximum daily volume of gas. In each year
during the term of the gas supply agreement, Saranac is obligated to take or
pay for an amount of gas equal to at least 80% of the aggregate of the maximum
daily volumes of gas for each day in the year.
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NATURAL GAS TRANSPORTATION
Saranac entered into an agreement for firm gas transportation service with
TransCanada Pipelines Limited, which expires on the later of October 2008 or
another date determined by Saranac, but in no case later than March 2010. The
TransCanada gas transportation agreement provides for transportation of a
maximum daily volume of gas not to exceed 53,000 MMBtu from the
Alberta/Saskatchewan border to the United States/Canada border. Saranac
assigned the TransCanada gas transportation agreement to Shell Canada, which
pays TransCanada a portion of the payments it receives from Saranac for gas
supply under the gas supply agreement described above.
North Country Gas Pipeline Corporation, a wholly-owned subsidiary of
Saranac, transports the gas required for operation of the Saranac project from
the United States/Canada border approximately 22 miles to the Saranac project.
North Country has entered into a gas transportation agreement with Saranac
which expires in June 2024, but which can be terminated by Saranac upon one
year's notice after June 2009. The North Country gas transportation agreement
provides for daily deliveries of gas up to a maximum of 51,000 MMBtu on a firm
basis and 5,000 MMBtu on an interruptible basis. The payments made by Saranac
under the North Country gas transportation agreement provide for a recovery of
North Country's costs of acquiring, financing and maintaining its pipeline
facilities.
OPERATION AND MAINTENANCE SERVICES
Saranac entered into a 16-year agreement with Falcon Power Operating which
expires in July 2010 for the operation and maintenance of the Saranac project.
The duties of Falcon Power Operating under this agreement include coordinating
day-to-day operations with New York State Electric and Gas and the purchasers
of thermal energy from the Saranac project, performing routine on-line
maintenance and scheduled off-line maintenance, taking corrective action with
respect to any unscheduled outages and providing reports to Saranac regarding
the amount of electricity and thermal energy generated, the volume of fuel
consumed and the level of usage of other utilities. Falcon Power Operating is
paid a fixed monthly management fee of $125,000, adjusted annually for cost of
living increases, and is reimbursed for the direct costs of its services.
Falcon Power Operating is entitled to a bonus or is required to pay a penalty
based on the annual availability and heat rate of the Saranac project, provided
that the total bonus or penalty in any year may not exceed 50% of the aggregate
management fees for the year. Saranac may terminate the Saranac operation and
maintenance agreement if, due to Falcon Power Operating's operation of the
Saranac project, the annual availability of the Saranac project is less than
86% of its potential availability or the average annual heat rate exceeds the
maximum rate specified in the agreement. The liability of each of Falcon Power
Operating and Saranac (other than for penalties and bonuses) under the
operation and maintenance agreement is limited to an aggregate amount not to
exceed $1.5 million in excess of any available insurance proceeds.
OWNERSHIP OF PROJECT SITE
Title to the Saranac project and the interests in the land on which it was
constructed are held by the County of Clinton Industrial Development Agency.
Saranac occupies the Saranac project site under an installment sale agreement
with the Clinton IDA. The Clinton IDA has agreed to sell the property to
Saranac for payments equal to the amounts due from the Clinton IDA with respect
to the Saranac project financing documents and other expenses incurred by the
Clinton IDA relating to the Saranac project. The installment sale agreement
will terminate and the property will be conveyed to Saranac in 2024. The
Clinton IDA has entered into a similar installment sale agreement with North
Country with respect to the pipeline facilities used by North Country to
transport gas to the Saranac project, which terminates in 2009.
PROJECT COMPANY OWNERSHIP
Saranac Energy Company, Inc., an indirect wholly-owned subsidiary of
Falcon Seaboard Resources, is the sole general partner of Saranac and also owns
a limited partnership interest in
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Saranac. The other limited partners in Saranac are TPC Saranac Partner One,
Inc. and TPC Saranac Partner Two, Inc., each a wholly-owned indirect subsidiary
of Tomen Corporation, and GE Capital. Below is a chart illustrating the
ownership structure for the Saranac project.
[GRAPHIC OMITTED]
- ----------
(1) The respective percentages of distributions allocated to Saranac Energy
Company, the TPC Saranac partners and GE Capital are set forth in the
Saranac partnership agreement and described below.
PROJECT FINANCING DEBT
Saranac and the Clinton IDA financed the construction of the Saranac
project with commercial term loans made under the Saranac credit agreement. GE
Capital, which holds the largest percentage of the debt outstanding under the
Saranac credit agreement, is also a limited partner in Saranac. As of September
30, 1999, the aggregate principal amount outstanding under the Saranac credit
agreement was $183.1 million. Through swap arrangements, the interest rate on
all of the term loans outstanding under the Saranac credit agreement has been
fixed at a current annual rate of 8.185%, which will increase to 8.31% in
October 2001 and 8.56% in October 2005. In addition to the outstanding term
loans, the Saranac credit agreement provides for the issuance of up to $20.5
million in letters of credit for Coral Energy and up to $6.6 million for a
letter of credit to secure a debt service reserve fund to support the Saranac
project financing debt. The term loans outstanding under the Saranac credit
agreement mature on March 31, 2008 and are payable in 54 quarterly principal
installments which increase in annual aggregate amount from $6.14 million in
1998 to $34.38 million in 2007.
Collateral. Saranac is jointly and severally liable with the Clinton IDA
on the loans outstanding under the Saranac credit agreement, and the liability
of the Clinton IDA is limited to recourse to the Saranac project. Saranac's
obligations under the Saranac project financing documents are secured by liens
on substantially all of the real and personal property of Saranac.
Limitation on Distributions. Distributions to the Saranac partners may be
made monthly with excess cash flow from the Saranac project, to the extent
permitted by the Saranac partnership agreement, upon satisfaction of the
following conditions:
(1) no default or event of default has occurred under the Saranac project
financing documents;
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(2) all project accounts are fully funded to their required levels; and
(3) the debt service coverage ratio for the preceding three-month period
is at least 1.20 to 1.0.
If the debt service coverage ratio test described in clause (3) immediately
above is not satisfied for six consecutive quarters, all amounts otherwise
distributable to the Saranac partners for the next three months will be
retained for application to mandatory prepayment of amounts owing under the
Saranac project financing documents.
Additional Debt. Saranac is prohibited from incurring debt other than
under the Saranac project financing documents, except for:
(1) customary trade debt;
(2) debt not to exceed $750,000 incurred in accordance with the approved
Saranac operating budget;
(3) debt incurred to redeem the Saranac limited partnership interest of GE
Capital upon specified regulatory events; this debt must be repaid
only from amounts which would otherwise have been distributed to GE
Capital in respect of its Saranac limited partnership interest;
(4) intercompany debt between Saranac and North Country; and
(5) debt secured by (a) liens securing the purchase of property in an
aggregate principal amount not to exceed $250,000 and (b) liens in
favor of New York State Electric and Gas, Georgia-Pacific and the
Clinton County Development Corp. permitted under the Saranac project
financing documents.
PARTNERSHIP DISTRIBUTIONS
Each of the Saranac partners has an interest in cash distributions by
Saranac which changes when after-tax rates of return specified in the Saranac
partnership agreement are achieved by GE Capital and the TPC Saranac partners
on their contributions to Saranac. The cash distributions of Saranac are
divided into three levels:
o Level 1: distributions in fixed amounts payable during the first 15
years of operation of the Saranac project, which are applied first to
pay debt service and other amounts due under the Saranac project
financing documents and any refinancing loans, with the remainder paid
to GE Capital to enable it to achieve a base rate of return;
o Level 2: distributions of the Saranac available cash remaining after
payment of the level 1 distributions during the first 15 years of
operation of the Saranac project. During the first 15 years of
operation of the Saranac project, Saranac Energy will receive 63.51%
of the level 2 distributions until TPC Saranac partners achieve an
8.35% rate of return and, after this return is achieved, which we
expect to occur in 2000, Saranac Energy will receive 81.18% of the
level 2 distributions.
o Level 3: distributions after the first 15 years of operation of the
Saranac project. After the first 15 years of operation of the Saranac
project, Saranac Energy will receive 68% of the level 3 distributions
until GE Capital achieves a supplemental rate of return specified in
the Saranac partnership agreement and, thereafter, Saranac Energy will
receive 76% of the level 3 distributions.
Distributions which would otherwise be payable to Saranac Energy and the
TPC Saranac partners on a quarterly basis may be required to be retained in a
reserve account established under the Saranac project financing documents. If
the ratio of available cash from the Saranac project to the scheduled level 1
distributions is less than 1.40 to 1.0 for any quarter, all level 2
distributions payable to Saranac Energy will be retained in the reserve
account. If this situation continues for three consecutive quarters, the amount
on deposit in the reserve account will be distributed to GE Capital as an early
level 1 distribution. When the level 1 distribution ratio has been maintained
at 1.40 to 1.0
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or greater for three consecutive quarters, the amount on deposit in the reserve
account will be released to Saranac Energy. Amounts otherwise distributable to
Saranac Energy may also be retained in a reserve account if an event has
occurred which if not cured would give GE Capital the right to replace Saranac
Energy as the general partner of Saranac. These amounts will be paid to GE
Capital if the event is not cured.
SELECTED FINANCIAL INFORMATION
Saranac made distributions to Saranac Energy in 1995, 1996, 1997 and 1998
in the amounts of approximately $13.3 million, $21.7 million, $22.8 million and
$16.2 million, respectively.
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POWER RESOURCES PROJECT
The Power Resources project is a 200 megawatt natural gas-fired combined
cycle cogeneration facility located near Big Spring, Texas. The Power Resources
project is owned by Power Resources, Inc. and commenced commercial operation in
June 1988. Below is a chart illustrating the commercial structure of the Power
Resources project.
[GRAPHIC OMITTED]
SALE AND TRANSMISSION OF POWER
POWER RESOURCES POWER PURCHASE AGREEMENT
Power Resources sells capacity and energy to Texas Utilities under the
Power Resources power purchase agreement. The initial term of the Power
Resources power purchase agreement expires in September 2003. The contract
capacity under the Power Resources power purchase agreements is 200 megawatts.
Texas Utilities' long-term unsecured debt obligations were rated "Baa1" by
Moody's, "BBB" by S&P and BBB+ by Duff & Phelps as of January 1999.
Payments. The Power Resources power purchase agreement provides for
payments by Texas Utilities for capacity and energy produced by the Power
Resources project according to a fixed schedule set forth in the contract. The
capacity and energy rates for the remaining term of the Power Resources power
purchase agreement are as follows:
<TABLE>
<CAPTION>
CAPACITY ENERGY
YEAR ($/KILOWATT/MONTH) (CENTS/KILOWATT-HOUR)
- ---------------- -------------------- ----------------------
<S> <C> <C>
1999 ......... 16.24 3.17
2000 ......... 16.81 3.28
2001 ......... 17.40 3.40
2002 ......... 18.00 3.52
2003 ......... 18.63 3.64
</TABLE>
However, for any month in which the rolling 12-month average capacity
factor exceeds 72.5%, Power Resources is paid an energy payment for the billing
kilowatt-hour for the months which are in excess of the 72.5% annual capacity
factor at a rate based on 99% of Texas Utilities' average cost of gas and a
specified heat rate. There is no change in the capacity payment in this
circumstance.
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<PAGE>
Backdown. Texas Utilities has the right to request Power Resources to
backdown generation by up to 200,000 megawatt-hour per year. In addition.
subject to limitations specified in the Power Resources power purchase
agreement, Texas Utilities may request additional backdown. Over the last five
years, Texas Utilities has taken 300,000 megawatt-hour of backdown each year.
We believe that 300,000 megawatt-hour represents the upper limit on annual
backdown.
Texas Utilities Purchase Option. Texas Utilities has the option to
purchase the Power Resources project at the end of the term of the Power
Resources power purchase agreement. In addition, during the term of the Power
Resources power purchase agreement and for a period of one year following the
expiration of the agreement, Texas Utilities has a right of first refusal to
purchase the Power Resources project if Power Resources determines to lease,
sell or otherwise dispose of the Power Resources project. The purchase price
will be the agreed-upon appraised fair market value for the Power Resources
project.
Arbitration. Disputes regarding replacement of integral components of the
Power Resources project (including the generator stator, generator rotor, main
power transformer or steam turbine) and disputes concerning sales of the Power
Resources project assets in connection with Texas Utilities' option to purchase
or right of first refusal are subject to arbitration under the Texas General
Arbitration Act.
INTERCONNECTION
At Power Resources' expense, Texas Utilities modified an existing
switching station and existing transmission facilities and constructed new
transmission facilities in order to facilitate the signing of the Power
Resources power purchase agreement. Power Resources constructed an auxiliary
switchyard and substation to complete the interconnection. The Power
Resources-constructed facilities are required to interconnect with Texas
Utilities' facilities. The interconnection facilities are operated and
maintained by Texas Utilities for a minimal fee payable by Power Resources.
SALE OF THERMAL ENERGY
Power Resources has entered into a 15-year thermal energy purchase
agreement with Fina Oil and Chemical under which Power Resources agrees to
supply Fina with up to 150,000 pounds per hour of process thermal energy for
use in Fina's oil refinery, which is adjacent to the Power Resources project.
Fina returns any resulting thermal energy condensate to the Power Resources
project for re-use. The initial term of the agreement expires in September of
2003, but the agreement is subject to extension upon mutual consent by the
parties. As long as Power Resources meets its supply obligations under the
thermal energy purchase agreement, Fina is required to purchase at least the
minimum amount of thermal energy per year required to allow the Power Resources
project to maintain its qualifying facility status, even if the oil refinery is
closed or if Fina builds its own cogeneration facility. The thermal energy
purchase price is $2.48 per thousand pounds based on a base rate of $2.00
escalating at 2% annually from the commencement of delivery. If Fina closes the
refinery, the purchase price would be 60% of the contractual rate. We believe
that the refinery is critical to Fina's operations and is likely to continue
production through at least the end of the Power Resources power purchase
agreement term in 2003.
FUEL PROCUREMENT
NATURAL GAS SUPPLY
Under a fuel purchase agreement between Fina and Power Resources, Power
Resources is obligated to purchase, at $2.79 per MMbtu for 1999 escalating by
2% per year thereafter, an average of 3,600 million MMBtu per day of refinery
gas for use in the Power Resources project's combustion turbines. To meet its
additional gas requirements, Power Resources has entered into a gas purchase
agreement with CE Texas Gas, which expires on December 30, 2003. The
contractual rates under this gas purchase agreement are fixed at $2.98 per
MMBtu for 1998 and escalate by 3.0% per year thereafter, plus an annual
reservation fee of $580,842 which also escalates by 3.0% per year. Power
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<PAGE>
Resources pays a fuel transportation charge to CE Texas Gas of $0.075 per MMBtu
for each MMBtu delivered by CE Texas Gas up to an average of 25,000 MMBtu per
day, and $0.06 per MMBtu delivered which exceeds an average of 25,000 MMBtu per
day, calculated on a monthly basis. In order to meet its supply requirements to
Power Resources, CE Texas Gas entered into a gas purchase agreement with Louis
Dreyfus Natural Gas Corporation which expires on October 1, 2003. Under this
agreement, Dreyfus will make available, sell and deliver to CE Texas Gas on a
firm basis, and CE Texas Gas will purchase and receive from Dreyfus on a firm
basis, contracted amounts of gas, allocated among four pricing tiers,
sufficient to meet the operating requirements of the Power Resources project.
If Dreyfus fails to perform under the contract, Dreyfus must reimburse CE Texas
Gas for any additional costs which CE Texas Gas incurs in obtaining the
required natural gas. If CE Texas Gas fails to purchase the agreed amount of
natural gas, it must reimburse Dreyfus for any amount of natural gas that
Dreyfus is unable to resell in the spot market. The first tier of gas
deliveries are made according to a fixed price which is $2.23 per MMBtu in 1999
and which incrementally increases to $2.51 per MMBtu in 2003 for up to 31,200
MMBtu per day. The second tier quantities are set at the West Texas spot price
plus 5 cents per MMBtu for up to an additional 3,000 MMBtu per day. The third
tier of purchases is for up to an additional 15,000 MMBtu per day, and prices
for the third and fourth tiers are negotiated between Dreyfus and Power
Resources.
NATURAL GAS TRANSPORTATION
Under the terms of the Dreyfus gas purchase agreement, Dreyfus will
deliver gas into various interconnection points of the Westar Transmission
System. CE Texas Gas has entered into long-term transmission agreements with
Westar for the delivery of gas to the Power Resources project. Under these gas
transportation agreements, CE Texas Gas pays been $0.06 and $0.12 per MMBtu to
transport the gas, depending on the point of entry into the Westar pipeline
system. These agreements are effective until September 30, 2003.
WATER SUPPLY
In addition to the thermal energy condensate returned to the Power
Resources project by Fina under the thermal energy purchase agreement, the
Power Resources project receives up to 155 gallons of water per minute from the
Colorado Municipal Water District under an agreement which expires in September
2003 and up to 65 gallons of water per minute from Sid Richardson Carbon
Limited under an agreement which expires in April 2007. The rate paid by Power
Resources under the Colorado Municipal Water District agreement is the same
rate as that charged to the City of Big Spring, Texas for water supply, subject
to a minimum of $0.60 per thousand gallons. Power Resources pays a rate of
$1.08 (escalated at 3% annually) per thousand gallons under the Sid Richardson
Carbon Limited agreement, so long as the water provided satisfies agreed-upon
conductivity standards.
OPERATION AND MAINTENANCE SERVICES
Operation and maintenance services for the Power Resources project are
provided by Falcon Power Operating under an operation and maintenance agreement
which expires in January 2004. Falcon Power Operating is obligated to provide
all services, personnel, insurance and materials necessary to operate and
maintain the Power Resources project in accordance with prudent operating
practices and contractual requirements. Power Resources is obligated to
reimburse Falcon Power Operating on a monthly basis for operating costs and pay
Falcon Power Operating an operator fee. The fee is subject to adjustment for
operating bonuses or liquidated damages based on the Power Resources project's
capacity factor. The operator fee is $1.14 million annually as of 1998, which
fee is comprised of a management fee of $0.24 million per year (with no
escalation) and an operating fee of $0.9 million in 1998, escalating at 3.5%
per year.
USE OF PROJECT SITE
Power Resources leases the real property on which the Power Resources
project is located from Fina for a nominal rent under a lease agreement which
expires on November 21, 2004. The term of
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<PAGE>
the lease may be extended for an additional 15-year period at Power Resources'
option and will be automatically extended for an additional period if Power
Resources and Fina elect to extend the term of the thermal energy purchase
agreement. Power Resources has a right of first refusal under the lease
agreement if Fina receives an offer to purchase all or any portion of the
leased property. Except in limited circumstances, either party may terminate
the lease agreement upon an event of default by the other party under the
thermal energy purchase agreement. In addition, Power Resources owns the fee
title to a number of parcels of land adjacent to the property leased from Fina
on which are located related support facilities. Power Resources has the
benefit of non-exclusive easements over property adjacent to the Power
Resources project under an easement agreement with Fina. These easements
include the right of pedestrian access, railway access, storm water drainage,
waterline services and wastewater connection to the existing salt water
disposal well.
Power Resources also pays an annual fee of $39,753 to the City of Big
Spring, Texas in lieu of property taxes because of an agreement under which the
Power Resources project and the Fina refinery are deemed to be located outside
of the City's jurisdiction. This agreement expires in December 2003.
PROJECT COMPANY OWNERSHIP
Falcon Seaboard Oil owns all of the capital stock of Power Resources and
is wholly owned by Falcon Seaboard Resources. Falcon Seaboard Resources is a
wholly-owned subsidiary of ours. Below is a chart illustrating the ownership
structure for the Power Resources project.
[GRAPHIC OMITTED]
PROJECT FINANCING DEBT
Power Resources financed the construction of the Power Resources project
with commercial loans made by a consortium of banks under the Power Resources
credit agreement. As of September 30, 1999, the aggregate principal amount of
debt outstanding under the Power Resources credit agreement was $79.8 million.
Through swap arrangements, the interest rate on two-thirds of the loans has
been fixed at a current annual rate of 10.625% and the interest rate on the
remaining one-third of the loans has been fixed at 10.385%. After 2001, all of
the loans will bear interest at a fixed rate of 10.635%.
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<PAGE>
Collateral. Power Resources' obligations under its project financing
documents are secured by the following collateral:
o an assignment of all revenues received by Power Resources from the
operation of the Power Resources project;
o a lien on substantially all of the real and personal property of Power
Resources; and
o a pledge of the capital stock of Power Resources.
Limitation on Distributions. Power Resources may make distributions to
Falcon Seaboard Oil with excess cash flow from the Power Resources project upon
satisfaction of the following conditions:
(1) all project accounts are fully funded to their required levels;
(2) no default or event of default has occurred and is continuing under
the Power Resources project financing documents; and
(3) the historical quarterly debt service coverage ratio is at least 1.20
to 1.0. However, even if the historical quarterly debt service
coverage ratio is less than 1.20 to 1.0:
o if the historical debt service coverage ratio is at least 1.17 to 1.0
but less than 1.20 to 1.0, distributions may be made with 50% of the
excess cash flow from the Power Resources project;
o if the historical debt service coverage ratio is at least 1.15 to 1.0
but less than 1.17 to 1.0, distributions may be made with 40% of the
excess cash flow from the Power Resources project;
o if the historical debt service coverage ratio is at least 1.13 to 1.0
but less than 1.15 to 1.0, distributions may be made with 30% of the
excess cash flow from the Power Resources project;
o if the historical debt service coverage ratio is at least 1.1 to 1.0
but less than 1.13 to 1.0, distributions may be made with 20% of the
excess cash flow from the Power Resources project; and
o if the historical debt service coverage ratio is at least 1.1 to 1.0,
distributions may be made with 10% of the excess cash flow from the
Power Resources project.
SELECTED FINANCIAL INFORMATION
Power Resources made distributions to Falcon Seaboard Oil in 1995 in the
amount of approximately $5.6 million, in 1996 in the amount of approximately
$300,000 and in 1997 in the amount of approximately $1.5 million.
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<PAGE>
YUMA PROJECT
The Yuma project is a 50 megawatt natural gas-fired combined cycle
cogeneration facility located in Yuma, Arizona. The Yuma project is owned by
Yuma Cogeneration and commenced commercial operation in May 1994. Below is a
chart illustrating the commercial structure of the Yuma project.
[GRAPHIC OMITTED]
SALE AND TRANSMISSION OF POWER
YUMA POWER PURCHASE AGREEMENT
Yuma Cogeneration sells capacity and energy to San Diego Gas & Electric
under the Yuma power purchase agreement. The Yuma power purchase agreement is a
standard offer no. 2 contract and expires in May 2024. The contract capacity
under the Yuma power purchase agreement is 50 megawatts. San Diego Gas &
Electric's long-term unsecured debt obligations were rated "A2" by Moody's,
"A+" by S&P and "A+" by Duff & Phelps as of January 1999.
Payments. Under the Yuma power purchase agreement, Yuma Cogeneration sells
power to San Diego Gas & Electric at a price based on the cost that San Diego
Gas & Electric avoids by purchasing energy from the Yuma project instead of
obtaining the energy from other sources. Yuma Cogeneration may deliver up to
56.5 megawatts of energy to San Diego Gas & Electric at these rates. The
average price of energy under the Yuma power purchase agreement was 3.0 cents
per kilowatt-hour in 1998. Payments for capacity are fixed at $140 per
kilowatt-year from 1999 to the end of the Yuma power purchase agreement term.
Yuma Cogeneration is eligible for capacity bonus payments of up to
approximately 18% of the contract capacity if it maintains availability in
excess of 85% during the on-peak hours of the peak months (excluding
curtailment). We expect bonus capacity payments to be $22 per kilowatt-year.
Curtailment. San Diego Gas & Electric is not required to accept or
purchase energy from the Yuma project for a maximum of 900 flexible hours and
400 block hours (in one 400 hour block or two 200 hour blocks) through year
nine, 1,400 flexible hours and 400 block hours through year 15, and 2,200
flexible hours and 400 block hours through year 30. During curtailments, Yuma
Cogeneration is free to sell power into the open market.
TRANSMISSION AND INTERCONNECTION
Power from the Yuma project is delivered over transmission lines
constructed and owned by Arizona Public Service Company to the Southwest Power
Link, a high voltage 500 kilovolt bulk
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<PAGE>
transmission line in which San Diego Gas & Electric owns a majority interest.
An agreement for interconnection, a firm transmission service agreement and an
interruptible transmission agreement have been executed between Arizona Public
Service Company and Yuma Cogeneration. Delivery fees are $1.52 per
kilowatt-month (no escalation) plus $50,000 per year through the term of the
contracts. Yuma Cogeneration pays a transmission services charge of $0.002082
per kilowatt-hour (no escalation) under the interruptible transmission
agreement. Arizona Public Service Company reserves 50.85 megawatts of its
transmission capacity for power from the Yuma project. Both the firm and
interruptible transmission agreements expire on December 31, 2024.
SALE OF THERMAL ENERGY
Yuma Cogeneration has entered into a thermal energy sales agreement with
Queen Carpet, Inc. Queen Carpet was recently acquired by Shaw Industries, Inc.
of Dalton, Georgia, the largest tufted carpet manufacturer in the world. Queen
Carpet has the right to terminate the agreement upon one year's notice if a
change in its technology eliminates its need for thermal energy, and in any
case to terminate the agreement at any time upon three years notice. Otherwise,
the agreement expires on May 1, 2024. Queen Carpet is obligated to take a
minimum annual amount of 126,900 MMBtu per year, which is sufficient to permit
the Yuma project to meet its thermal energy requirements for qualifying
facility status. Yuma Cogeneration delivers thermal energy for use in Queen
Carpet's manufacturing process as well as for absorption chillers. The price of
thermal energy delivered for use in air conditioning is equal to 75% of Queen
Carpet's net avoided energy cost of producing chilled water. The price of
thermal energy used for textile manufacturing is 75% of the price of natural
gas purchased from the nearest available gas utility by a comparable industrial
customer. For 1998, the total thermal energy revenues were approximately
$718,000.
FUEL PROCUREMENT
Under the terms of the gas purchase agreement between Yuma Cogeneration
and Southwest Gas Corporation, Yuma Cogeneration may direct Southwest Gas to
purchase gas on its behalf and transport it to the Yuma project under the CG-30
tariff. This agreement allows Yuma Cogeneration to nominate gas from any one of
several surrounding supply basins and to receive the gas at the price of the
relevant index without a basis spread. The CG-30 tariff agreement can be
terminated by either party after June 26, 2002. If terminated, Yuma
Cogeneration will return to the CT-I transportation-only tariff, under which
Yuma Cogeneration purchases gas in the open market on its own behalf and
Southwest Gas arranges transportation. Under the CG-30 arrangement, Yuma
Cogeneration pays a $15,000 per month service charge to Southwest Gas. The
monthly service charge under the CT-I arrangement is $5,725.
OPERATION AND MAINTENANCE SERVICES
In connection with the offering of the old securities, Yuma Cogeneration
operating personnel who had previously been employed by MidAmerican were
assigned to Falcon Power Operating, which entered into a long-term operation
and maintenance agreement with Yuma Cogeneration to provide operation and
maintenance services for the Yuma project on a cost of service basis.
OWNERSHIP OF PROJECT SITE
Yuma Cogeneration owns the fee title to the land on which the Yuma project
is located and has the benefit of associated easement rights for irrigation
purposes over adjacent land.
PROJECT COMPANY OWNERSHIP
Yuma Cogeneration is 50% owned by each of California Energy Development
and California Energy Yuma Corporation. We own all of the outstanding capital
stock of California Energy Development and California Energy Development owns
all of the capital stock of California Energy Yuma. Below is a chart
illustrating the ownership structure for the Yuma project.
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<PAGE>
[GRAPHIC OMITTED]
YUMA INDEBTEDNESS
The Yuma project was financed in part by a loan from MidAmerican, which
received a note from Yuma Cogeneration. A portion of the net proceeds of the
initial offering were used to repay MidAmerican for the outstanding principal
and accrued interest on the Yuma Cogeneration note of approximately $47.7
million and $1.3 million. Yuma Cogeneration does not now have any outstanding
indebtedness for borrowed money.
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<PAGE>
OTHER SOURCES OF AVAILABLE CASH FLOW
GAS SUPPLY ARRANGEMENTS
CE Texas Gas sells natural gas to Power Resources under its natural gas
purchase agreement with Power Resources and obtains the necessary gas supply
from Dreyfus under its gas purchase agreement with Dreyfus. The term of each of
these contracts expires in 2003. Dividends paid by CE Texas Gas to its sole
owner, CE Texas Energy, as a result of profits earned in connection with these
gas supply arrangements are included in CE Texas Energy's available cash flow.
In 1996 CE Texas Gas made distributions to CE Texas Energy of approximately
$4.2 million. In 1997 CE Texas Gas made distributions to CE Texas Energy of
approximately $4.5 million. In 1998 CE Texas Gas made distributions to CE Texas
Energy of approximately $8.8 million.
MAMMOTH ROYALTY
In addition to its ownership interests in the Imperial Valley projects,
Magma has rights to royalties from the 10 megawatt and 12 megawatt geothermal
power generating facilities owned by Mammoth-Pacific, L.P. and located in Mono
County, California. The amounts of the royalties are 12.5% and 12% of gross
proceeds, respectively. In 1996 Magma received total royalties from these
projects of approximately $1,939,000. In 1997 Magma received total royalties
from these projects of approximately $2,153,000. In 1998 Magma received total
royalties from these projects of approximately $2,284,000.
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DESCRIPTION OF THE SECURITIES
The following is a description of important provisions of the securities.
The following information does not purport to be a complete description of the
securities and is subject to, and qualified in its entirety by, reference to
the securities and the indenture. Unless otherwise specified, the following
description applies to all of the securities.
GENERAL
The old securities were, and the new securities will be, direct senior
obligations of ours, issued under the indenture for the securities and secured
by the collateral. The old securities were issued in fully registered form and
in denominations of $100,000 and any integral multiple of $1,000 in excess of
$100,000.
The indenture provides for the issuance of the securities and other series
of senior notes or securities as from time to time may be authorized by us,
subject to the limitations set forth in the indenture.
PRINCIPAL AMOUNT, INTEREST RATE AND FINAL MATURITY DATE
The old securities were and the new securities will be issued in a single
series in the aggregate principal amount of $400 million, bearing interest from
their date of issuance at 7.416% per annum and finally maturing on December 15,
2018.
PAYMENT OF INTEREST AND PRINCIPAL
INTEREST
Interest on the securities is payable semiannually in arrears on each June
15 and December 15 to the registered holders at the close of business on the
preceding June 1 or December 1. Interest will be calculated on the basis of a
360-day year, consisting of twelve 30-day months.
PRINCIPAL
The principal of the securities will be payable in semiannual
installments, commencing June 15, 2000, as follows:
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL AMOUNT
PAYMENT DATE PAYABLE
- --------------------------------- -----------------
<S> <C>
December 15, 1999 ......... 0.000%
June 15, 2000 ............. 1.300%
December 15, 2000 ......... 1.300%
June 15, 2001 ............. 1.575%
December 15, 2001 ......... 1.575%
June 15, 2002 ............. 2.575%
December 15, 2002 ......... 2.575%
June 15, 2003 ............. 2.250%
December 15, 2003 ......... 2.250%
June 15, 2004 ............. 1.825%
December 15, 2004 ......... 1.825%
June 15, 2005 ............. 1.850%
December 15, 2005 ......... 1.850%
June 15, 2006 ............. 2.400%
December 15, 2006 ......... 2.400%
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
PERCENTAGE OF
PRINCIPAL AMOUNT
PAYMENT DATE PAYABLE
- --------------------------------- -----------------
<S> <C>
June 15, 2007 ............. 2.250%
December 15, 2007 ......... 2.250%
June 15, 2008 ............. 3.525%
December 15, 2008 ......... 3.525%
June 15, 2009 ............. 3.075%
December 15, 2009 ......... 3.075%
June 15, 2010 ............. 1.775%
December 15, 2010 ......... 1.775%
June 15, 2011 ............. 1.900%
December 15, 2011 ......... 1.900%
June 15, 2012 ............. 2.560%
December 15, 2012 ......... 2.560%
June 15, 2013 ............. 2.550%
December 15, 2013 ......... 2.550%
June 15, 2014 ............. 3.225%
December 15, 2014 ......... 3.225%
June 15, 2015 ............. 3.380%
December 15, 2015 ......... 3.380%
June 15, 2016 ............. 3.660%
December 15, 2016 ......... 3.660%
June 15, 2017 ............. 3.780%
December 15, 2017 ......... 3.780%
June 15, 2018 ............. 4.545%
December 15, 2018 ......... 4.545%
</TABLE>
REDEMPTION OF THE SECURITIES
REDEMPTION GENERALLY
We are permitted to redeem the securities prior to the maturity date
therefor upon terms and subject to conditions contained in the indenture. We
are obligated to redeem all or a portion of the securities prior to their
maturity date, in accordance with terms and subject to conditions contained in
the indenture.
NOTICE TO TRUSTEE
Our election or requirement to redeem any securities will be evidenced by
our written request. If we elect to redeem all or a portion of the securities
in accordance with terms set forth in the indenture, we will deliver to the
trustee, at least 30 days prior to the date by which notice of redemption is
required to be given to the holders of the securities, or a shorter period as
may be agreed by the trustee, a written request specifying the date on which
the redemption will occur and the principal amount of securities to be
redeemed. If we are required to redeem all or a portion of the securities in
accordance with the terms of the indenture, we will deliver to the trustee,
immediately upon the occurrence of the event resulting in the obligation to
redeem, a written request specifying the principal amount of securities to be
redeemed, the price at which the securities will be redeemed, the applicable
yield maintenance premium, if any, the paragraph of the indenture under which
the securities are being redeemed and the redemption date, which redemption
date will be within 90 days of the occurrence of the event resulting in the
obligation to redeem.
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NOTICE TO HOLDERS OF THE SECURITIES
Notice of any optional or mandatory redemption must be given to the
holders of securities at least 30 but not more than 60 days prior to the
applicable redemption date. Each notice of redemption is required to set forth,
among other information:
o the redemption date;
o the redemption price and any applicable yield maintenance premium;
o if less than all outstanding securities are to be redeemed, the
identification of the particular securities to be redeemed and the
aggregate principal amount of securities to be redeemed;
o in the case of securities to be redeemed in part, the principal amount
of those securities to be redeemed and a statement to the effect that
after the redemption date, upon surrender of those securities, new
securities in the aggregate principal amount equal to the unredeemed
portion will be issued;
o the place where securities subject to redemption are to be surrendered
for payment of the redemption price; and
o a statement to the effect that the availability in a special purpose
trust fund established under the indenture for redemption of the
securities on the redemption date of an amount of immediately available
funds sufficient to pay the redemption price and any applicable yield
maintenance premium in full is a condition precedent to the redemption
described in the notice.
SECURITIES PAYABLE ON REDEMPTION DATE
The securities, or portions of the securities, to be redeemed will become
due and payable on the redemption date, and from and after the redemption date
those securities or the portions will cease to bear interest. Upon surrender of
any security for redemption, we will pay and redeem that security or the
portion being redeemed at the redemption price plus any applicable yield
maintenance premium. However, any payment of interest on any security the
payment date of which is on or prior to the redemption date will be payable to
the holder of the securities registered as such at the close of business on the
relevant record date according to the terms of the indenture and the security.
If less than all the securities are to be redeemed, the trustee will redeem the
securities on a pro rata basis among the outstanding securities not previously
called for redemption in whole.
OPTIONAL REDEMPTION
The securities will be subject to our optional redemption, in whole or in
part, at any time on any business day, at a price equal to the redemption price
plus the yield maintenance premium.
The yield maintenance premium is calculated as follows:
o The yield maintenance premium for a security is equal to the discounted
present value calculated for the security less the unpaid principal
amount of the security.
o The discounted present value of a security is equal to the discounted
present value of all principal and interest payments scheduled to become
due on the security after the date of redemption, calculated using a
discount rate equal to the sum of:
(1) the yield to maturity on the United States Treasury security having an
average life equal to the remaining average life of the security and
trading in the secondary market at the price closest to par; plus
(2) 50 basis points.
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o If there is no United States treasury security having an average life
equal to the remaining average life of the security, the discount rate
will be calculated using a yield to maturity interpolated or
extrapolated on a straight-line basis, rounding to the nearest month,
if necessary, from the yields to maturity for two United States
treasury securities having average lives most closely corresponding to
the remaining average life of the security and trading in the
secondary market at the price closest to par.
o The yield maintenance premium will never be less than zero.
MANDATORY REDEMPTION--AT PAR
EVENT OF LOSS
If (a) any of our subsidiaries that has assigned its available cash flow
to secure our obligation to make payments on the securities receives available
cash flow in excess of $15 million from one or more distributions of insurance
proceeds by a project company in connection with the damage or destruction of
all or a portion of its project, then (b) the available cash flow will be used
to redeem securities at a price equal to the principal amount of the securities
being redeemed plus accrued interest.
EXPROPRIATION EVENT
If (a) any assigning subsidiary receives available cash flow in excess of
$15 million from one or more distributions of expropriation proceeds by a
project company in connection with a governmental authority's compulsory taking
or transfer or the threat of a governmental authority's compulsory taking or
transfer of its project, then (b) the available cash flow will be used to
redeem securities at a price equal to the principal amount of the securities
being redeemed plus accrued interest.
TITLE EVENT
If (a) any assigning subsidiary receives available cash flow in excess of
$15 million from one or more distributions of title insurance proceeds by a
project company in connection with a defect in the title to the land on which
the assigning subsidiary's project is located, then (b) the available cash flow
will be used to redeem securities at a price equal to the principal amount of
the securities being redeemed plus accrued interest.
PERMITTED POWER CONTRACT BUY-OUT
If (a) any assigning subsidiary receives available cash flow in excess of
$15 million from one or more distributions of buy-out proceeds by a project
company in connection with one or more permitted power contract buy-outs
permitted under the project financing documents, then (b) the available cash
flow will be used to redeem the securities. The redemption price will be equal
to the lesser of:
(1) 100% of the available cash flow; and
(2) the amount which will cause each rating agency to confirm that, after
giving effect to the redemption, the rating assigned to the
securities by the rating agency will be equal to or better than the
higher of:
o the existing rating assigned to the securities by the rating agency;
and
o the initial rating assigned to the securities by the rating agency.
MANDATORY REDEMPTION--WITH YIELD MAINTENANCE PREMIUM
PROJECT FINANCING OR PROJECT DEBT REFINANCING
If (a) any assigning subsidiary receives available cash flow in excess of
$15 million from one or more distributions of refinancing proceeds by a project
company in connection with one or more
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project financings or project debt refinancings with respect to the assigning
subsidiary's project company, then (b) the available cash flow will be used to
redeem the securities. The redemption price will be equal to the lesser of the
following plus the yield maintenance premium:
(1) 100% of the available cash flow; and
(2) the amount which will cause each rating agency to confirm that, after
giving effect to the redemption, the rating assigned to the
securities by the rating agency will be equal to or better than the
higher of:
o the existing rating assigned to the securities by the rating agency;
and
o the initial rating assigned to the securities by the rating agency.
ASSET SALE
If (a) any assigning subsidiary receives available cash flow in excess of
$15 million from one or more distributions of asset sale proceeds by a project
company in connection with one or more asset sales with respect to its project,
then (b) available cash flow will be used to redeem the securities. The
redemption price will be equal to the lesser of the following plus the yield
maintenance premium:
(1) 100% of the available cash flow; and
(2) the amount which will cause each rating agency to confirm that, after
giving effect to the redemption, the rating assigned to the
securities by the rating agency will be equal to or better than the
higher of:
o the existing rating assigned to the securities by the rating agency;
and
o the initial rating assigned to the securities by the rating agency.
SALE OF EQUITY INTERESTS
If:
o we sell all or any portion of our interest in any assigning
subsidiary, other than a transfer permitted under the financing
documents, and receive proceeds in excess of $15 million in
connection with the sale; or
o any assigning subsidiary sells all or any portion of its interest in
any project company, other than a transfer permitted under the
financing documents, and receives proceeds in excess of $15 million
in connection with the sale,
then the proceeds of the sale will be used to redeem the securities. The
redemption price will be equal to the lesser of the following plus the yield
maintenance premium
o 100% of the proceeds; and
o the amount which will cause each rating agency to confirm that, after
giving effect to the redemption, the rating assigned to the
securities by the rating agency will be equal to or better than the
higher of:
(1) the existing rating assigned to the securities by the rating agency;
or
(2) the initial rating assigned to the securities by the rating agency.
REDEMPTION DATE
The redemption date for any redemption will be any date we select during
the 90-day period following the date on which the event requiring the
redemption occurred.
RATINGS
Moody's, S&P and Duff & Phelps have assigned the securities ratings of
"Baa3", "BBB-" and "BBB", respectively. Each rating reflects only the view of
the applicable rating agency at the time the
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rating was issued, and any explanation of the significance of a rating may be
obtained only from the rating agency. There is no assurance that any rating
will remain in effect for any given period of time or that any rating will not
be lowered, suspended or withdrawn entirely by the applicable rating agency,
if, in the rating agency's judgment, circumstances so warrant. Any lowering,
suspension or withdrawal by any rating agency may have an adverse effect on the
market price or marketability of the securities.
FORM; TRANSFER AND EXCHANGE; BOOK-ENTRY SYSTEM
FORM OF SECURITIES
We will issue the new securities (except for those sold to institutional
accredited investors) initially in the form of a single global bond or, if
required, multiple global bonds. We refer to this single global bond or
multiple global bonds as the global security. We will issue the new securities
in registered form.
We will issue the global security initially to The Depository Trust
Company, referred to in this section as DTC. The global security will be
registered in the name of Cede & Co., which is the nominee of DTC. The trustee
will act as custodian of the global security for DTC or appoint a
sub-custodian. Because Cede & Co. will be the holder of record of the global
security, each person owning a beneficial interest in the global security must
rely upon the procedures of the institutions having accounts with DTC to
exercise or be entitled to any of the rights of holder.
New securities issued to institutional accredited investors will be issued
in definitive form. Upon the transfer of a security in definitive form, the
security will, unless the global security has previously been exchanged for
securities in definitive form, be exchanged for an interest in the global
security representing the principal amount of securities being transferred.
PAYMENTS OF PRINCIPAL AND INTEREST
We will make payments of principal of and interest on the securities
represented by the global security through the Trustee to DTC or its nominee.
None of us, the trustee, any paying agents or the registrar will have any
responsibility or liability for any aspect of the records relating to, or
payments made on account of, beneficial ownership interests in the securities
held by Cede & Co., as nominee for DTC, or Euroclear, or for maintaining,
supervising or reviewing any records relating to the beneficial ownership
interests.
Because of time zone differences, the securities account of a Euroclear
participant purchasing an interest in the global security from a DTC
participant will be credited during the securities settlement processing day
(which must be a business day for Euroclear) immediately following the DTC
settlement date. Credit in interests in the global security settled during the
processing day will be reported to the relevant Euroclear participant on that
day. Cash received in Euroclear as a result of sales of interests in the global
security by or through a Euroclear participant to a DTC participant will be
received with value on the DTC settlement date but will be available in the
relevant Euroclear cash account only as of the business day following
settlement in DTC.
EXCHANGING INTERESTS IN THE GLOBAL SECURITY FOR DEFINITIVE SECURITIES
Any person having a beneficial interest in the securities evidenced by the
global security may, upon request, exchange its interest in the global security
for a definitive security. Upon receipt by the trustee of written or electronic
instructions from DTC or its nominee on behalf of any person having a
beneficial interest in the securities evidenced by the global security and upon
receipt by the trustee of a written order of that person containing
registration instructions: (1) the trustee will cause, in accordance with the
standing instructions and procedures existing between it and DTC, the aggregate
principal amount of the global security to be reduced; and (2) following the
reduction, we will execute and the trustee will authenticate and deliver to the
beneficial owner or the transferee, as the case may be, a definitive security.
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In addition, the securities will be issued as definitive securities to
holders or their nominees, rather than to Cede & Co. as nominee for DTC, if:
o We advise the Trustee in writing that DTC is no longer willing or able
to discharge properly its responsibilities as depositary with respect to
the securities and we are unable to locate a qualified successor;
o We, at our option, elect to terminate the book-entry system through DTC
with respect to the securities; or
o after the occurrence of an event of default under the indenture,
beneficial owners holding interests representing an aggregate principal
amount of securities of not less than 51% of the securities represented
by the global security advise the trustee through DTC in writing that the
continuation of a book-entry system through DTC (or a successor) with
respect to the securities is no longer in the beneficial owners' best
interest.
Upon the occurrence of any event described in the immediately preceding
paragraph, the trustee will, upon written notice and receipt of a list of all
persons who hold a beneficial interest in the global security from DTC, be
required to notify, at our expense, all persons who hold a beneficial interest
in the global security through DTC participants or indirect participants
through DTC participants of the issuance of definitive securities. Upon
surrender by the trustee of the global security and receipt from DTC of
instructions for re-registration, we will execute and the Trustee will
authenticate and deliver the definitive securities.
TRANSFER AND EXCHANGE OF SECURITIES
Subject to the terms of the Indenture, the securities may be surrendered
for registration of transfer or exchange for securities of the same series, of
authorized denomination, and of like tenor, maturity and principal amount at
the corporate trust office of the Trustee. The security registrar is not
required to do the following:
o issue or register the transfer of or exchange any securities of any
series during a period:
o beginning at the opening of business 15 days before the day of
the mailing of a notice of redemption of the securities of that
series selected for redemption and ending at the close of
business on the day of the mailing, or
o beginning on the record date for the stated maturity of any
installment of principal of or payment of interest on the
securities of that series and ending on the stated maturity of
the installment; or
o issue or register the transfer or exchange of any securities selected
for redemption in whole or in part, except the unredeemed portion of
any securities selected for redemption in part. No service charge
will be required of any holder participating in any transfer or
exchange of the securities. However, payment may be required of any
tax or other governmental charges imposed in connection with the
transfer or exchange.
DTC'S BOOK-ENTRY SYSTEM
Securities represented by the global security will be held in book-entry
form in DTC. DTC has advised us that it is:
o a limited purpose trust company organized under the laws of the State
of New York;
o a member of the United States Federal Reserve System;
o a clearing corporation within the meaning of the New York Uniform
Commercial Code; and
o a clearing agency registered under Section 17A of the Exchange Act.
DTC was created to hold securities for its participants and to facilitate
the clearance and settlement of securities transactions between DTC
participants through electronic book-entries,
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thereby eliminating the need for physical movement of certificates. DTC
participants include securities brokers and dealers, banks, trust companies and
clearing corporations. Indirect access to the DTC system also is available to
others, such as banks, brokers and dealers and trust companies that clear
through or maintain a custodial relationship with a DTC participant, either
directly or indirectly.
Under the rules, regulations and procedures creating and affecting DTC and
its operations, DTC is required to make book-entry transfers of securities held
by it among DTC participants on whose behalf it acts and to receive and
transmit distributions of principal, premium and interest on the securities.
DTC participants and indirect participants with which beneficial owners of
securities held with DTC have accounts similarly are required to make
book-entry transfers and receive and transmit payments of principal and
interest on behalf of the beneficial owners. Accordingly, although beneficial
owners who hold securities through DTC participants or indirect participants
will not possess the securities, DTC's rules, by virtue of the requirements
described above, provide a mechanism by which DTC participants will receive
payments and will be able to transfer their interests in the securities.
Because DTC may act only on behalf of DTC participants, who in turn act on
behalf of indirect participants, any holder of securities through DTC desiring
to pledge its securities to persons or entities that do not participate in DTC,
or otherwise take actions with respect to its securities, will be required to
withdraw its securities from DTC as described above.
DTC has advised us as follows:
o that it will take any action permitted to be taken by a holder only at
the direction of one or more DTC participants to whose accounts with DTC
the holder's securities are credited;
o that it will take these actions with respect to any percentage of the
beneficial interests of holders who hold securities through DTC
participants or indirect participants only at the direction of and on
behalf of DTC participants whose account holders include undivided
interests that satisfy the percentage; and
o that it may take conflicting actions with respect to other undivided
interests to the extent that these actions are taken on behalf of DTC
participants whose account holders include the undivided interests.
NATURE OF RECOURSE ON THE SECURITIES
Our obligation to make payments of principal of, premium (if any) and
interest on the securities will be an obligation solely of ours, secured by the
collateral. Neither MidAmerican nor El Paso Energy, nor any affiliate,
shareholder, member, officer, director or employee of ours or of MidAmerican or
El Paso Energy will guarantee the payment of the securities or has any
obligation with respect to the securities (other than the assignment by the
assigning subsidiaries of their available cash flows to secure our obligation
to make payments on the securities).
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SUMMARY DESCRIPTION OF THE PRINCIPAL FINANCING DOCUMENTS
The following descriptions of the material provisions of the depositary
agreement, the indenture, the debt service reserve letter of credit
reimbursement agreement and the security documents are summaries and do not
describe all of the terms of the agreements. The material financing documents
have been filed as exhibits to the registration statement of which this
prospectus is a part.
OVERVIEW OF THE PRINCIPAL FINANCING DOCUMENTS
The principal financing documents that we entered into in connection with
the issuance and sale of the old securities, and the primary purposes of these
documents, are as follows:
o Indenture: We entered into the indenture with the trustee, as
representative of the holders of the securities. The indenture
includes, among other things:
(1) procedures for the issuance of the securities and additional
securities and their authentication by the trustee;
(2) provisions which permit, or require, us to redeem securities before
their maturity date;
(3) affirmative covenants which require us to take actions while any
securities are outstanding;
(4) negative covenants which restrict our activities while any securities
are outstanding; and
(5) events of default which permit the holders of the securities to
exercise remedies against us and the collateral.
o Depository Agreement: We entered into the depositary agreement with
the assigning subsidiaries, the collateral agent and the depositary
bank. The depositary agreement sets forth requirements for the
deposit of available cash flow into depositary accounts established
by us and the withdrawal of monies from these accounts to pay
operating and administrative costs and debt service. The depositary
agreement also includes the conditions that we must satisfy in order
to receive distributions from the depositary accounts.
o Debt Service Reserve Letter of Credit and Reimbursement Agreement:
The depositary agreement requires us to fund the debt service reserve
account up to the required balance. We can fulfill this requirement
by depositing cash in the debt service reserve account and/or
providing a letter of credit for the account. The debt service
reserve letter of credit and reimbursement agreement provides for the
issuance of a letter of credit for the debt service reserve account
and sets forth the circumstances in which the beneficiary of the
letter of credit may make drawings on the letter of credit.
o Security Documents: The security documents provide for the collateral
agent's security interest in the collateral. We granted a security
interest in all of our personal property under the CE Generation
security agreement. The designated portfolio companies granted a
security interest in their available cash flow under the subsidiary
security agreement. We, Magma and intermediate holding companies
pledged the equity interests in some of our subsidiaries under the
pledge agreements.
o Intercreditor Agreement: We entered into the intercreditor agreement
with the assigning subsidiaries, the trustee, the collateral agent
and the depositary bank. The collateral agent obtains its authority
to act on behalf of the secured parties under the intercreditor
agreement. The intercreditor agreement also provides for the sharing
of collateral among the secured parties and the procedures for voting
by the secured parties on the exercise of remedies.
DEPOSITARY AGREEMENT
GENERAL
The collateral agent, acting on behalf of the trustee, the holders of the
securities and the other secured parties, has entered into a depositary
agreement with us and the assigning subsidiaries, and
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has appointed the depositary bank. Under the depositary agreement, we have
established accounts with the depositary bank and granted a security interest
in these accounts to the collateral agent for the benefit of the secured
parties. The depositary agreement sets forth, among other things:
o the terms upon which available cash flow in the depositary accounts is
disbursed to pay operating and administrative costs and payments of
principal of, premium (if any), interest on and other amounts due on the
securities,
o the conditions which must be satisfied prior to making distributions to
us,
o the mechanism for receipt and disbursement of available cash flow
representing loss proceeds, expropriation proceeds, title proceeds,
buy-out proceeds, refinancing proceeds or asset sale proceeds and
proceeds from the sale of our interest in a assigning subsidiary or the
sale by a assigning subsidiary of its interest in a project company, and
o the terms upon which monies on deposit in the accounts may be invested
in permitted investments.
When used in this prospectus, the term permitted investments means
investments in securities that are:
o direct obligations of the United States or any agency of the United
States;
o obligations fully guaranteed by the United States or any agency of the
United States;
o certificates of deposit or bankers acceptances issued by commercial
banks organized under the laws of the United States or of any political
subdivision of the United States or under the laws of Canada, Japan,
Switzerland or any country that is a member of the European Economic
Community having a combined capital and surplus of at least $250 million
and having long-term unsecured debt securities then rated "A" or better
by S&P or "A2" or better by Moody's. However, at the time of investment
not more than $25 million may be invested in certificates of deposit from
any one bank;
o repurchase obligations with a term of not more than seven days for
underlying securities of the types described in the preceding paragraph;
o open market commercial paper of any corporation incorporated or doing
business under the laws of the United States or of any political
subdivision, other than MidAmerican or any of its affiliates, of the
United States having a rating of at least "A-1" from S&P and "P-1" from
Moody's. However, at the time of investment not more than $25 million may
be invested in commercial paper from any one company;
o auction rate securities or money market preferred stock, other than
securities issued by MidAmerican or any of its affiliates, having one or
the two highest ratings obtainable from either S&P or Moody's; or
o investments in money market funds or money market mutual funds sponsored
by any securities broker dealer of recognized national standing having an
investment policy that requires substantially all the invested assets of
the fund to be invested in investments descried in any one or more of the
foregoing clauses having a rating of "A" or better by S&P or "A2" or
better by Moody's.
ESTABLISHMENT OF ACCOUNTS
We have established the following depositary accounts with the depositary
bank:
o revenue account;
o debt payment account;
o debt service reserve account;
o distribution suspense account;
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o redemption account; and
o 9 7/8% notes account.
We have granted a security interest in the depositary accounts to the
collateral agent for the benefit of the secured parties. The depositary
accounts will at all times be in the name of the collateral agent and in the
exclusive possession of, and under the exclusive dominion and control of, the
depositary bank acting at the direction of the collateral agent. Neither we nor
any of the assigning subsidiaries have any right to withdraw monies from the
depositary accounts or any other rights with respect to the depositary accounts
other than as described in the depositary agreement.
DEPOSIT AND DISBURSEMENT OF FUNDS
REVENUE ACCOUNT
We have and will continue to deposit or cause to be deposited into the
revenue account the following funds:
o all available cash flow, other than available cash flow required to be
deposited in the redemption account as described below,
o to the extent the debt service reserve account is fully funded, interest
and other investment income earned on funds on deposit in any of the
depositary accounts, and
o any other amounts required to be transferred to the revenue account
under the depositary agreement or the intercreditor agreement.
We are required to submit to the collateral agent, on or prior to each
date on which funds are to be transferred from the revenue account to the other
depositary accounts, a funds transfer certificate indicating the amounts which
should be transferred from the revenue account to the other depositary accounts
on that date.
PRIORITY OF PAYMENTS
On one business day of each month selected by us the depositary bank
transfers monies on deposit in the revenue account in accordance with the
following order of priority in the amounts specified by us in our funds
transfer certificate:
(1) First, to the persons entitled to the payments described in this
clause, an amount equal to the sum of (a) all of our operating and
administrative costs as well as those of the assigning subsidiaries and
California Energy Yuma and SECI Holdings incurred on or before the funding date
or reasonably expected to be incurred within the next 30 days, plus (b) any
taxes, assessments or other governmental charges or levies then due. However,
operating and administrative costs payable to our affiliates or the affiliates
of the assigning subsidiaries, California Energy Yuma or SECI Holdings will not
be paid under this first priority;
(2) Second, to the depositary bank, the collateral agent, the trustee and
the debt service reserve letter of credit provider, an amount equal to all
administrative expenses due and payable to those parties on the next payment
date;
(3) Third, to the debt payment account, an amount which, together with the
funds then on deposit in or credited to that account, is equal to the sum of:
(a) all principal of and interest on the securities and all other amounts
payable under indenture, to the extent due and payable on the next
payment date;
(b) all principal of and interest on any debt service reserve bonds as
described below under the caption "Debt Service Reserve Letter of
Credit Reimbursement Agreement," to the extent due and payable on the
next payment date;
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(c) all commitment, letter of credit and fronting fees payable under any
debt service reserve letter of credit reimbursement agreement, to the
extent due and payable on the next payment date; and
(d) all interest on any debt service reserve letter of credit loans as
described below under the caption "Debt Service Reserve Letter of
Credit Reimbursement Agreement," to the extent due and payable on the
next payment date;
(4) Fourth, to a sub-account of the debt payment account, an amount which,
together with the funds then on deposit in or credited to that sub-account, is
equal to the sum of (a) all principal of any debt service reserve letter of
credit loans and (b) all related fees and charges for tax gross-ups, capital
adequacy costs and breakage costs, in each case to the extent due or becoming
due on the next payment date;
(5) Fifth, to the debt service reserve account, an amount which, together
with the sum of (a) the funds then on deposit in or credited to that account
and (b) the amount available for drawing under any debt service reserve letter
of credit, is equal to the then current debt service reserve required balance;
(6) Sixth, (a) to the debt service reserve letter of credit provider or
any other financial institution providing a debt service reserve letter of
credit loan, other breakage costs which are due and payable in connection with
debt service reserve letter of credit loans, and (b) to the secured parties,
any indemnification expenses or other amounts which are not otherwise paid and
which are required to be paid to the secured parties;
(7) Seventh, to the persons entitled to the payments described in this
clause, an amount equal to the operating and administrative costs that were not
paid under the first priority above; and
(8) Eighth, to the distribution suspense account, any amounts remaining in
the revenue account after the making of the transfers described above in
clauses (1) through (7) above.
However, in the event the securities are accelerated and no foreclosure
occurs within 180 days afterwards, then principal of the debt service reserve
letter of credit loans will be paid in the third priority instead of the fourth
priority until the time that foreclosure has occurred or the acceleration has
been rescinded or otherwise remedied.
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The priority of transfers and payments from the revenue account as
described above is illustrated in the following flow chart.
[GRAPHIC OMITTED]
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DEBT PAYMENT ACCOUNT
Funds on deposit in or credited to the debt payment account on any funding
date according to the third priority above will be used to pay the following:
o all principal of and interest on the securities and all other amounts
payable under the indenture,
o all principal of and interest on any debt service reserve bonds,
o all commitment, letter of credit and fronting fees due and payable under
the debt service reserve letter of credit reimbursement agreement, and
o all interest on any debt service reserve letter of credit loans.
Funds on deposit in or credited to the sub-account of the debt payment account
on any funding date according to the fourth priority above will be used to pay
all principal of any debt service reserve letter of credit loans and related
fees and charges in connection with tax gross-ups, capital adequacy costs and
breakage costs on the payment date.
On any payment date that any of the amounts described in this paragraph
are due and payable (or if that day is not a business day, then on the next
business day), the depositary bank will remit funds on deposit in or credited
to the debt payment account or its sub-account to the persons entitled to the
payment of those amounts. If on any payment date, there are more funds on
deposit in or credited to the debt payment account than are required after
making the payments described in the immediately preceding sentence, the
depositary bank will transfer the excess funds from the debt payment account to
the revenue account on the payment date. If on any payment date, there are more
funds on deposit in or credited to the debt payment account's sub-account than
are required after making the payments described above, the depositary bank
will transfer the excess funds from the sub-account to the debt payment account
on the payment date.
DEBT SERVICE RESERVE ACCOUNT
We initially funded the debt service reserve account by providing the
depositary bank with a debt service reserve letter of credit in the amount of
approximately $24 million. We will at all times be required to maintain funds
in the debt service reserve account in an amount which, together with the
amount available for drawing under any debt service reserve letter of credit,
is equal to the then current debt service reserve required balance. The debt
service reserve required balance on any date equals the maximum semiannual
principal and interest payment due on the securities for the remaining term.
The funds on deposit in the debt service reserve account and the amounts
available for drawing under any debt service reserve letter of credit will be
used to make the following amounts, if amounts on deposit in the debt payment
account are insufficient to make these payments:
o payments of principal of, premium (if any) and interest on the
securities;
o any other amounts payable under the indenture for the securities; and
o to a limited extent as described below, interest on debt service
reserve letter of credit loans.
Any funds on deposit in or credited to the debt service reserve account which,
when aggregated with the amount available for drawing under any debt service
reserve letter of credit, exceed the then current debt service reserve required
balance, will be transferred to the revenue account.
Any debt service reserve letter of credit will be issued by a bank or
other financial institution with a long-term unsecured debt rating of at least
"A2" by Moody's and at least "A" by S&P. Each debt service reserve letter of
credit will permit the depositary bank to make drawings upon the occurrence of
the following events:
(1) there being insufficient funds in the debt payment account on any
payment date to pay interest or principal then due on the securities
after application of funds from the debt service reserve account;
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(2) upon our failure to provide a substitute letter of credit from
another letter of credit provider within at least 45 days after
receipt of a notice from the current letter of credit provider that
its long-term debt is rated less than "A2" as determined by Moody's
or "A" as determined by S&P;
(3) upon receipt of a notice from the debt service reserve letter of
credit provider that the debt service reserve letter of credit will
be terminated before the stated expiration date;
(4) upon our failure to obtain an extension or provide a replacement debt
service reserve letter of credit at least 45 days before the
expiration of the existing debt service reserve letter of credit; and
(5) upon receipt of a notice from the letter of credit provider that
interest is due and payable, but unpaid, on outstanding debt service
reserve letter of credit loans. However, any drawing made according
to this clause (5), together with all other drawings made in the same
fiscal year, cannot exceed $5,000,000.
The depositary bank will apply the proceeds of each drawing described in
clauses (1) and (5) above to payment of the relevant obligation. The depositary
bank will apply the proceeds of each drawing described in clauses (2), (3) and
(4) above to the debt service reserve account until the amount of the debt
service reserve required balance is met.
DISTRIBUTION SUSPENSE ACCOUNT
The distribution suspense account will be funded with monies remaining in
the revenue account after all other required transfers and payments have been
made. On any funding date on which the distribution conditions described below
are satisfied, monies on deposit in the distribution suspense account may be
distributed to or as directed by us:
o the debt payment account and the debt service reserve account are funded
to their then current required levels and all payments described in
first, second, sixth and seventh priorities above are satisfied in full;
o no default or event of default has occurred and is continuing or will
result from the distribution;
o the debt service coverage ratio for the preceding four fiscal quarters
ending on or prior to the funding date, measured as one period, is
greater than or equal to 1.5 to 1.0;
o the projected debt service coverage ratio for the succeeding four fiscal
quarters, including the quarter in which the distribution is to be made,
measured as one period, is greater than or equal to 1.5 to 1.0; and
o if a material default or an event of default has occurred and is
continuing under any project financing document for the Saranac project,
the Power Resources project, the Yuma project or the geothermal projects,
the loan life coverage ratio is greater than or equal to 1.7 to 1.0.
For purposes of this description of the distribution conditions:
(1) "debt service coverage ratio" means, for any period, the ratio of
clause (1) below to clause (2) below:
(1) the sum of:
o all available cash flow for the period; plus
o all interest and other investment income earned on monies on
deposit in or credited to the depositary accounts during the
period; plus
o all other cash flow received and deposited in the revenue
account during the period.
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(2) the sum of:
o all operating and administrative costs, other than operating
and administrative costs that are subordinate to debt service
on the securities and our other senior debt, if any, and other
expenses due and payable during the period; plus
o the aggregate of principal and interest payments, and any other
amounts due, on the securities and all other permitted debt,
excluding subordinated debt, for the period; and
(2) "loan life coverage ratio" means, at any measurement date, the ratio
of clause (1) below to clause (2) below:
(1) the sum of:
o the net present value, at a discount rate equal to the interest
rate for the securities, of the projected available cash flow
from the date of measurement to the final maturity date for the
securities, other than the available cash flow of a assigning
subsidiary for which there has occurred a default or an event
of default under the project financing documents for the
assigning subsidiary's project company; plus
o the then remaining balance in the debt service reserve account;
plus
o all interest and other investment income then on deposit in or
credited to the revenue account and the debt service reserve
account.
(2) the sum of:
o the aggregate principal amount of the securities and all other
permitted debt which is repayable during the period from the
measurement date up to and including the final maturity date of
the securities; plus
o all administrative costs and other expenses due and payable
during the period from the measurement date up to and including
the final maturity date of the securities.
If on any funding date amounts on deposit in the revenue account are
insufficient to make the transfers described in the first through seventh
priorities above, then amounts on deposit in the distribution suspense account
will be transferred to the revenue account.
REDEMPTION ACCOUNT
The following funds will be deposited in the redemption account:
o all available cash flow representing insurance proceeds for damage to or
destruction of all or a portion of a project;
o all available cash flow representing expropriation proceeds for a
governmental authority's compulsory taking or transfer of a project or
threat of a compulsory taking or transfer of a project;
o all available cash flow representing title insurance proceeds for a
defect in the title to the land on which a project is located;
o all available cash flow representing proceeds from a power contract
buy-out;
o all available cash flow representing proceeds from a sale of assets;
o all available cash flow representing proceeds from the refinancing of
project-level debt;
o all proceeds from our sale of all or a portion of our interests in any
assigning subsidiary; and
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o all proceeds from an assigning subsidiary's sale of all or a portion of
its interests in its project company.
Funds on deposit in the redemption account will be used to redeem the
securities and to pay our other secured obligations.
9 7/8% NOTES ACCOUNT
MidAmerican intends to redeem all of Magma's remaining 9 7/8% promissory
notes on June 30, 2000, the first day upon which redemption is permitted under
the indenture for the 9 7/8% promissory notes (if not previously repurchased).
As of the date of this prospectus, the outstanding principal amount of the 9
7/8% notes is approximately $4.2 million.
PERMITTED INVESTMENTS
All funds held by the depositary bank in the depositary accounts will be
invested in permitted investments at our expense and risk
o if no default or event of default has occurred and is continuing, at
election and as directed in writing by one of our authorized officers;
and
o if a default or an event of default has occurred and is continuing,
at the election of and as directed by the collateral agent.
These permitted investments must mature, or be subject to redemption or be
capable of being sold or otherwise liquidated at the option of their holder, in
amounts and not later than as may be necessary to provide funds when needed to
make payments from the depositary accounts. In no event will any of the
permitted investments in the depositary accounts mature more than one year
after the date acquired. Absent written instructions from us or the collateral
agent, as applicable, the depositary bank will invest funds held in the
depositary accounts in direct obligations of the United States or any United
States agency with a maturity of 30 days or less. Net interest and other
investment income earned on any permitted investments credited to any
depositary account will be transferred (1) first to the debt service reserve
account until the amount of funds deposited in or credited to that account,
together with the amount available for drawing under any debt service reserve
letter of credit, is equal to the then current debt service reserve required
balance, and (2) then to the revenue account.
INDENTURE
GENERAL
The old securities were, and the new securities will be, issued under an
indenture entered into between us and the trustee acting on behalf of the
holders of securities. The indenture describes the terms of the securities. We
are permitted to issue additional securities under the indenture, subject to
the satisfaction of conditions described below. All additional securities will
rank evenly in priority with the securities, will be secured by the collateral
and will have terms, be in a form and be issued at prices as approved by us in
writing. No additional securities may be issued at any time if a default or an
event of default has occurred and is continuing or if the proposed issuance
would cause a default or an event of default. All net proceeds of any
additional securities must be used for one or more of the purposes specified in
the indenture and described below.
COVENANTS
Following is a description of some of our affirmative and negative
covenants.
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AFFIRMATIVE COVENANTS
INFORMATION REQUIREMENTS
We will furnish or cause to be furnished the following financial
statements and compliance certificates to the trustee and the rating agencies,
as well as any holder of securities or beneficial owner of a security at their
request:
o our unaudited consolidated financial statements for the first, second
and third quarters within 45 days after the end of the quarter;
o our annual audited consolidated financial statements within 90 days
after the end of each fiscal year; and
o an officer's certificate stating whether a default or an event of
default has occurred each time we provide the financial statements
described above.
We will also furnish notices of defaults and events of default to the
trustee and the rating agencies.
MAINTENANCE OF EXISTENCE, QUALIFICATION AND RIGHTS
Other than as provided below under the caption "Business Activities;
Fundamental Changes; Sales of Assets," we will at all times preserve and
maintain in full force and effect (1) our existence as a limited liability
company in good standing under the laws of the State of Delaware and (2) our
qualification to do business in each other jurisdiction where qualification is
necessary, except in each case as permitted under the financing documents.
We will maintain and renew all of the powers, rights, privileges and
franchises necessary to transact our business as it is actually conducted or as
it is proposed to be conducted, unless the failure to do so would not
reasonably be expected to result in a material adverse effect.
As used above and as used throughout the remainder of this summary, the
term "material adverse effect" means a material adverse effect on any of the
following:
o the financial condition of results of operation of us or the assigning
subsidiaries taken as a whole;
o the validity or priority of the liens on the collateral;
o our ability to perform our material obligations under the indenture, the
securities or any of the other financing documents; or
o the ability of the assigning subsidiaries to perform any of their
material obligations under the financing documents.
COMPLIANCE WITH LAWS AND GOVERNMENTAL APPROVALS
We will comply with all applicable laws and obtain all necessary
governmental approvals relating to our issuance of the securities and the
performance of our obligations under the indenture, if our failure to do so
would reasonably be expected to result in a material adverse effect.
PERFORMANCE OF FINANCING DOCUMENTS
We will perform all of our material covenants and agreements contained in
any of the financing documents to which we are a party and will take all
reasonable and necessary actions to prevent the termination or cancellation of
any those financing document as against us, any assigning subsidiary or any
affiliate of ours or any assigning subsidiary, unless our failure to do so
would not reasonably be expected to result in a material adverse effect.
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MAINTENANCE OF PROPERTY; PRESERVATION OF COLLATERAL
We will preserve and maintain good and valid title to all of our
properties and assets subject to no liens other than those permitted liens
described below, unless our failure to do so would not reasonably be expected
to result in a material adverse effect.
We will preserve and maintain the liens on the collateral and will defend
our title to the collateral against the claims of all persons, unless our
failure to do so could not reasonably be expected to result in a material
adverse effect.
OTHER AFFIRMATIVE COVENANTS
The indenture also contains other affirmative covenants, including our
obligations to:
o make payments on the securities,
o maintain an office for payment, exchange and transfer of the securities,
o pay all taxes and charges required to be paid by us,
o keep proper books and records in accordance with generally accepted
accounting principals,
o provide the trustee, the collateral agent and the depositary bank with
reasonable inspection rights,
o use the proceeds of the issuance and sale of the securities and any
additional securities in accordance with the indenture,
o retain a nationally recognized independent accounting firm and permit
the trustee, the collateral agent and the depositary bank to discuss our
affairs, finances and accounts with that accounting firm upon reasonable
notice and at reasonable times following and during the continuance of a
default or an event of default,
o pledge all of the capital stock of Magma within 10 days after the date
on which the stock is released from the liens securing Magma's 9 7/8%
promissory notes, and
o make an election to be treated as an association taxable as a
corporation for United States tax purposes.
NEGATIVE COVENANTS
RESTRICTIONS ON THE INCURRENCE OF DEBT AND THE CREATION OF LIENS
We will not incur any debt except the following permitted debt:
o debt incurred under the indenture and the securities;
o debt incurred under an agreement providing for the issuance of a debt
service reserve letter of credit;
o debt in an aggregate principal amount not to exceed $10 million, so long
as, after giving effect to the incurrence of the debt, no default or
event of default will have occurred and be continuing;
o subordinated debt loaned to us by our affiliates which are not our
direct or indirect majority-owned subsidiaries, in an aggregate principal
amount not to exceed $200 million, so long as this subordinated debt is
used to finance capital expenditures, expansions or operation and
maintenance costs for the existing projects or the construction of new
projects; and
o debt incurred in excess of the $10 million of debt described above, so
long as (1) after giving effect to the incurrence of the debt, no default
or event of default will have occurred and be continuing, and (2) after
giving effect to the incurrence of the debt, the rating assigned to the
securities by each rating agency will be equivalent to or better than an
investment grade rating.
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We will not create any lien upon or with respect to any of our properties
except the following permitted liens:
o liens specifically permitted or required by, or created by, any security
document;
o liens to secure permitted debt, so long as the holder of the permitted
debt, or a representative of the holder, will have entered into the
intercreditor agreement;
o liens for taxes, assessments or governmental charges which are either
not yet due or which are being diligently contested in good faith by
appropriate proceedings and for which adequate reserves are established
in accordance with generally accepted accounting principles;
o other liens incidental to the conduct of our business 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 of the encumbered assets in the operation of our business;
and
o liens which existed on the closing date for the old securities and are
set forth on a schedule to the indenture.
BUSINESS ACTIVITIES; FUNDAMENTAL CHANGES; SALES OF ASSETS
We will not at any time engage in any activities other than:
o owning our subsidiaries and related activities;
o the activities contemplated by the indenture and the other financing
documents and related activities; and
o any other activity which could not reasonably be expected to result in a
material adverse effect and which the rating agencies confirm in writing
will not result in a lowering of the existing ratings for the securities.
We will not enter into any transaction of merger or consolidation, change
our form of organization or our business, liquidate, wind-up or dissolve
ourselves or discontinue our business, unless (1) we are the surviving company
or the surviving company is a domestic or Canadian company and assumes our
obligations under the securities and the other financing documents, (2)
immediately before and after the transaction, no event of default will have
occurred and be continuing, and (3) the rating agencies confirm that the
transaction will not result in a lowering of the existing ratings for the
securities.
We will not dispose of or encumber any of our assets, except as permitted
under the financing documents.
INVESTMENTS; TRANSACTIONS WITH AFFILIATES
We will not form or have any subsidiaries, make investments, loans or
advances or acquire the stock, obligations or securities of any person, other
than the following:
o those that existed on the closing date for the old securities,
o permitted investments,
o investments, loans or advances made with funds which do not constitute
collateral, and
o investments in subsidiaries if the rating agencies confirm that their
formation will not result in a lowering of the existing ratings for the
securities.
We will not enter into any transaction, whether or not in the ordinary
course of business, with any of our affiliates which is not on an arm's-length
basis. We may, however, perform our obligations under, and engage in the
transactions permitted by, the financing documents.
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RESTRICTED PAYMENTS
The following are restricted payments and will be made only from the
distribution suspense account if the distribution conditions described above
are satisfied:
o any declaration and payment of distributions, dividends or any other
similar payment made on account of our equity interests;
o any payment of the principal of or interest on any of our subordinated
debt; or
o any loans or advances to any of our affiliates.
OTHER NEGATIVE COVENANTS
The indenture also contains other negative covenants, including, without
limitation, our obligation not to do any of the following:
o amend our certificate of formation or any other organizational document
if this action could reasonably be expected to result in a material
adverse effect,
o assign any of our rights or obligations under any financing document or
enter into any additional agreements, contracts or other undertakings if
this action could reasonably be expected to result in a material adverse
effect,
o take any action which will cause us to be in violation of the Investment
Company Act of 1940, as amended, or
o contingently or otherwise become liable in connection with any guarantee
obligation other than guarantees of permitted debt which is incurred by
(a) a person that is not one of our affiliates or (b) one of our
wholly-owned subsidiaries.
EVENTS OF DEFAULT AND REMEDIES
EVENTS OF DEFAULT
The following events constitute events of default under the indenture:
(1) if we fail to pay any principal of, premium (if any) or interest on
any security when it becomes due and payable;
(2) if we make a false representation in a financing document and the
circumstances underlying the misrepresentation have resulted in, or
could reasonably be expected to result in, a material adverse effect.
We will have 30 days to cure this default, or up to 90 days if we are
diligently pursuing the cure;
(3) if we fail to perform any covenant under the indenture relating to
maintenance of existence, payment of taxes, incurrence of debt,
creation of liens, business activities, fundamental changes, sales of
assets, restricted payments or issuance of guarantee obligations. We
will have 30 days to cure this default;
(4) if we fail to perform any of our covenants contained in the indenture
other than those referred to above. We will have 60 days to cure this
default, or up to 90 days if we are diligently pursuing the cure;
(5) if we are the subject of a bankruptcy proceeding or another similar
proceeding;
(6) if any security document ceases in any material respect to be in full
force and effect or any material lien purported to be granted in any
security document ceases to be a valid and perfected lien in favor of
the collateral agent with the priority purported to be created in the
security document. We will have 10 days to cure this default;
(7) if payment of our debt in excess of $5 million, other than debt
incurred under the indenture or a debt service reserve letter of
credit and reimbursement agreement, is accelerated following an event
of default under the instrument evidencing the debt;
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(8) if one or more final and non-appealable judgment or judgments for the
payment of money in excess of $5 million is entered against us and
remains unpaid or unstayed for a period of 90 or more consecutive
days, other than a judgment which we are diligently contesting in good
faith by appropriate proceedings and for which we have established
adequate cash reserves;
(9) if any party to any financing document, other than a secured party,
fails to perform covenant contained in the financing document, subject
to any applicable grace periods, and the failure could reasonably be
expected to result in a material adverse effect; and
(10) if MidAmerican fails to call for redemption all of Magma's
outstanding 9 7/8% promissory notes within 10 days of the first day on
which redemption is permitted under the indenture for the 9 7/8%
notes.
EXERCISE OF REMEDIES
CONTROL BY HOLDERS OF SECURITIES
Holders of securities holding more than 50% of the aggregate principal
amount of the outstanding securities 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. However,
(1) their direction may not be in conflict with any rule of law or with the
indenture or the intercreditor agreement, (2) the trustee may take any other
action deemed proper by the trustee which is not inconsistent with the
direction of the holders, and (3) the trustee need not follow any direction of
the holders if doing so would in its reasonable discretion either involve it in
personal liability or be unduly prejudicial to holders of securities not
joining in the direction.
REMEDIES AVAILABLE
If any event of default occurs and continues:
(1) in the case of an event of default described in clause (1) above under
the caption "Events of Default," holders of securities holding more than 33
1/3% in aggregate principal amount of the outstanding securities may, by
written notice to us and the trustee, declare the entire principal amount of
the outstanding securities, all accrued and unpaid interest and all other
amounts payable in connection with the outstanding securities, to be
immediately due and payable;
(2) in the case of an event of default described in clause (5) above under
the caption "Events of Default," the entire principal amount of the outstanding
securities, all accrued and unpaid interest and all other amounts payable in
connection with the outstanding securities will automatically become due and
payable; and
(3) in the case of all other events of default described above under the
caption "Events of Default," a majority of the holders may, by written notice
to us and the trustee, declare the entire principal amount of the outstanding
securities, all accrued and unpaid interest and all other amounts payable in
connection with the outstanding securities, to be immediately due and payable.
Subject to the intercreditor agreement, if at any time after the principal
of the securities becomes due and payable upon a declared acceleration, and
before any judgment or decree for the payment of the money due, or any portion
of the money due, is entered, a majority of the holders, by written notice to
us and the trustee, may rescind and annul a declaration and its consequences
if:
(1) there is paid to or deposited with the trustee a sum sufficient to
pay:
(a) all overdue installments of interest on the securities;
(b) the principal of and premium, if any, on the securities that have
become due other than by the declaration of acceleration, and
interest on the securities at the rates provided in the securities
for late payments of principal;
(c) to the extent that payment is lawful, interest upon overdue interest
at the rates provided in the securities for late payments of
interest; and
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(d) all sums paid or advanced by the trustee under the indenture and the
reasonable compensation, expenses, disbursements and advances of the
trustee and its agents and counsel; and
(2) all events of default, other than the nonpayment of principal of the
securities that has become due solely by the declared acceleration, have been
cured or waived in accordance with the indenture.
APPLICATIONS OF FUNDS
Following the application of funds as provided in the intercreditor
agreement, any money to be applied by the trustee after an event of default
will be applied in the following order:
(1) first, to the payment of all amounts due to the trustee or any
predecessor trustee under the indenture;
(2) second, if the unpaid principal amount of the outstanding securities
has not become due, to the payment of any overdue interest , together
with interest, to the extent legally enforceable, on the payments of
overdue interest;
(3) third, if the unpaid principal amount of a portion of the outstanding
securities has become due, (1) first to the payment of premium (if
any) and accrued interest on all outstanding securities, together with
interest, to the extent legally enforceable, on the payments of
premium (if any) and overdue interest, and (2) next to the payment of
the unpaid principal amount of all securities then due;
(4) fourth, if the unpaid principal amount of all of the outstanding
securities has become due, to the payment of the whole amount then due
and unpaid upon the outstanding securities for principal, premium (if
any) and interest, together with interest to the extent legally
enforceable, on the overdue principal, premium (if any) and interest;
and
(5) fifth, if the unpaid principal amount of all of the outstanding
securities has become due, and all of the outstanding securities have
been indefeasibly paid in full in cash or cash equivalents, any
surplus then remaining will be paid to us or to whoever may be
lawfully entitled to receive the surplus, or as a court of competent
jurisdiction may direct.
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The priority of payments described in clauses (1) through (5) above is
illustrated in the following flow chart.
[GRAPHIC OMITTED]
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AMENDMENTS AND SUPPLEMENTS
We and the trustee may amend or supplement the indenture without the
consent of the holders of securities for the following purposes:
o to add additional covenants against us, to surrender rights or powers
conferred upon us or to confer additional rights, remedies, benefits,
powers or authorities upon the holders of securities,
o to increase the assets securing our obligations under the indenture,
o to provide for the issuance of additional securities on the conditions
described in the indenture, or
o for any purpose not inconsistent with the terms of the indenture to cure
any ambiguity, defect or inconsistency.
The indenture may be otherwise amended or supplemented by us and the
trustee with the consent of the majority holders. However, no amendment or
supplement may, without the consent of each holder of securities, modify the
following:
o the principal, premium (if any) or interest payable upon any of the
securities,
o the dates on which interest on or principal of any of the securities is
paid,
o the dates of maturity of any of the securities, or
o the procedures for amendment of the indenture by a supplemental
indenture.
SATISFACTION AND DISCHARGE
We may terminate the indenture by delivering all outstanding securities to
the trustee for cancellation and by paying all other sums payable under the
indenture.
Legal and covenant defeasance will be permitted upon terms and conditions
customary for transactions of this nature.
TRUSTEE
There will at all times be a trustee under the indenture which will:
o be a corporation organized and doing business under the laws of the
United States, any state or territory of the United States or the
District of Columbia;
o be authorized under those laws to exercise corporate trust powers;
o be subject to supervision or examination by federal, state, territorial
or District of Columbia authority;
o either (1) have a combined capital and surplus of at least $50 million
or (2) have a combined capital and surplus of at least $10 million and be
a wholly-owned subsidiary of a corporation having a combined capital and
surplus of at least $50 million; and
o have a corporate trust office in New York City.
We agree 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 gross negligence or bad faith of the trustee.
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The trustee may resign at any time by giving written notice to us. The
trustee may be removed at any time by act of the majority holders, delivered to
the trustee and us. We will give notice of each resignation and removal of the
trustee and each appointment of a successor trustee to all holders of
securities and to the rating agencies. The trustee also serves as trustee for
the holders of the Imperial Valley project financing debt. In the event a
conflict of interest were to arise between those holders and the holders of
securities, the trustee may determine, or be required, to resign as trustee
under the indenture.
DEBT SERVICE RESERVE LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT
GENERAL
On the closing date for the old securities, Credit Suisse First Boston
issued a debt service reserve letter of credit for our account in the amount of
approximately $24 million in favor of the depositary bank. The debt service
reserve letter of credit was issued under the debt service reserve letter of
credit and reimbursement agreement.
The depositary bank may make drawings under any debt service reserve
letter of credit upon the occurrence of the following events:
(1) there being insufficient funds in the debt payment account on any
payment date to pay interest or principal then due on the securities
after application of funds from the debt service reserve account;
(2) upon our failure to provide a substitute letter of credit from another
letter of credit provider within not more than 45 days after receipt of
a notice from the current letter of credit provider that its long-term
debt is rated less than "A" as determined by S&P or "A2" as determined
by Moody's;
(3) upon receipt of a notice from the letter of credit provider that the
debt service reserve letter of credit will be terminated before its
stated expiration date;
(4) upon our failure to obtain an extension or provide a replacement debt
service reserve letter of credit at least 45 days before the expiration
of the current debt service reserve letter of credit; and
(5) upon receipt of a notice from the letter of credit provider that
interest is due and payable, but unpaid, with respect to outstanding
debt service reserve letter of credit loans, so long as any drawing
under this clause, together with all other drawings under the debt
service reserve letter of credit in the same calendar year, does not
exceed $5,000,000.
The depositary bank will apply the proceeds of each drawing described in
clauses (1) and (5) to payment of the relevant obligation. The depositary bank
will apply the proceeds of each drawing described in clauses (2), (3) and (4)
to the debt service reserve account until the debt service reserve required
balance is met.
The amount available for drawing under the debt service reserve letter of
credit will be reduced upon (1) the making of draws, (2) a reduction of the
debt service reserve required balance and (3) the deposit of cash in the debt
service reserve account.
DEBT SERVICE RESERVE LETTER OF CREDIT LOANS
Each drawing on the debt service reserve letter of credit submitted by the
depositary bank will be converted into a loan to us.
Each debt service reserve letter of credit loan will be evidenced by a
note and will mature on the later of (1) ten years from the closing date for
the old securities or (2) five years from the drawing giving rise to the loan.
We will repay the principal amount of each debt service reserve letter of
credit loan as, when and to the extent funds are made available from the
revenue account for these repayments.
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CONVERSION TO DEBT SERVICE RESERVE BOND
If:
(1) 50% or more of the principal amount of any debt service reserve letter
of credit loan remains outstanding on or after 5 years from the drawing
giving rise to the loan; or
(2) the principal amount of any debt service reserve letter of credit loan
remains outstanding on or after l0 years from the closing date for the
old securities;
then the letter of credit provider may, upon 30 days' prior written notice to
us and the trustee, convert the debt service reserve letter of credit loan into
a debt service reserve bond. Each debt service reserve bond will amortize on a
basis which results in levelized payment of the principal of and interest on
the debt service reserve bond to and including its maturity date, which will be
the final maturity date of the securities. Each debt service reserve bond will
bear interest at a fixed rate equal to the higher of:
(a) the interest rate last applicable to the converted debt service reserve
letter of credit loan; and
(b) the rate of interest, at the time of conversion, on United States
Treasury notes with an average life most comparable to the average life
of the securities plus the higher of (1) 2.50% and (2) the spread over
United States Treasury notes applicable to the securities on the
closing date for the old securities.
We will pay principal of and interest on each debt service reserve bond with
the same payment priority as payments of principal of and interest on the
securities.
EVENTS OF DEFAULT
The following events constitute events of default under the debt service
reserve letter of credit and reimbursement agreement:
o We fail to pay any principal, interest or other amounts due under the
debt service reserve letter of credit and reimbursement agreement or any
debt service reserve letter of credit bond within 15 days after its due
date in the case of principal and interest, and within 15 days after
delivery of notice to us in the case of fees, costs and expenses;
o if we make a false and the representation in the debt service reserve
letter of credit and reimbursement agreement circumstances that gave rise
to the misrepresentation have resulted in or could reasonably be expected
to have a material adverse effect. We have 30 days to cure this default,
or up to 90 days if we are diligently pursuing the cure;
o if any provision of the indenture, the depositary agreement or any
security document is terminated, amended or otherwise modified without
the prior written approval of banks which hold at least 66 2/3% of the
obligations and/or commitments under the debt service reserve letter of
credit and reimbursement agreement, if the termination, amendment or
other modification would do any of the following:
o affect the priority of payments from the revenue account under the
depositary agreement in a manner adverse to the agent under the debt
service reserve letter of credit and reimbursement agreement or any bank
party to the debt service reserve letter of credit reimbursement
agreement;
o increase the interest rate on the securities other than in accordance
with the indenture;
o amend the payment dates for the securities in a manner adverse to the
letter of credit agent or any letter of credit bank; or
o change the voting requirements under the intercreditor agreement in a
manner adverse to the letter of credit agent or any letter of credit
bank. We have 60 days to cure this default, or up to 90 days if we are
diligently pursuing the cure;
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o if we fail to perform covenants under the indenture which are
incorporated by reference in the debt service reserve letter of credit
and reimbursement agreement and all outstanding securities have paid in
full and the indenture is no longer in effect. We will have 30 days to
cure this default;
o if we fail to perform our covenants contained in any other provision of
the debt service reserve letter of credit and reimbursement agreement. We
will have 60 days to cure this default, or up to 90 days if we are
diligently pursuing the cure; and
o if an event of default as described under any of clauses (2) through
(10) of the summary of indenture events of default occurs and continues
until the earlier of the expiration of 30 days or an acceleration of the
securities.
REMEDIES
Upon the occurrence of an event of default under the debt service reserve
letter of credit and reimbursement agreement, the debt service reserve letter
of credit provider may (1) terminate the debt service reserve letter of credit,
(2) accelerate any outstanding debt service reserve letter of credit loans or
debt service reserve bonds and (3) terminate its commitment.
SECURITY ARRANGEMENTS
Our payment of the principal of, premium (if any), interest on and other
amounts due under or in connection with the securities or the other secured
obligations will be secured by the collateral under the terms of the security
documents. The preservation and administration of the collateral by the
collateral agent and the disposition of the collateral among the secured
parties upon acceleration and foreclosure will be governed by the intercreditor
agreement.
SECURITY DOCUMENTS
SUBSIDIARY SECURITY AGREEMENT
Under the subsidiary security agreement executed by the assigning
subsidiaries in favor of the collateral agent, Magma, Salton Sea Power, Falcon
Seaboard Resources, Falcon Seaboard Power, Falcon Seaboard Oil, California
Energy Development and CE Texas Energy have (1) assigned to the collateral
agent all of the assigning subsidiaries' rights to receive available cash flow
and (2) granted to the collateral agent, acting on behalf of the secured
parties, a lien on all of the assigning subsidiaries' available cash flow which
is deposited with the depositary bank.
The subsidiary security agreement also contains affirmative and negative
covenants of the assigning subsidiaries. Affirmative covenants of the assigning
subsidiaries include the obligation of each assigning subsidiary to, subject to
exceptions set forth in the subsidiary security agreement:
o provide notices and information to the trustee and the rating
agencies;
o maintain its existence, qualification to do business and rights and
privileges, except, with respect to qualification to do business and
rights and privileges, where the failure to do so could not
reasonably be expected to result in a material adverse effect;
o comply with all applicable laws, except where the failure to do so
could not reasonably be expected to result in a material adverse
effect;
o obtain and comply with all necessary governmental approvals, except
where the failure to do so could not reasonably be expected to result
in a material adverse effect;
o perform its obligations under the financing documents, except where
the failure to do so could not reasonably be expected to result in a
material adverse effect;
o cause its project company:
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(1) to perform its covenants under its project documents and project
financing documents, except where the failure to do so could not
reasonably be expected to result in a material adverse effect;
(2) not to amend, terminate or otherwise modify any of its project
documents or project financing documents, except a power contract
buy-out which would not result in a ratings down-grade or where doing
so could not reasonably be expected to result in a material adverse
effect;
(3) to maintain the qualifying facility status of its project, except
where the failure to do so could not reasonably be expected to result
in a material adverse effect;
(4) not to enter into any additional project documents or project
financing documents, except where doing so could not reasonably be
expected to result in a material adverse effect;
(5) not to incur any additional debt except:
o if the rating agencies confirm in writing that the incurrence will
not result in a ratings downgrade; and
o other than with respect to Magma and Falcon Seaboard Resources, in
other limited circumstances; and
(6) not to create any liens other than liens permitted under the
financing documents;
o maintain title to its assets, except where the failure to do so could
not reasonably be expected to result in a material adverse effect;
o maintain the liens on its collateral in favor of the collateral
agent, except where the failure to do so could not reasonably be
expected to result in a material adverse effect;
o pay its taxes;
o keep books and records in accordance with generally accepted
accounting principals;
o cause all available cash flow to which it has a right to receipt to
be deposited into the revenue account;
o use its reasonable best efforts to cause its project company, and
each of its subsidiaries which owns an interest in its project
company, to declare and pay distributions to it with all available
cash flow then available for distribution; and
o hold all available cash flow received by it in trust for the secured
parties and immediately deliver all of its available cash flow to the
depositary bank.
Negative covenants of the assigning subsidiaries include the following
obligation of each assigning subsidiary not to, subject to exceptions set forth
in the subsidiary security agreement:
o incur any debt other than the secured obligations, debt existing on
the closing date for the old securities and other permitted debt or;
o create any lien on its properties other than permitted liens;
o become liable for any guarantee obligation, except guarantees of
permitted debt which is incurred by (1) a person that is not an
affiliate of the assigning subsidiary or (2) other than a
wholly-owned subsidiary of the assigning subsidiary;
o engage in any activities other than (1) the ownership of an interest
in its project company, (2) with respect to Magma, the performance of
its obligations under the project documents, (3) the activities
contemplated by the indenture and the other financing documents and
related activities and (4) other activities which could not
reasonably be expected to result in a material adverse effect and
which the rating agencies confirm will not result in a lowering of
the existing ratings for the securities;
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o merge, consolidate, change its form of organization or business,
liquidate, wind-up or dissolve itself, unless: (1) the assigning
subsidiary is the surviving company or the surviving company is a
domestic company that assumes the assigning subsidiary's obligations
under the financing documents; (2) no event of default under the
indenture exists or results from the transaction; and (3) the rating
agencies confirm that the transaction will not result in a lowering of
the existing ratings for the securities;
o sell, transfer or convey any portion of its interest in its project
company other than, so long as no event of default has occurred and is
continuing, (1) any sale for fair market value the proceeds of which are
in the form of cash or cash equivalents and are used to redeem securities
in accordance with the indenture, if required, or (2) a transfer
permitted under the financing documents;
o form subsidiaries, make investments, loans or advances or acquire the
stock, obligations or securities of any person other than (1) permitted
investments, (2) investments, loans or advances made with funds which do
not constitute collateral and (3) subsidiaries the formation of which the
rating agencies confirm will not result in a lowering of the existing
ratings for the securities;
o enter into non-arm's-length transactions with affiliates except as
permitted by the financing documents;
o make restricted payments other than the payment of available cash flow
into the revenue account;
o assign its rights or obligations under the financing documents or enter
into additional contracts or agreements if those assignments or
additional contracts or agreements could reasonably be expected to result
in a material adverse effect; or
o amend its organizational documents or any other material contract if
the amendment could reasonably be expected to result in a material
adverse effect.
CE GENERATION SECURITY AGREEMENT
Under to the CE Generation security agreement executed by us in favor of
the collateral agent, we have granted to the collateral agent, acting on behalf
of the secured parties, a lien on the following, whether currently owned or
later acquired by us:
o all of our rights under the contracts, agreements or undertakings to
which we are a party;
o the depositary accounts and all cash, investments and other assets on
deposit in or credited to those accounts;
o all of our other tangible personal and intangible property, to the
extent it is possible to grant a lien on this property, other than
the capital stock of Magma, which will be pledged upon the redemption
of, or earlier release of security interests under, Magma's 9 7/8%
promissory notes; and
o all proceeds received or receivable in connection with any of the
above, to the extent it is possible to grant a lien on these
proceeds.
PLEDGE AGREEMENTS
Under the pledge agreements executed by us, Magma and some of the
intermediate holding companies in favor of the collateral agent, those parties
pledged the following to the collateral agent, acting on behalf of the secured
parties:
(1) all of the equity interests in CE Texas Gas and the assigning
subsidiaries, other than the capital stock of Magma and the 1% of the
shares of capital stock of Salton Sea Power which is owned by Salton
Sea Funding Corporation;
(2) upon the redemption of, or other release of security interests under,
Magma's 9 7/8% promissory notes, all of the capital stock of Magma;
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(3) all of the capital stock of SECI Holdings; and
(4) all dividends, distributions, cash, instruments and other property
and proceeds from time to time received, receivable or otherwise
distributed in respect of or in exchange for the equity interests
described in clauses (1), (2) and (3).
MidAmerican's obligation to make payments on Magma's 9 7/8% promissory
notes is secured by a pledge of the capital stock of Magma and a lien on
dividends and distributions in respect of the Magma stock. On March 3, 1999,
MidAmerican repurchased $195.8 million in aggregate principal amount of its 9
7/8% Notes in connection with a tender offer for a repurchase price, including
premium, of $215.4 million. In connection with the corresponding reduction of
$195.8 million of the principal outstanding under Magma's 9 7/8% promissory
notes, $215.4 million of the proceeds of the old securities were paid to
MidAmerican. As a result of the 9 7/8% note repurchase offer, the outstanding
principal amount of Magma's 9 7/8% promissory notes was reduced from $200
million to approximately $4.2 million. MidAmerican intends to redeem the
remaining outstanding Magma 9 7/8% promissory notes on June 30, 2000, which is
the first day upon which an optional redemption is permitted under the trust
indenture for Magma's 9 7/8% promissory notes. A portion of the net proceeds of
the old securities, in the amount of approximately $4.2 million, has been paid
to MidAmerican and placed into a restricted account held by the depositary bank
which is maintained solely for the purpose of paying the remaining amounts due
to the secured parties. These proceeds are being used to pay interest on, and
effect the redemption or earlier repurchase of the remaining outstanding
principal of, Magma's 9 7/8% promissory notes. At the time of this redemption,
the collateral agent is expected to obtain a pledge of all of Magma's capital
stock.
INTERCREDITOR AGREEMENT
The collateral will be shared among the secured parties as provided in the
intercreditor agreement entered into among us, the assigning subsidiaries and
the secured parties. The intercreditor agreement will govern:
(1) the appointment of the collateral agent as agent for each of the
secured parties;
(2) the preservation and administration of the collateral by the
collateral agent;
(3) the disposition of the collateral among the secured parties upon
acceleration and foreclosure; and
(4) the application of:
o available cash flow representing loss proceeds, expropriation
proceeds, title proceeds, buy-out proceeds, refinancing proceeds or
asset sale proceeds; and
o proceeds from our sale of all or a portion of our interests in any
assigning subsidiary or the sale by an assigning subsidiary of all or
a portion of its interest in any project company.
Each person replacing any of the secured parties and each person, or a trustee
therefor or agent thereof, holding secured obligations will be required to
become a party to the intercreditor agreement, which will be amended to the
extent necessary to accommodate the replacement or addition of those persons.
VOTING
The exercise of remedies following the occurrence of a trigger event, as
described below, will be governed by the provisions of the intercreditor
agreement. The affirmative vote of secured parties holding at least the
following percentages of the combined exposure of all of the secured parties
will be sufficient to direct the collateral agent to exercise remedies or take
other actions:
o with respect to a trigger event resulting from an event of default
relating to payment, 33 1/3% of the combined exposure; or
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o with respect to any other trigger event or any other event or
circumstance requiring a vote of the secured parties, 50% of the
combined exposure.
TRIGGER EVENTS; EXERCISE OF REMEDIES
Each of the following events will be deemed a trigger event under the
intercreditor agreement if the collateral agent, upon direction from the
required percentage of secured parties, declares the event to be a trigger
event:
o the occurrence of an event of default under the indenture and the
acceleration of all or a portion of the principal amount of the
outstanding Securities; and
o the occurrence of an event of default under any other instrument
evidencing secured obligations and the acceleration of the secured
obligations in an aggregate principal amount in excess of $5 million;
If a trigger event occurs and continues, the collateral agent, upon the written
instructions of the required percentage of secured parties, will be authorized
to take any and all actions and to exercise any and all rights, remedies and
options available to it under the security documents.
APPLICATION OF PROCEEDS FOLLOWING A TRIGGER EVENT
Upon a foreclosure or other exercise of remedies following a trigger
event, the proceeds of any sale, disposition or other realization upon the
collateral will be distributed in the following order of priority:
(1) first, to the trustee, the letter of credit provider, the collateral
agent and the depositary bank, an amount sufficient to pay all administrative
costs due and payable to those parties under the intercreditor agreement and
the other financing documents;
(2) second, to the secured parties, an amount equal to the unpaid amount
of all secured obligations constituting principal, interest, premium (if any)
and fees due and payable to the secured parties;
(3) third, to the secured parties, an amount equal to the unpaid amount of
all other secured obligations due and payable to the secured parties as of the
date of the distribution; and
(4) fourth, to us, the assigning subsidiaries or our or their successors
and assigns or to whomever may be lawfully entitled, or as a court of competent
jurisdiction may direct, any surplus remaining after giving effect to clauses
(1) through (3) immediately above.
At the time the collateral agent is to make a distribution under clause
(2) above, and with the same priority as the distribution, the collateral agent
will deposit into a separate interest-bearing trust account funds up to the
amount available for drawing on the debt service reserve letter of credit,
calculated after giving effect to the redemption of securities with proceeds of
the distribution. The collateral agent will hold the funds in the account until
receipt of a written notice from the debt service reserve letter of credit
provider that either (a) the depositary bank has made a drawing on the debt
service reserve letter of credit, or (b) the debt service reserve letter of
credit has expired or terminated. Upon receipt of a notice specified in (a)
above, the collateral agent will distribute to the letter of credit provider
funds equal to the drawing's proportionate share of the funds in by the
account. Upon receipt of a notice specified in (b) above, the collateral agent
will distribute the balance of the funds on deposit in the account in
accordance with clauses (2), (3) and (4) above.
The proceeds of any sale, disposition or other realization with respect to
collateral held for the benefit of some but not all of the secured parties will
be applied to the payment of obligations owed to the secured parties for whose
benefit the collateral was held.
APPLICATION OF PROCEEDS
All (a) available cash flow representing loss proceeds, expropriation
proceeds, title insurance proceeds, buy-out proceeds, refinancing proceeds or
asset sale proceeds and (b) proceeds from our
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sale of all or a portion of our interests in any assigning subsidiary or the
sale by a assigning subsidiary of all or a portion of its interests in any
project company, in each case which are required to be applied to the
redemption of securities, will be distributed in the following order of
priority:
(1) first, to the trustee, the letter of credit provider, the collateral
agent and the depositary bank, an amount sufficient to pay all administrative
costs due and payable to these parties as of the date of the distribution;
(2) second, to the secured parties, an amount equal to the unpaid amount
of all secured obligations constituting principal, interest, premium (if any)
and fees due and payable to the secured parties as of the date of the
distribution;
(3) third, to the secured parties, an amount equal to the unpaid amount of
all other secured obligations due and payable to the secured parties as of the
date of the distribution; and
(4) fourth, to us, the assigning subsidiaries or our or their successors
and assigns or to whomever may be lawfully entitled or as a court of competent
jurisdiction may direct, any surplus remaining after giving effect to clauses
(1) through (3) immediately above.
At the time a distribution is to be made under clause (2) above, and with
the same priority as the distribution, the collateral agent will set aside
available funds in a separate interest-bearing trust account in an amount up to
the amount available for drawing on the debt service reserve letter of credit,
calculated after giving effect to the redemption of securities with proceeds of
the distribution. Upon a subsequent draw on the debt service reserve letter of
credit, the collateral agent will transfer funds from the separate account to
the letter of credit provider up to the amount drawn. Upon an expiration or
termination of the debt service reserve letter of credit, funds in the separate
account collateralizing the debt service reserve letter of credit will be
released and applied as set forth in clauses (2), (3) and (4) above.
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PLAN OF DISTRIBUTION
Each broker-dealer that receives new securities for its own account as a
result of market-making activities or other trading activities in connection
with the exchange offer must acknowledge that it will deliver a prospectus in
connection with any resale of the new securities. This prospectus, as it may be
amended or supplemented from time to time, may be used by participating
broker-dealers during the period referred to below in connection with resales
of new securities received in exchange for old securities if the old securities
were acquired by the participating broker-dealers for their own accounts as a
result of the market-making or other trading activities. We have agreed that
this prospectus, as it may be amended or supplemented from time to time, may be
used by a participating broker-dealer in connection with resales of new
securities for a period ending 120 days after the registration statement of
which this prospectus is a part has been declared effective (subject to
extension) or, if earlier, when all new securities have been disposed of by the
participating broker-dealer.
We will not receive any proceeds from the issuance of the new securities
offered by this prospectus. New securities received by broker-dealers for their
own accounts in connection with the exchange offer may be sold from time to
time in one or more transactions in the over-the-counter market, in negotiated
transactions, through the writing of options on the new securities or a
combination of these methods of resale, at market prices prevailing at the time
of resale, at prices related to prevailing market prices or at negotiated
prices. Any resale may be made directly to purchasers or to or through brokers
or dealers and/or the purchasers of any new Securities. Any broker-dealer that
resells new securities that were received by it for its own account in
connection with the exchange offer and any broker-dealer the participates in a
distribution of new Securities may be deemed to be an "underwriter" within the
meaning of the Securities Act, and any profit on any resale of new Securities
and any commissions or concessions received by any of those 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, a broker-dealer will not be deemed to admit that it
is a "underwriter" within the meaning of the Securities Act.
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UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
QUALIFICATIONS AND DEFINED TERMS
The following summary describes material United States federal income tax
considerations related to the acquisition, ownership and disposition of the
securities.
The summary is subject to the following qualifications:
o The summary is based on the Internal Revenue Code of 1986, as
amended, and regulations, rulings and judicial decisions as of the
date hereof, all of which may be repealed, revoked or modified with
possible retroactive effect;
o This discussion does not deal with holders that may be subject to
special tax rules, including:
o insurance companies,
o tax-exempt organizations,
o financial institutions,
o dealers in securities or currencies,
o holders whose functional currency is not the U.S. dollar, and
o holders who will hold the securities as a hedge against currency
risks or as part of a straddle, synthetic security, conversion
transaction or other integrated investment comprised of the
securities and one or more other investments;
o The summary is applicable only to purchasers that acquire the
securities at the initial offering price and who will hold the
securities as capital assets within the meaning of Section 1221 of
the Internal Revenue Code;
o The summary is for general information only and does not address all
aspects of United States federal income taxation that may be relevant
to holders of the securities in light of their particular
circumstances; and
o The summary does not address any tax consequences arising under the
laws of any state, local or foreign taxing jurisdiction.
Accordingly prospective holders should consult their own tax advisors as to the
particular tax consequences to them of acquiring, holding or disposing of the
securities.
As used in this discussion, the term "United States holder" means a
beneficial owner of a security that is (1) a citizen or resident of the United
States for U.S. federal income tax purposes, (2) a corporation created or
organized under the laws of the United States, any State or the District of
Columbia, (3) an estate the income of which is subject to United States federal
income tax without regard to its source or (4) a trust if a court within the
United States is able to exercise primary supervision over the administration
of the trust and one or more United States persons have the authority to
control all substantial decisions of the trust. A "non-United States holder" is
any beneficial holder of a security that is not a United States holder.
INCOME TAX CONSIDERATIONS FOR UNITED STATES HOLDERS
TAX CONSEQUENCES OF THE EXCHANGE OFFER
The exchange of an old security for a new security in the exchange offer
will not constitute a "significant modification" of the old security for United
States federal income tax purposes and, accordingly, the new security will be
treated as a continuation of the old security in the hands of the holder. As a
result, there will be no United States federal income tax consequences to a
United States holder who exchanges an old security for the new security in the
exchange offer and the holder will have the same adjusted tax basis and holding
period in the new security as it had in the old security immediately before the
exchange.
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ORIGINAL ISSUE DISCOUNT AND PAYMENTS OF INTEREST
The old securities were not, and the new securities will not be, issued
with more than a
de minimis amount of original issue discount. Accordingly, interest on a
security generally will be taxable to a United States holder as ordinary income
at the time it accrues or is received in accordance with the United States
holder's method of accounting for U.S. federal income tax purposes.
DISPOSITION OF SECURITIES
Upon the sale, exchange, redemption, retirement or other disposition of a
security, a United States holder generally will recognize gain or loss equal to
the difference between (1) the amount realized upon the sale, exchange,
redemption, retirement or other disposition (not including amounts attributable
to accrued but unpaid interest, which will be taxable as such) and (2) the
holder's adjusted tax basis in the security. A United States holder's tax basis
in a security will, in general, be the United States holder's cost for the
security. The gain or loss will be capital gain or loss. Capital gain
recognized by an individual investor upon a disposition of a security that has
been held for more than 12 months will generally be subject to a maximum tax
rate of 20% or, in the case of a security that has been held for 12 months or
less, will be subject to tax at ordinary income tax rates.
INCOME TAX CONSIDERATIONS FOR NON-UNITED STATES HOLDERS
PAYMENTS OF PRINCIPAL AND INTEREST
Under present U.S. federal income tax law, subject to the discussion of
backup withholding and information reporting below, payments of principal of
and interest on the securities to any non-United States holder will not be
subject to U.S. federal income or withholding tax so long as the following
conditions are satisfied:
o the non-United States holder does not actually or constructively own
10% or more of the total combined voting power of all classes of our
membership interests entitled to vote;
o the non-United States holder is not a bank receiving interest under a
loan agreement entered into in the ordinary course of its trade or
business;
o the non-United States holder is not a controlled foreign corporation
that is related to us (directly or indirectly) through equity
ownership;
o the interest payments are not effectively connected with a United
States trade or business; and
o the following certification requirements are met:
o the beneficial owner of the security certifies on IRS Form W-8
or a substantially similar substitute form, under penalties of
perjury, that it is not a United States person and provides its
name and address, and
o (a) the beneficial owner files the form with the withholding
agent or (b) in the case of a security held by a securities
clearing organization, bank or other financial institution that
holds customers' securities in the ordinary course of its trade
or business and holds the security, the financial institution
certifies to us or our agent under penalties of perjury that the
statement has been received from the beneficial owner by it or by
a financial institution between it and the beneficial owner and
furnishes the withholding agent with a copy of the certification.
DISPOSITION OF SECURITIES
Under present U.S. federal income tax law, subject to the discussion of
backup withholding and information reporting below, a non-United States holder
will not be subject to U.S. federal income tax on gain realized on the sale,
exchange, redemption, retirement or other disposition of a security, unless (1)
the gain is effectively connected with a trade or business carried on by the
holder within the United States or, if a treaty applies, is generally
attributable to a United States permanent
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establishment maintained by the holder, or (2) the holder is an individual who
is present in the United States for 183 days or more in the taxable year of
disposition and other requirements are met.
BACKUP WITHHOLDING AND INFORMATION REPORTING
In general, payments of interest and the proceeds of the sale, exchange,
redemption, retirement or other disposition of the securities payable by a U.S.
paying agent or other U.S. intermediary will be subject to information
reporting. In addition, backup withholding at a rate of 31% will apply to these
payments if the holder fails to provide an accurate taxpayer identification
number in the case of a United States holder or the certification described
above (in the case of a non-United States holder) or other evidence of exempt
status or fails to report all interest and dividends required to be shown on
its U.S. federal income tax returns. Some categories of United States Holders
(including, among others, corporations) and non-United States holders that
comply with certification requirements are not subject to backup withholding.
Any amount paid as backup withholding will be creditable against the holder's
U.S. federal income tax liability, so long as the required information is
timely furnished to the Internal Revenue Service. Holders of securities should
consult their tax advisors as to their qualification for exemption from backup
withholding and the procedure for obtaining an exemption. On October 6, 1997,
new Treasury Regulations were issued that generally modify the information
reporting and backup withholding rules applicable to specified payments made
after December 31, 1999. In general, the new regulations would not
significantly alter the present rules discussed above.
LEGAL MATTERS
The validity of the new securities will be passed upon for us by Latham &
Watkins, 885 Third Avenue, Suite 1000, New York, New York 10022.
EXPERTS
Our consolidated financial statements as of December 31, 1998 and 1997,
and the related consolidated statements of operations and cash flows for each
of the three years in the period ended December 31, 1998, included in this
prospectus have been audited by Deloitte & Touche LLP, independent auditors, as
stated in their report appearing in this prospectus, and are included in
reliance upon the report of such firm given upon their authority as experts in
accounting and auditing.
The consolidated financial statements of Magma Power Company and
subsidiaries and Falcon Seaboard Resources, Inc and subsidiaries as of December
31, 1998 and 1997 and the related consolidated statements of operations and
cash flows for each of the three years in the period ended December 31, 1998
included in this prospectus have been audited by Deloitte & Touche LLP,
independent auditors, as stated in their reports appearing in this prospectus,
and are included in reliance upon the reports of such firm given upon their
authority as experts in accounting and auditing.
POWER GENERATION PROJECTS INDEPENDENT ENGINEER
Fluor Daniel, Inc. prepared the power generation projects independent
engineer's report dated February 24, 1999, which is included as Appendix A to
this prospectus. Fluor Daniel's report has been included in this prospectus in
reliance upon the conclusions of Fluor Daniel and upon the firm's experience in
preparing independent engineer's reports for power projects.
NATURAL GAS PROJECTS INDEPENDENT ENGINEER
R.W. Beck, Inc. prepared the natural gas projects independent engineer's
report dated February 24, 1999, which is included as Appendix B to this
prospectus. R.W. Beck's report has been included in this prospectus in reliance
upon the conclusions of R.W. Beck and upon the firm's experience in preparing
independent engineer's reports for natural gas-fired power projects.
125
<PAGE>
GEOTHERMAL PROJECTS INDEPENDENT ENGINEER
Fluor Daniel also prepared the geothermal projects independent engineer's
report dated February 17, 1999, which is included as Appendix C to this
prospectus. Fluor Daniel's report has been included in this prospectus in
reliance upon the conclusions of Fluor Daniel and upon the firm's experience in
preparing independent engineer's reports for geothermal power projects.
CONSULTANTS' REPORTS
Henwood Energy Services has prepared the power market consultant's report
dated February 11, 1999 included as Appendix D to this prospectus. You should
read this report in its entirety for information with respect to industry and
regulatory matters affecting the sales of electricity by some of the projects
and the related subjects discussed in the report. Henwood's report has been
included in this prospectus in reliance upon the conclusions of Henwood and
upon the firm's experience in providing business advisory and other services
and market forecasts in electricity and gas to international firms and public
authorities.
GeothermEx, Inc. prepared the geothermal resource consultant's report
dated February 1999 included as Appendix E to this prospectus. You should read
this report in its entirety for information on the sufficiency of the
geothermal resources available for use and for conversion to electrical power
by the Imperial Valley projects and the related subjects discussed in the
report. GeothermEx's report has been included in this prospectus in reliance
upon the conclusions of GeothermEx and upon the firm's experience in preparing
consultant's reports for geothermal projects.
WHERE YOU CAN FIND MORE INFORMATION
We have filed a registration statement on Form S-4 with the Securities and
Exchange Commission under the Securities Act with respect to our offering of
the new securities. This prospectus does not contain all of the information in
the registration statement. You will find additional information about us and
the new securities in the registration statement. Any statement made in this
prospectus concerning the provisions of legal documents are not necessarily
complete and you should read the documents that are filed as exhibits to the
registration statement.
We are subject to the informational requirements of the Exchange Act and
file periodic reports, registration statements, proxy statements and other
information with the Securities and Exchange Commission. You may inspect and
copy the registration statement, including exhibits, and our periodic reports,
registration statements, proxy statements and other information we file with
the Securities and Exchange Commission at the Public Reference Section of the
Securities and Exchange Commission at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and at the regional offices of the
Securities and Exchange Commission located at Seven World Trade Center, 13th
Floor, New York, New York 10048 and 500 West Madison Street, Suite 1400,
Chicago, Illinois 60661. Copies of this material can be obtained from the
Public Reference Section of the Securities and Exchange Commission at Room
1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 at
prescribed rates. The Securities and Exchange Commission maintains a web site
that contains reports, proxy and information statements and other materials
that are filed through the Securities and Exchange Commission's Electronic Data
Gathering, Analysis and Retrieval (EDGAR) system. This Web site can be accessed
at http://www.sec.gov.
126
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----------
<S> <C>
Consolidated Financial Statements of CE Generation, LLC:
Independent Auditors' Report ........................................... F-3
Consolidated Balance Sheets as of December 31, 1998 and 1997 ........... F-4
Consolidated Statements of Operations for the Three Years Ended
December 31, 1998, 1997 and 1996 ...................................... F-5
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1998, 1997 and 1996 ...................................... F-6
Notes to Consolidated Financial Statements ............................. F-7 - F-25
</TABLE>
<TABLE>
<S> <C>
Interim Consolidated Financial Statements of CE Generation, LLC:
Consolidated Balance Sheets as of September 30, 1999
and December 31, 1998 ................................................. F-26
Consolidated Statements of Operations for the Nine
Months Ended September 30, 1999 and 1998 .............................. F-27
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1999 and 1998 .............................. F-28
Notes to Consolidated Financial Statements ............................. F-29 - F-32
</TABLE>
<TABLE>
<S> <C>
Consolidated Financial Statements of Magma Power Company:
Independent Auditors' Report ........................................... F-33
Consolidated Balance Sheets as of December 31, 1998 and 1997 ........... F-34
Consolidated Statements of Operations for the Three Years Ended
December 31, 1998, 1997 and 1996 ...................................... F-35
Consolidated Statements of Stockholders Equity for the Three Years Ended
December 31, 1998, 1997 and 1996 ...................................... F-36
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1998, 1997 and 1996 ...................................... F-37
Notes to Consolidated Financial Statements ............................. F-38 - F-49
</TABLE>
<TABLE>
<S> <C>
Interim Consolidated Financial Statements of Magma Power Company:
Consolidated Balance Sheets as of September 30, 1999
and December 31, 1998 ............................................... F-50
Consolidated Statements of Operations for the Nine
Months Ended September 30, 1999 and 1998 ............................ F-51
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1999 and 1998 ............................ F-52
Notes to Consolidated Financial Statements ........................... F-53
</TABLE>
F-1
<PAGE>
<TABLE>
<CAPTION>
PAGE
------------
<S> <C>
Consolidated Financial Statements of Falcon Seaboard Resources, Inc.:
Independent Auditors' Report .................................................. F-54
Consolidated Balance Sheets as of December 31, 1998 and 1997 .................. F-55
Consolidated Statements of Operations for the Three Years Ended
December 31, 1998, 1997 and 1996 ............................................. F-56
Statements of Changes in Stockholders Equity for the Three Years Ended
December 31, 1998, 1997 and 1996 ............................................. F-57
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1998, 1997 and 1996 ............................................. F-58
Notes to Consolidated Financial Statements .................................... F-59 - F-66
</TABLE>
<TABLE>
<S> <C>
Interim Consolidated Financial Statements of Falcon Seaboard Resources, Inc.:
Consolidated Balance Sheets as of September 30, 1999
and December 31, 1998 ...................................................... F-67
Consolidated Statements of Operations for the Nine
Months Ended September 30, 1999 and 1998 ................................... F-68
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1999 and 1998 ................................... F-69
Notes to Consolidated Financial Statements .................................. F-70
</TABLE>
<TABLE>
<S> <C>
Unaudited Pro Forma Condensed Financial Data of Magma Power Company:
Unaudited Pro Forma Condensed Statement of Operations for the Year Ended
December 31, 1998 ............................................................ F-72
Unaudited Pro Forma Condensed Statement of Operations for the Nine Months Ended
September 30, 1999 ........................................................... F-73
Notes to Unaudited Pro Forma Condensed Financial Data ......................... F-74
</TABLE>
F-2
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors
CE Generation, LLC
We have audited the accompanying consolidated balance sheets of CE
Generation, LLC as of December 31, 1998 and 1997, and the related consolidated
statements of operations and cash flows for each of the three years in the
period ended December 31, 1998. These financial statements are the
responsibility of CE Generation, LLC's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of CE Generation, LLC as of
December 31, 1998 and 1997 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.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
January 28, 1999 (February 22, 1999 as to the first paragraph in Note 1
and March 3, 1999 as to Note 15)
* * * * *
F-3
<PAGE>
CE GENERATION, LLC
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
ASSETS
Cash and cash equivalents .......................................... $ 25,774 $ 23,684
Restricted cash .................................................... 26,877 6,597
Accounts receivable ................................................ 67,629 53,072
Prepaid expenses ................................................... 11,677 10,222
Inventory .......................................................... 15,442 12,251
Deferred income taxes .............................................. 31,753 32,898
---------- ----------
Other assets ....................................................... 4,629 6,399
---------- ----------
Total current assets .............................................. 183,781 145,123
Restricted cash .................................................... 101,676 310
Properties, plants, contracts and equipment, net ................... 893,492 932,207
Equity investments ................................................. 125,036 131,207
Excess of cost over fair value of net assets acquired, net ......... 310,700 322,581
Note receivable from related party (Note 7) ........................ 140,520 --
Deferred financing charges and other assets ........................ 27,180 29,446
---------- ----------
Total assets .................................................... $1,782,385 $1,560,874
========== ==========
LIABILITIES AND EQUITY
LIABILITIES:
Accounts payable and other accrued liabilities ..................... $ 37,940 $ 45,345
Current portion of long term debt .................................. 72,104 119,743
---------- ----------
Total current liabilities ....................................... 110,044 165,088
Project loan ....................................................... 76,261 90,529
Salton Sea notes and bonds ......................................... 568,980 341,816
Notes payable to related party ..................................... 247,681 247,812
Deferred income taxes .............................................. 240,602 247,891
Other long term liabilities ........................................ 1,870 3,598
---------- ----------
Total liabilities ............................................... 1,245,438 1,096,734
Commitments and contingencies (Notes 9 and 12)
Net investment and advances ........................................ 536,947 464,140
---------- ----------
Total liabilities and equity ....................................... $1,782,385 $1,560,874
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE>
CE GENERATION, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
REVENUE:
Sales of electricity and steam .................. $395,560 $381,458 $281,307
Equity earnings in subsidiaries ................. 10,732 14,542 4,263
Interest and other income ....................... 29,883 11,138 19,273
-------- -------- --------
Total revenues ................................ 436,175 407,138 304,843
-------- -------- --------
COST AND EXPENSES:
Plant operations ................................ 114,092 119,973 94,245
General and admininstration ..................... 4,963 4,380 3,503
Depreciation and amortization ................... 96,818 88,504 72,533
Interest expense ................................ 74,653 80,907 77,669
Less interest capitalized ....................... (347) -- (4,805)
-------- -------- --------
Total expenses ................................ 290,179 293,764 243,145
-------- -------- --------
Income before provision for income taxes ......... 145,996 113,374 61,698
Provision for income taxes ....................... 52,218 43,378 15,487
-------- -------- --------
Net income ....................................... $ 93,778 $ 69,996 $ 46,211
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE>
CE GENERATION, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------ ------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................. $ 93,778 $ 69,996 $ 46,211
ADJUSTMENTS TO RECONCILE CASH FLOWS FROM OPERATING
ACTIVITIES:
Depreciation and amortization ............................... 96,818 88,504 72,533
Provision for deferred income taxes ......................... (6,144) 4,280 3,874
Equity earnings in subsidiaries ............................. (10,732) (14,542) (4,263)
CHANGES IN OTHER ITEMS:
Accounts receivable ....................................... (14,557) (2,005) (1,112)
Decrease (increase) in inventory .......................... (3,191) 2,893 (4,993)
Accounts payable and other accrued liabilities ............ (9,133) 4,837 (26,540)
Other assets .............................................. 7,524 4,769 32,990
---------- ---------- ----------
Net cash flows from operating activities ............... 154,363 158,732 118,700
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................ (46,222) (21,676) (90,734)
Purchase of Falcon Seaboard and Partnership
Interest, net of cash acquired ............................ -- -- (264,324)
Distributions from equity investments ....................... 16,903 23,960 8,295
Decrease (increase) in restricted cash ...................... (101,366) 15,120 41,786
---------- ---------- ----------
Net cash flows from investing activities ............... (130,685) 17,404 (304,977)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of Salton Sea notes and bonds ..................... (106,938) (90,228) (48,106)
Proceeds from Salton Sea notes and bonds .................... 285,000 -- 135,000
Note receivable from related party .......................... (140,520) -- --
Repayment of note payable to related party .................. (131) -- (480)
Repayment of project loans .................................. (12,805) (11,237) (107,906)
Deferred charge relating to debt financing .................. (4,943) (11,623) (11,749)
Advances (to) from MEHC, net ................................ (20,971) (60,759) 175,267
Decrease (increase) in restricted cash ...................... (20,280) (97) 26,915
---------- ---------- ----------
Net cash flows from financing activities ............... (21,588) (173,944) 168,941
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents ......... 2,090 2,192 (17,336)
Cash and cash equivalents at beginning of year ............... 23,684 21,492 38,828
---------- ---------- ----------
Cash and cash equivalents at end of year ..................... $ 25,774 $ 23,684 $ 21,492
========== ========== ==========
SUPPLEMENTAL DISCLOSURE:
Interest paid ............................................... $ 73,283 $ 72,846 $ 64,244
========== ========== ==========
Income taxes paid ........................................... 58,362 39,098 11,613
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(AMOUNTS IN THOUSANDS)
1. BUSINESS
MidAmerican Energy Holdings Company ("MEHC" and formerly CalEnergy
Company, Inc.) completed a strategic restructuring in conjunction with its
acquisition of MidAmerican Energy Holdings Company in which MEHC's common stock
interests in Magma Power Company, Falcon Seaboard Resources, Inc. and
California Energy Development Corporation, and their subsidiaries (which own
the geothermal and natural gas-fired combined cycle cogeneration facilities
described below), were contributed by MEHC to the newly created CE Generation,
LLC. This restructuring was completed in February 1999.
BASIS OF PRESENTATION--These consolidated financial statements of CE
Generation, LLC reflect the consolidated financial statements of Magma Power
Company and subsidiaries (excluding wholly-owned subsidiaries retained by
MEHC), Falcon Seaboard Resources, Inc. and subsidiaries and Yuma Cogeneration
Associates, each a wholly-owned subsidiary. The consolidated financial
statements present the financial position, results of operations and cash flows
of CE Generation as if CE Generation was a separate legal entity for all
periods presented. CE Generation has accounted for MEHC's contribution of
assets and liabilities to CE Generation in accordance with Interpretation No.
39 of APB Opinion No. 16, Transfers and Exchanges Between Companies Under
Common Control. Accordingly, MEHC's basis in these assets and liabilities,
which reflects the acquisitions discussed in Note 3, has been carried over and
reflected in CE Generation's financial statements. All material intercompany
transactions and balances have been eliminated in consolidation.
GENERAL--CE Generation is engaged in the independent power business. The
following table sets out information concerning CE Generation's projects:
<TABLE>
<CAPTION>
COMMERCIAL
PROJECT FUEL OPERATION CAPACITY LOCATION
- ------------------ ------------ ----------- ---------- -------------
<S> <C> <C> <C> <C>
Vulcan Geothermal 1986 34 MW California
Del Ranch Geothermal 1989 38 MW California
Elmore Geothermal 1989 38 MW California
Leathers Geothermal 1990 38 MW California
Salton Sea I Geothermal 1987 10 MW California
Salton Sea II Geothermal 1990 20 MW California
Salton Sea III Geothermal 1989 49.8 MW California
Salton Sea IV Geothermal 1996 39.6 MW California
Salton Sea V Geothermal 2000 49 MW California
CE Turbo Geothermal 2000 10 MW California
Power Resources Gas 1988 200 MW Texas
Yuma Gas 1994 50 MW Arizona
Saranac Gas 1994 240 MW New York
Norcon Gas 1992 80 MW Pennsylvania
</TABLE>
Vulcan, Del Ranch, Elmore, Leathers and CE Turbo are referred to as the
Partnership Projects. Salton Sea I, II, III, IV and V are referred as the
Salton Sea Projects. The Partnership Projects and the Salton Sea Projects are
collectively referred to as the Imperial Valley Projects. Power Resources,
Yuma, Saranac and Norcon are referred to as the Gas Projects.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CASH EQUIVALENTS--CE Generation considers all investment instruments
purchased with an original maturity of three months or less to be cash
equivalents. Restricted cash is not considered a cash equivalent.
F-7
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
RESTRICTED CASH--The restricted cash balance is composed of restricted
accounts for debt service, capital expenditures and major maintenance
expenditures. The debt service funds are legally restricted as to their use and
require the maintenance of specific minimum balances equal to the next debt
service payment.
The capital expenditure funds are restricted for use in the construction
of Salton Sea V, the CE Turbo Project and the construction of new brine
facilities at the Imperial Valley Projects, which resulted from the sale on
October 13, 1998 by Salton Sea Funding Corporation of $285,000 aggregate amount
of 7.475% Senior Secured Series F Bonds due November 30, 2018 (see Note 7).
WELL COSTS--The cost of drilling and equipping production wells and other
direct costs, are capitalized and amortized on a straight-line basis over their
estimated useful lives when production commences. The estimated useful lives of
production wells are twenty years.
DEFERRED WELL AND REWORK COSTS--Geothermal well rework costs are deferred
and amortized over the estimated period between reworks ranging from 18 months
to 24 months. These deferred costs, net of accumulated amortization, are $6,709
and $4,811 at December 31, 1998 and 1997, respectively, and are included in
other assets.
PROPERTIES, PLANTS, CONTRACTS, EQUIPMENT AND DEPRECIATION--The cost of
major additions and betterments are capitalized, while replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage value if
applicable, is computed on the straight line method over the estimated useful
life of 30 years. Depreciation of furniture, fixtures and equipment is computed
on the straight line method over the estimated useful lives of the related
assets, which range from 3 to 10 years.
The acquisitions of Magma Power Company, Falcon Seaboard Resources, Inc.
and Edison Mission Energy's partnership interests by CE Generation have been
accounted for as purchase business combinations. All identifiable assets
acquired and liabilities assumed were assigned a portion of the cost of
acquiring the respective companies equal to their values at the date of the
acquisition and includes power sales agreements which are amortized separately
on a straight-line basis over (1) for the Edison Partnership interests and
Magma acquisitions, the remaining portion of the scheduled price periods of the
power sales agreements which range from 1 to 5 years, (2) for the Edison
Partnership interests and Magma acquisitions, the 20 year avoided cost periods
of the power sales agreements and (3) over the remaining contract periods which
range from 7 to 30 years.
EQUITY INVESTMENTS--CE Generation's investments in Saranac and Norcon are
accounted for using the equity method of accounting since CE Generation has the
ability to exercise significant influence over the investees' operating and
financial policies through its managing general partnership interests. At
December 31, 1998 and 1997, the carrying amount of CE Generation's investment
in Saranac differs from its underlying equity in net assets of Saranac by
$108,788 (net of accumulated amortization of $24,824) and $119,060 (net of
accumulated amortization of $14,552), respectively. This difference, which
represents the adjustment to record the fair value of the investment at the
date of acquisition, is being amortized on a straight-line basis over
approximately 13 years, the remaining portion of the power sales agreement at
the date of acquisition.
EXCESS OF COST OVER FAIR VALUE--Total acquisition costs in excess of the
fair values assigned to the net assets acquired are amortized over a 40 year
period for the Magma acquisition and a 25 year period for the Falcon Seaboard
acquisition, both using the straight line method. Accumulated amortization was
$32,857 and $22,985 at December 31, 1998 and 1997, respectively.
F-8
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
MAINTENANCE AND REPAIR RESERVES--Major maintenance and repair reserves are
recorded monthly based on CE Generation's long-term scheduled major maintenance
plans for the Gas Projects and included in accrued liabilities. Other
maintenance and repairs are charged to expense as incurred.
CAPITALIZATION OF INTEREST AND DEFERRED FINANCING COSTS--Prior to the
commencement of operations, interest is capitalized on the costs of the plants
and geothermal resource development to the extent incurred. Capitalized
interest and other deferred charges are amortized over the lives of the related
assets.
Deferred financing costs are amortized over the term of the related
financing using the effective interest method.
REVENUE RECOGNITION--Revenues are recorded based upon electricity and
steam delivered to the end of the month. See Note 5 for contractual terms of
power sales agreements. Royalties earned from providing geothermal resources to
power plants operated by other geothermal power producers are recorded when
delivered.
INCOME TAXES--CE Generation has historically been included in the
consolidated income tax returns of MEHC. CE Generation's provision for income
taxes is computed on a separate return basis. CE Generation recognizes deferred
tax assets and liabilities based on the difference between the financial
statement and tax bases of assets and liabilities using estimated tax rates in
effect for the year in which the differences are expected to reverse.
FINANCIAL INSTRUMENTS--CE Generation utilizes swap agreements to manage
market risks and reduce its exposure resulting from fluctuation in interest
rates. For interest rate swap agreements, the net cash amounts paid or received
on the agreements are accrued and recognized as an adjustment to interest
expense. CE Generation's practice is not to hold or issue financial instruments
for trading purposes. These instruments are either exchange traded or with
counterparties of high credit quality; therefore, the risk of nonperformance by
the counterparties is considered to be negligible.
Fair values of financial instruments are estimated based on quoted market
prices for debt issues actively traded or on market prices of similar
instruments and/or valuation techniques using market assumptions.
IMPAIRMENT OF LONG-LIVED ASSETS--CE Generation reviews long-lived assets
and certain identifiable intangibles 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.
START-UP COSTS--In 1998, CE Generation adopted SOP No. 98-5, Reporting on
the Costs of Start-Up Activities, which requires costs of start-up activities
and organization costs be expensed as incurred. Such adoption had no
significant effect on CE Generation.
CHANGE IN ACCOUNTING ESTIMATE--During the year ended December 31, 1998, CE
Generation modified the amortization method to amortize the fair value
adjustments associated with the scheduled price periods of the four plants
acquired in the Imperial Vally. CE Generation modified its amortization method
from the weighted average of the scheduled price periods to amortization of the
fair value adjustments over the scheduled price periods of the individual plant.
The change in accounting estimate included increasing the accumulated
amortization of the aggregate fair value adjustment associated with the
scheduled price periods of the four plants acquired in the Imperial Valley. The
impact of the change was to decrease 1998 net income by $4.7 million. This
change will not have a significant impact on future periods as the scheduled
price period terminates in 1999.
F-9
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
USE OF ESTIMATES--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.
ACCOUNTING PRONOUNCEMENTS--In June 1998, the FASB issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, which established
accounting and reporting standards for derivative instruments and for hedging
activities. It requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. This statement is effective for all fiscal quarters
of fiscal years beginning after June 15, 2000. CE Generation has not yet
determined the impact of this accounting pronouncement.
3. ACQUISITIONS
On August 7, 1996, MEHC completed the acquisition of Falcon Seaboard
Resources, Inc. (FSRI) for approximately $226,000. The transaction was
accounted for as a purchase business combination. All identifiable assets
acquired and liabilities assumed were assigned a portion of the cost of
acquiring FSRI, equal to the fair values at the date of acquisition.
On April 17, 1996, MEHC completed the acquisition of Edison Mission
Energy's partnership interests (the "Partnership Interest Acquisition") in four
geothermal operating facilities in California for approximately $70,000. The
four projects, Vulcan, Del Ranch, Leathers and Elmore are located in the
Imperial Valley of California. Prior to this transaction, CE Generation was a
50% owner of these facilities and consolidated these entities using the
proportional consolidation method. The Partnership Interest Acquisition has
been accounted for as a purchase business combination. All identifiable assets
acquired and liabilities assumed were assigned a portion of the cost of
acquiring the Partnership Interest, equal to their fair values at the date of
the acquisition.
On a pro forma basis for the year ended December 31, 1996, assuming these
transactions were effected January 1, 1996, CE Generation's revenue and net
income would have been $374,973 and $52,586, respectively.
4. EQUITY INVESTMENTS
CE Generation indirectly holds noncontrolling general and limited
partnership interests in two partnerships, Saranac Power Partners, L.P.
(Saranac) and Norcon Power Partners, L.P. (Norcon) which were formed to build,
own and operate natural gas fired combined cycle cogeneration facilities. The
lenders to these partnerships have recourse only against these facilities and
the income and revenues therefrom. CE Generation has a current approximate 45%
economic interest in Saranac and a current 20% economic interest in Norcon. CE
Generation will have an approximate 80% economic interest in each of these
partnerships after outside limited partners' returns, as defined in the
Partnership Agreements, are achieved. The Saranac outside limited partners, TPC
Saranac and General Electric Capital Company, must achieve after tax returns of
approximately 8.35% and 7.252%, respectively. Norcon's partner, TPC Norcon,
must achieve a pre-tax return of approximately 16.5%.
The following is a summary of aggregated financial information for all
investments owned by CE Generation which are accounted for under the equity
method at December 31, 1998 and 1997:
F-10
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Assets ............... $ 414,546 $ 434,028
Liabilities .......... 306,234 326,230
Net income ........... 44,338 47,478
</TABLE>
Saranac's total revenue for the years ended December 31, 1998, 1997 and
1996 were $141,876, $146,954 and $140,396, respectively. Norcon's total
revenues for the years ended December 31, 1998, 1997 and 1996 were $52,268,
$50,908 and $44,893, respectively.
Saranac has project financing through a 14 year note payable agreement
with a lender with a principal amount outstanding of $189,282 at December 31,
1998. The note agreement is collateralized by all of the assets of Saranac.
Saranac is restricted by the terms of the payable agreement from making
distributions or withdrawing any capital amounts without the consent of the
lender. Under terms of the note payable agreement, distributions may be made to
the partners in accordance with the terms of the Saranac partnership agreement.
Distributions are made monthly and quarterly to the extent of the partnership's
excess cash balances.
Each of the Saranac partners has an interest in cash distributions by
Saranac which changes when certain after-tax rates of return are achieved by GE
Capital and the TPC Saranac partners on their contributions to Saranac. The
cash distributions of Saranac are divided into three levels:
(1) distributions in fixed amounts payable during the first 15 years of
operation of the Saranac project, which are applied first to pay debt service
and other amounts due under the Saranac project financing documents and any
refinancing loans, with the remainder paid to GE Capital to enable it to
achieve a certain base rate of return; (2) distributions of the Saranac
available cash remaining after payment of the level 1 distributions during the
first 15 years of operation of the Saranac project: (3) distributions after the
first 15 years of operation of the Saranac project. During the first 15 years
of operation of the Saranac project, Saranac Energy will receive 63.51% of the
level 2 distributions until TPC Saranac partners achieve an 8.35% rate of
return and, after such return is achieved (which we expect to occur in 2000),
Saranac Energy will receive 81.18% of the level 2 distributions. After the
first 15 years of operation of the Saranac project, Saranac Energy will receive
68% of the level 3 distributions until GE Capital achieves a certain
supplemental rate of return and, thereafter, Saranac Energy will receive 76% of
the level 3 distributions.
Norcon has project financing under a note payable comprised of senior and
junior debt with a total principal amount outstanding at December 31, 1998 of
$104,524. The note payable is collateralized by all of Norcon's assets. Under
the terms of the note payable agreement, Norcon is allowed to make
distributions after certain funds have been established; principally, a minimum
of $500 must be maintained in the Project's revenue account. Distributions are
made monthly and quarterly to the extent of the partnership's excess cash
balances.
There were no undistributed earnings in equity investments at December 31,
1998.
F-11
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
5. PROPERTIES, PLANTS, CONTRACTS AND EQUIPMENT
Properties, plants, contracts and equipment comprise the following at
December 31:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Power plants ............................................ $ 678,710 $ 659,369
Wells and resource development .......................... 137,399 124,500
Power sales agreements .................................. 287,653 287,653
Licenses and equipment .................................. 41,671 41,471
--------- ---------
Total operating facilities ........................... 1,145,433 1,112,993
Less accumulated depreciation and amortization .......... (270,244) (184,788)
--------- ---------
Net operating facilities ................................ 875,189 928,205
--------- ---------
Construction in progress:
Other development ...................................... 18,303 4,002
--------- ---------
Total ................................................ $ 893,492 $ 932,207
========= =========
</TABLE>
SIGNIFICANT CUSTOMERS AND CONTRACTS--All of CE Generation's current sales
of electricity from the Imperial Valley Projects, which comprise approximately
74% both of 1998 and 1997 electricity and steam revenues, are to Southern
California Edison Company (Edison) and are under long-term power purchase
contracts. Accounts receivable, which are primarily from Edison, are primarily
uncollateralized receivables from long-term power purchase contracts described
below. If the customers were unable to perform, CE Generation could incur an
accounting loss equal to the entire receivable balance, or $67,629 and $53,072
at December 31, 1998 and 1997, respectively.
GEOTHERMAL PROJECTS--The current Partnership Projects sell all electricity
generated by the respective plants pursuant to four long-term standard offer
no. 4, or SO4, agreements between the Projects and Edison that are based on this
standard form. These SO4 agreements provide for capacity payments, capacity
bonus payments and energy payments. Edison makes fixed annual capacity and
capacity bonus payments to the Projects to the extent that capacity factors
exceed certain benchmarks. The price for capacity and capacity bonus payments is
fixed for the life of the SO4 Agreements. Energy is sold at increasing scheduled
rates for the first ten years after firm operation and thereafter at a rate
which is based on the cost that Southern California Edison avoids by purchasing
energy from the project instead of obtaining the energy from other sources.
Southern California Edison's avoided cost is currently determined by an approved
interim formula which adjusts historic costs by an inflation/deflation factor
representing monthly changes in the cost of natural gas at the California border
and adjustment factors based on the time the day, week and year in which the
energy is delivered. Consequently, under this methodology, energy payments under
the SO4 agreements will fluctuate based on the time of generation and monthly
changes in average fuel costs in the California energy market. Legislation
recently adopted in California establishes that the price qualifying facilities
receive as energy payments would be modified from the current short-run avoided
cost basis to the clearing price established by the PX once specified conditions
are met. As the main condition, the legislation requires that the California
Public Utilities Commission must first issue an order determining that the PX is
functioning properly for the purposes of determining the short-run avoided cost
energy payments to be made to non-utility power generators. Additionally, a
project company may, upon appropriate notice to Southern California Edison,
exercise a one-time option to elect to thereafter receive energy payments based
upon the clearing price from the PX.
The PX is a nonprofit public benefit corporation formed under California
law to provide a competitive marketplace where buyers and sellers of power,
including utilities, end-use customers,
F-12
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
independent power producers and power marketers, complete wholesale trades
through an electronic auction. The PX currently operates two markets: (1) a day
ahead market which is comprised of twenty-four separate concurrent auctions for
each hour of the following day and (2) an hour ahead market for each hour of
each day for which bids are due two hours before each hour. In each market, the
PX receives bids from buyers and sellers and, based on the bids, establishes the
market clearing price for each hour and schedules deliveries from sellers whose
bids did not exceed the market clearing price to buyers whose bids were not less
than the market clearing price. All trades are executed at the market clearing
price.
The scheduled energy price periods of the Partnership Projects SO4
agreements extended until February 1996, December 1998 and December 1998 for
each of the Vulcan, Del Ranch and Elmore Partnerships, respectively, and extend
until December 1999 for the Leathers Partnership. Del Ranch and Elmore
Partnerships' SO4 agreements provided for energy rates of 14.6 cents per kWh in
1998. Leathers Partnership SO4 agreement provides for an energy rate of 14.6
cents per kWh in 1998 and 15.6 cents per kWh in 1999. The weighted average
energy rate for all of the Partnership Projects' SO4 Agreements was 11.7 cents
per kWh in 1998.
Salton Sea I sells electricity to Edison pursuant to a 30-year negotiated
power purchase agreement, as amended (the Salton Sea I PPA), which provides for
capacity and energy payments. The energy payment is calculated using a Base
Price which is subject to quarterly adjustments based on a basket of indices.
The time period weighted average energy payment for Salton Sea I was 5.4 cents
per kWh during 1998. As the Salton Sea I PPA is not an SO4 Agreement, the
energy payments do not revert to Edison's Avoided Cost of Energy. The capacity
payment is approximately $1,100 per annum.
Salton Sea II and Salton Sea III sell electricity to Edison pursuant to
30-year modified SO4 agreements that provide for capacity payments, capacity
bonus payments and energy payments. The price for contract capacity and contract
capacity bonus payments is fixed for the life of the modified SO4 agreements.
The energy payments for each of the first ten year periods, which periods expire
in April 2000 and February 1999, respectively, are levelized at a time period
weighted average of 10.6 cents per kWh and 9.8 cents per kWh for Salton Sea II
and Salton Sea III, respectively. Thereafter, the monthly energy payments will
be Edison's Avoided Cost of Energy. For Salton Sea II only, Edison is entitled
to receive, at no cost, 5% of all energy delivered in excess of 80% of contract
capacity through September 30, 2004. The annual capacity and bonus payments for
Salton Sea II and Salton Sea III are approximately $3,300 and $9,700,
respectively.
Salton Sea IV sells electricity to Edison pursuant to a modified SO4
agreement which provides for contract capacity payments on 34 MW of capacity at
two different rates based on the respective contract capacities deemed
attributable to the original Salton Sea PPA option (20 MW) and to the original
Fish Lake PPA (14 MW). The capacity payment price for the 20 MW portion adjusts
quarterly based upon specified indices and the capacity payment price for the
14 MW portion is a fixed levelized rate. The energy payment (for deliveries up
to a rate of 39.6 MW) is at a fixed rate for 55.6% of the total energy
delivered by Salton Sea IV and is based on an energy payment schedule for 44.4%
of the total energy delivered by Salton Sea IV. The contract has a 30-year term
but Edison is not required to purchase the 20 MW of capacity and energy
originally attributable to the Salton Sea I PPA option after September 30,
2017, the original termination date of the Salton Sea I PPA.
For the years ended December 31, 1998, 1997 and 1996, Edison's average
Avoided Cost of Energy was 3.0 cents, 3.3 cents and 2.5 cents per kWH,
respectively, which is substantially below the contract energy prices earned
for the year ended December 31, 1998. CE Generation cannot predict the likely
F-13
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
level of Avoided Cost of Energy or PX prices under the SO4 agreements and the
modified SO4 agreements at the expiration of the scheduled payment periods. The
revenues generated by each of the projects operating under SO4 agreements will
decline significantly after the expiration of the respective scheduled payment
periods.
The Imperial Valley Projects other than Salton Sea Unit I receive
transmission service from the Imperial Irrigation District to deliver
electricity to Southern California Edison near Mirage, California. These
projects pay a rate based on the Imperial Irrigation District's cost of service
which was $1.52 per month per kilowatt of service provided for 1998 and is
recalculated annually. The transmission service and interconnection agreements
expire in 2015 for the Partnership Projects, 2019 for Salton Sea Unit III, 2020
for Salton Sea Unit II and 2026 for Salton Sea Unit IV. Salton Sea Unit V and
the CE Turbo projects have entered into 30-year agreements with similar terms
with the Imperial Irrigation District. Salton Sea Unit I delivers energy to
Southern California Edison at the project site and has no transmission service
agreement with the Imperial Irrigation District.
The Imperial Valley projects obtain their geothermal resource rights from
Magma Power Company and Magma Land Company I which are our subsidiaries.
The Partnership Project pays royalties based on both energy revenues and
total electricity revenues. Del Ranch and Leathers pay royalties of 5% of
energy revenues and 1% of total electricity revenue. Elmore pays royalties of
5% of energy revenues. Vulcan pays royalties of 4.167% of energy revenues.
The Salton Sea Project's weighted average royalty expense in 1998, 1997,
and 1996 was approximately 4.8%, 6.1% and 5.2%, respectively. The royalties are
paid to numerous recipients based on varying percentages of electrical revenue
or steam production multiplied by published indices.
During 1998 CE Generation changed the estimated useful life related to the
step up in basis for two of the plants received in the acquisition of the
Imperial Valley projects. This change conformed these plants' estimated useful
life with the others acquired in the purchase and resulted in an increase in
depreciation and amortization of approximately $7,500 in 1998. This change will
not have a significant impact on future periods as the scheduled price period
terminates in 1999 and the step up will be fully depreciated at that time.
GAS PROJECTS--The Saranac Project sells electricity to New York State
Electric & Gas pursuant to a 15 year negotiated power purchase agreement (the
Saranac PPA), which provides for capacity and energy payments. Capacity
payments, which in 1998 total 2.3 cents per kWh, are received for electricity
produced during "peak hours" as defined in the Saranac PPA and escalate at
approximately 4.1% annually for the remaining term of the contract. Energy
payments, which averaged 6.7 cents per kWh in 1998, escalate at approximately
4.4% annually for the remaining term of the Saranac PPA. The Saranac PPA
expires in June of 2009. Saranac sells steam to Georgia-Pacific and Tenneco
Packaging under long-term steam sales agreements. CE Generation believes that
these agreements will enable Saranac to sell the minimum annual quantity of
steam necessary for the Saranac Project to maintain its qualifying facility
status under PURPA for the term of the Saranac PPA.
The Power Resources Project sells electricity to Texas Utilities Electric
Company (TUEC) pursuant to a 15 year negotiated power purchase agreement (the
Power Resources PPA), which provides for capacity and energy payments. Capacity
payments and energy payments, which in 1998 are $3,138 per month and 3.0 cents
per kWh, respectively, escalate at 3.5% annually for the remaining term of the
Power Resources PPA. The Power Resources PPA expires in September 2003. Power
Resources sells steam to Fina Oil and Chemical under a 15-year agreement. Power
Resources has
F-14
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
agreed to supply Fina with up to 150,000 pounds per hour of steam. As long as
Power Resources meets its supply obligations, Fina is required to purchase at
least the minimum amount of steam per year required to allow the Power Resources
Project to maintain its qualifying facility status under PURPA.
The NorCon Project sells electricity to Niagara Mohawk Power Corporation
(Niagara) pursuant to a 25 year negotiated power purchase agreement (the Norcon
PPA) which provides for energy payments calculated pursuant to an adjusting
formula based on Niagara's ongoing Tariff Avoided Cost and the contractual
Long-Run Avoided Cost. The NorCon PPA term extends through December 2017.
NorCon sells steam to Welch Foods, Inc. under an agreement that expires in
December 2012. Welch is required to purchase at least the minimum amount of
steam per year required to maintain the NorCon Project's qualifying facility
status under the Public Utility Regulatory Policies Act of 1978. If NorCon
fails to deliver steam, it will be liable for liquidated damages, limited to
$10,000 per occurrence. NorCon's aggregate liability over the term of the steam
purchase agreement is subject to an escalating cap, which starts at $2.0
million and increases to $3.2 million by the 20th year of the contract.
Yuma sells electricity to San Diego Gas & Electric Company (SDG&E) under
an existing 30-year power purchase contract. The energy is sold at SDG&E's
Avoided Cost of Energy and the capacity is sold to SDG&E at a fixed price for
the life of the power purchase contract. The power is wheeled to SDG&E over
transmission lines constructed and owned by Arizona Public Service Company
(APS). Yuma sells steam to Queen Carpet, Inc. pursuant to an agreement that
expires on May 1, 2024. Queen Carpet is required to take a minimum of 126,900
MMBtus of steam per year, which is sufficient to permit the Yuma Project to
maintain its qualifying facility status under the Public Utility Regulatory
Policies Act.
Saranac, Power Resources, NorCon and Yuma each delivers energy to its
respective power purchaser at or near the site of its project and does not
utilize transmission service provided by any other party. The facilities to
interconnect each of these projects to the system of the power purchaser were
constructed under the terms of its power purchase agreement or, in the case of
NorCon, a separate agreement with Niagara Mohawk which expires upon the
termination of the NorCon power purchase agreement with Niagara Mohawk.
Saranac purchases natural gas from Coral Energy under a 15-year gas supply
agreement that expires in 2009. The price was $3.58 per MMBtu at December 1998
and escalates at the rate of 4% per year. Coral delivers the gas to the
pipeline owned by Saranac's subsidiary, North Country Gas Pipeline which
transports the gas to the Saranac project.
Fina Oil and Chemical supplies 3,600 MMBtu of refinery fuel gas to the
Power Resources project under an agreement that expires in 2003. The delivery
point is at the Power Resources project. The price was $2.74 per MMBtu in 1998
and excalates at 2% per year. Louis Dreyfus Natural Gas Corporation also
supplies natural gas for the Power Resources project under a gas supply
agreement that expires in 2003. The price for the first 31,200 MMBtu per day
under the agreement was $2.164 per MMBtu in 1998 and escalates incrementally to
$2.57 per MMBtu in 2003. The price for the second 3,000 MMBtu per day under the
agreement is set at the West Texas spot price plus $.05 per MMBtu. Additional
gas may be purchased under the agreement at prices that are negotiated with
Louis Dreyfus. Louis Dreyfus delivers the gas to Westar Transmission System
which transports the gas for Power Resources to the project at a rate of $.06
to $.12 per MMBtu depending upon the point of entry into the Westar
Transmission system.
NorCon purchases natural gas from Louis Dreyfus Natural Gas Corporation
under a 15-year gas supply agreement that expires in 2009. Louis Dreyfus
delivers the gas to National Fuel Gas Supply
F-15
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
Corporation which transports the gas for NorCon to the NorCon project. The price
paid to Louis Dreyfus was $4.11 per MMBtu at December 1998, which escalates at
the rate of 7% per year, less amounts payable to National Fuel under the gas
transportation agreement. The National Fuel transportation agreement expires in
2012.
Yuma purchases natural gas from Southwest Gas Corporation. Yuma is
entitled to direct Southwest Gas to purchase gas from any of several gas supply
basins and transport it to the project. Yuma pays a price based on the
applicable index for the relevant basin. The agreement may be terminated by
either party commencing in 2002, in which case Southwest Gas would be required
to provide gas transportation service under its transportation tariff to Yuma.
ROYALTIES--Royalty expense for the years ended December 31, 1998, 1997 and
1996, which is included in plant operations in the consolidated statements of
operations, comprise the following:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Vulcan ..................... $ 363 $ 326 $ 361
Leathers ................... 2,811 2,694 2,203
Elmore ..................... 2,192 2,213 1,883
Del Ranch .................. 2,870 2,650 2,255
Salton Sea I & II .......... 810 1,206 634
Salton Sea III ............. 1,637 2,439 1,334
Salton Sea IV .............. 2,645 2,815 1,558
-------- -------- --------
Total ..................... $ 13,328 $ 14,343 $ 10,228
======== ======== ========
</TABLE>
The Partnership Project pays royalties based on both energy revenues and
total electricity revenues. Del Ranch and Leathers pay royalties of
approximately 5% of energy revenues and 1% of total electricity revenue. Elmore
pays royalties of approximately 5% of energy revenues. Vulcan pays royalties of
approximately 4.167% of energy revenues.
The Salton Sea Project's weighted average royalty expense in 1998 and 1997
was approximately 4.8% and 6.1%, respectively. The royalties are paid to
numerous recipients based on varying percentages of electrical or steam
production multiplied by published indices.
6. PROJECT LOAN
Each of CE Generation's direct or indirect subsidiaries is organized as a
legal entity separate and apart from CE Generation and its other subsidiaries
and MEHC. Pursuant to separate project financing agreements, the assets of each
subsidiary (excluding Yuma) are pledged or encumbered to support or otherwise
provide the security for their own project or subsidiary debt. It should not be
assumed that any asset of any such subsidiary will be available to satisfy the
obligations of CE Generation or any of its other such subsidiaries; provided,
however, that unrestricted cash or other assets which are available for
distribution may, subject to applicable law and the terms of financing
arrangements for such parties, be advanced, loaned, paid as dividends or
otherwise distributed or contributed to CE Generation or affiliates thereof.
"Subsidiaries" means all of CE Generation's direct or indirect subsidiaries (1)
owning interests in the Imperial Valley projects (including the Salton Sea
projects and the Partnership projects), the Saranac project, NorCon project or
PRI project or (2) owning interests in the subsidiaries that own interests in
the foregoing projects.
Power Resources has project financing debt with a consortium of banks with
interest and principal due quarterly over a 15-year period, beginning March 31,
1989. The original principal carried a variable interest rate based on the
London Interbank Offer Rate ("LIBOR") with a .85% interest
F-16
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
margin through the 5th anniversary of the loan, a 1.00% interest margin from the
5th anniversary through the 12th anniversary of the loan and a 1.25% interest
margin from the 12th anniversary through the end of the loan. The loan is
collateralized by an assignment of all revenues received by Power Resources, a
lien on substantially all of its real and personal property and a pledge of its
capital stock.
Effective June 5, 1989, Power Resources entered into an interest rate swap
agreement with the lender as a means of hedging floating interest rate exposure
related to its 15-year term loan. The swap agreement was for initial notional
amounts of $55,000 and $110,000, declining in correspondence with the principal
balances, and effectively fixed the interest rates at 9.385% and 9.625%,
respectively, excluding the interest margin. The swap agreements are settled in
cash based on the difference between a fixed and floating (index based) price
for the underlying debt. The national values of these financial instruments
were $90,529 and $103,334 at December 31, 1998 and 1997, respectively. Power
Resources would be exposed to credit loss in the event of nonperformance by the
lender under the interest rate swap agreement. However, Power Resources does
not anticipate nonperformance by the lender. The estimated cost to terminate
the interest rate swap agreement, based on termination values obtained from the
lender, was $9,904 and $10,550 at December 31, 1998 and 1997, respectively.
The interest rate can be increased by payments under a Compensation
Agreement included in Power Resources' term loan. The Compensation Agreement,
which entitles two of the term lenders to receive quarterly payments equivalent
to a percentage of Power Resources' discretionary cash flow (DCF) as separately
defined in the agreement, become effective initially for a 13-year period ending
December 31, 2003. Under certain conditions relating to the amount of Power
Resources' cash flow and the restrictions on cash distributions, Power Resources
has the option to replace the payment obligation in a quarter with a payment to
be calculated in a future quarter and added to the end of the initial term of
the agreement. The Compensation Agreement entitles the lenders to payments
totaling 10% of DCF for the first ten years, 7.5% of DCF for the next three
years and 10% of DCF for each quarter added to the initial term of the
agreement. PRI recorded additional interest expense of $1,176 and $1,091 for the
years ended December 31, 1998 and 1997, respectively, and $319 and $585 for the
periods from August 7, 1996 through December 31, 1996 related to amounts owed
under the Compensation Agreement.
Scheduled maturities of project financing debt for the year ending
December 31 are as follows:
<TABLE>
<S> <C>
1999 .......... $ 14,268
2000 .......... 16,087
2001 .......... 18,119
2002 .......... 20,312
2003 .......... 21,743
--------
Total ......... $ 90,529
========
</TABLE>
Under Power Resources' term loan agreement, certain covenants and
conditions must be met before cash distributions can be made, the most
significant of which is the maintenance of a historical quarterly debt service
coverage ratio of at least 1.20:1.00 in order to permit all available cash to
be distributed. Power Resources was in compliance with these requirements at
December 31, 1998.
7. SALTON SEA NOTES AND BONDS
The Salton Sea Funding Corporation (the "Funding Corporation"), a
wholly-owned indirect subsidiary of CE Generation, debt securities are as
follows:
F-17
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
SENIOR FINAL DECEMBER 31,
SECURED MATURITY -------------------------
ISSUED DATE SERIES DATE RATE 1998 1997
- -------------------------- --------- ------------------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
July 21, 1995 ............ A Notes May 30, 2000 6.69% $ 48,436 $ 97,354
July 21, 1995 ............ B Bonds May 30, 2005 7.37 106,980 133,000
July 21, 1995 ............ C Bonds May 30, 2010 7.84 109,250 109,250
June 20, 1996 ............ D Notes May 30, 2000 7.02 12,150 44,150
June 20, 1996 ............ E Bonds May 30, 2011 8.30 65,000 65,000
October 13, 1998 ......... F Bonds November 30, 2018 7.48 285,000 --
--------- ---------
$ 626,816 $ 448,754
========= =========
</TABLE>
Principal and interest payments are made in semi-annual installments. The
Salton Sea Notes and Bonds are non-recourse to CE Generation.
On October 13, 1998 the Funding Corporation completed a sale to
institutional investors of $285,000 aggregate amount of 7.475% Senior Secured
Series F Bonds due November 30, 2018. The proceeds of $144,480 from the
offering are being used to partially fund construction of two new geothermal
projects at the Salton Sea and other capital improvements at the existing
Salton Sea projects. The remaining amount of $140,520 is being used to fund the
cost of construction of, and was advanced to, the Zinc Recovery Project, which
is indirectly 100% owned by Salton Sea Minerals Corp., a MEHC affiliate not
owned by CE Generation.
The net revenues, equity distributions and royalties from the Partnership
Projects are used to pay principal and interest payments on outstanding senior
secured bonds issued by the Funding Corporation, the final series of which is
scheduled to mature in November 2018. The Funding Corporation Debt is
guaranteed by certain subsidiaries of Magma and secured by the capital stock of
the Funding Corporation. The proceeds of the Funding Corporation Debt were
loaned by the Funding Corporation pursuant to loan agreements and notes (the
"Imperial Valley Project Loans") to certain subsidiaries of Magma and used for
construction of certain Imperial Valley Projects, refinancing of certain
indebtedness and other purposes. Debt service on the Imperial Valley Project
Loans is used to repay debt service on the Funding Corporation Debt. The
Imperial Valley Project Loans and the guarantees of the Funding Corporation
Debt are secured by substantially all of the assets of the guarantors,
including the Imperial Valley Projects, and by the equity interests in the
guarantors.
The proceeds of Series F of the Funding Corporation debt are being used in
part to construct the Zinc Facility, and the direct and indirect owners of the
Zinc Facility (the "Zinc Guarantors", which will include Salton Sea Minerals
Corp. and Minerals LLC), are among the guarantors of the Funding Corporation
debt. In connection with the Divestiture, MEHC will guarantee the payment by
the Zinc Guarantors of a specified portion of the scheduled debt service on the
Imperial Valley Project Loans, including the current principal amount of
$140,520 and associated interest.
Pursuant to a depository agreement, Funding Corporation established a debt
service reserve fund in the form of a letter of credit in the amount of $42,457
from which scheduled interest and principal payments can be made.
Annual repayments of the Salton Sea Notes and Bonds for the years
beginning January 1, 1999 and thereafter are as follows:
F-18
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
<TABLE>
<S> <C>
1999 ............... $ 57,836
2000 ............... 25,072
2001 ............... 24,514
2002 ............... 27,148
2003 ............... 28,086
Thereafter ......... 464,160
---------
$ 626,816
=========
</TABLE>
CE Generation's ability to obtain distributions from its investment in the
Salton Sea Projects and Partnership Projects is subject to the following
conditions:
o the depositary accounts for the Salton Sea Notes and Bonds must be fully
funded;
o there cannot have occurred any default or event of default under the
Salton Sea Notes and Bonds;
o the historical debt service coverage ratio of Salton Sea Funding
Corporation for the prior four fiscal quarters must be at least 1.4 to
1.0, if the distribution occurs prior to 2000, or 1.5 to 1.0, if the
distribution occurs during or after 2000;
o there must be sufficient geothermal reources to operate the Salton Sea
projects at their required levels; and
o each Salton Sea project under construction cannot have failed to be
complete by its guaranteed substantial completion date, unless a
sufficient portion of the Salton Sea Notes and Bonds have been redeemed
or a ratings confirmation has been obtained.
8. NOTES PAYABLE TO RELATED PARTY
On July 21, 1995, MEHC issued $200,000 of 9.875% Limited Recourse Senior
Secured Notes Due 2003 (the "Notes"). The Notes are secured by an assignment
and pledge of 100% of the outstanding capital stock of Magma and are recourse
only to such Magma capital stock. The proceeds of Notes Offering were provided
by MEHC to Magma and Magma issued an intercompany note to MEHC in the amount of
$200,000. Interest on the intercompany note is at 9.875%. See Note 15.
Yuma Cogeneration Associates has outstanding a note payable to MEHC with a
principal balance at December 31, 1998 and 1997 of $47,681 and $47,812,
respectively, and bearing interest at a fixed rate of 10.25%. The terms of the
note require semiannual principal and interest payments. Annual repayment of
the note for each year beginning January 1, 1999 through 2003 is $4,755 with
$23,906 due thereafter.
9. COMMITMENTS AND CONTINGENCIES
Power Resources has contracted to purchase natural gas for its
cogeneration facility under two separate agreements, an 8-year agreement for up
to 40,000 MMBTU per day which expires in December 2003 and a 15-year agreement
for 3,600 MMBTU per day which expires in June 2003. These agreements include
annual price adjustments, and the 15-year agreement includes a provision which
allows the seller to terminate the agreement with a two-year written notice. As
of December 31, 1998, the seller had not elected to terminate this agreement;
therefore, the minimum volumes under the 15-year and 8-year agreements for the
years ending December 31, are included in the future minimum payments under
these contracts as follows:
F-19
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
<TABLE>
<S> <C>
1999 ........... $ 22,611
2000 ........... 23,308
2001 ........... 23,608
2002 ........... 24,285
2003 ........... 24,854
---------
Total ......... $ 118,666
=========
</TABLE>
CE Generation's geothermal and cogeneration facilities are qualifying
facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and
their contracts for the sale of electricity are subject to regulations under
PURPA. In order to promote open competition in the industry, legislation has
been proposed in the U.S. Congress that calls for either a repeal of PURPA on a
prospective basis or the significant restructuring of the regulations governing
the electric industry, including sections of the Public Utility Regulatory
Policies Act. Current federal legislative proposals would not abrogate, amend,
or modify existing contracts with electric utilities. The ultimate outcome of
any proposed legislation is unknown at this time.
Saranac has contracted to purchase natural gas from a third party, for its
cogeneration facility for a period of 15 years for an amount up to 51,000
MMBTU's per day. The price for such deliveries is a stated rate, escalated
annually at a rate of 4%.
Salton Sea Unit V is obligated to supply the electricity demands of the
Zinc Recovery Project at the price available to Salton Sea Unit V from the PX
less the wheeling costs to the PX.
Salton Sea Power, L.L.C., one of our indirect wholly-owned subsidiaries,
is constructing Salton Sea Unit V. Salton Sea Unit V will be a 49 net megawatt
geothermal power plant which will sell approximately one-third of its net
output to the zinc facility, which will be retained by MidAmerican. The
remainder will be sold through the California power exchange.
Salton Sea Unit V is being constructed pursuant to a date certain, fixed
price, turnkey engineering, procurement and construction contract by Stone &
Webster Engineering Corporation. Salton Sea Unit V is scheduled to commence
commercial operation in mid-2000. Total project costs of Salton Sea Unit V are
expected to be approximately $119,067 which will be funded by $76,281 of debt
from Salton Sea Funding Corporation and $42,786 from equity contributions.
CE Turbo LLC, one of our indirect wholly-owned subsidiaries, is
constructing the CE Turbo project. The CE Turbo project will have a capacity of
10 net megawatts. The net output of the CE Turbo project will be sold to the
zinc facility or sold through the California power exchange.
The partnership projects are upgrading the geothermal brine processing
facilities at the Vulcan and Del Ranch projects with the region 2 brine
facilities construction.
The CE Turbo project and the region 2 brine facilities construction are
being constructed by Stone & Webster pursuant to a date certain, fixed price,
turnkey engineering, procurement and construction contract. The obligations of
Stone & Webster are guaranteed by Stone & Webster, Incorporated. The CE Turbo
project is scheduled to commence initial operations in early-2000 and the
region 2 brine facilities construction is scheduled to be completed in
early-2000. Total project costs for both the CE Turbo project and the region 2
brine facilities construction are expected to be approximately $63,747 which
will be funded by $55,602 of debt from Salton Sea Funding Corporation and
$8,145 from equity contributions.
F-20
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
10. INCOME TAXES
Provision for income tax is comprised of the following at December 31:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ---------- ----------
<S> <C> <C> <C>
Currently payable:
State ........... $ 11,099 $ 8,451 $ 3,586
Federal ......... 47,263 30,647 8,027
-------- -------- --------
58,362 39,098 11,613
-------- -------- --------
Deferred:
State ........... (836) 1,057 1,280
Federal ......... (5,308) 3,223 2,594
-------- -------- --------
(6,144) 4,280 3,874
-------- -------- --------
Total ......... $ 52,218 $ 43,378 $ 15,487
======== ======== ========
</TABLE>
A reconciliation of the federal statutory tax rate to the effective tax
rate applicable to income before provision for income taxes follows:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Federal statutory rate .................................... 35.00% 35.00% 35.00%
Percentage depletion in excess of cost depletion .......... (4.36) (4.59) ( 7.31)
Investment and energy tax credits ......................... (2.52) (0.90) (17.45)
Goodwill amortization ..................................... 3.06 3.58 5.29
State taxes, net of federal benefit ....................... 4.59 5.18 5.44
Other ..................................................... -- (0.01) 4.13
----- ----- ------
Effective tax rate ........................................ 35.77% 38.26% 25.10%
===== ===== ======
</TABLE>
Deferred tax liabilities (assets) are comprised of the following at
December 31:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
Depreciation and amortization, net .......................... $ 240,602 $ 247,891
--------- ---------
Accruals not currently deductible for tax purposes .......... (3,218) (3,628)
General business tax credits ................................ (8,891) (12,094)
Alternative minimum tax credits ............................. (16,333) (16,333)
Other ....................................................... (3,311) (843)
--------- ---------
(31,753) (32,898)
--------- ---------
Net deferred taxes .......................................... $ 208,849 $ 214,993
========= =========
</TABLE>
CE Generation has unused general business tax credit carryforwards of
approximately $8,891 expiring between 2004 and 2018. CE Generation also has
approximately $16,333 of alternative minimum tax credit carryforwards which
have no expiration date.
F-21
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Although management uses its best
judgment in estimating the fair value of these financial instruments, there are
inherent limitations in any estimation technique. Therefore, the fair value
estimates presented herein are not necessarily indicative of the amounts which
CE Generation could realize in a current transaction.
The fair value of the note receivable from related party is estimated
based on the quoted market price of the corresponding debt issue.
The fair value of all debt issues listed on exchanges, including the note
payable to related party which is based on a debt issue listed on an exchange,
has been estimated based on the quoted market prices. The remaining note
payable to related party, which is not based on market prices, and the project
loan are estimated to have a fair value equal to the carrying value.
The carrying amounts in the table below are included in the consolidated
balance sheets under the indicated captions:
<TABLE>
<CAPTION>
1998 1997
------------------------ ---------------------------
ESTIMATED ESTIMATED
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
---------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Financial Assets:
Note receivable from related party ......... $140,520 $140,942 -- --
Financial Liabilities:
Project loan ............................... 90,529 90,529 $ 103,334 $ 103,334
Salton Sea notes and bonds ................. 626,816 646,397 448,754 463,720
Notes payable to related party ............. 247,681 265,581 247,812 265,641
Interest rate swap .......................... -- (9,904) -- (10,550)
</TABLE>
12. LITIGATION
NYSEG--On February 14, 1995, NYSEG filed with the FERC a Petition for a
Declaratory Order, Complaint, and Request for Modification of Rates in Power
Purchase Agreements Imposed Pursuant to the Public Utility Regulatory Policies
Act of 1978 (Petition) seeking FERC (i) to declare that the rates NYSEG pays
under the Saranac PPA, which was approved by the New York Public Service
Commission (the PSC) were in excess of the level permitted under PURPA and (ii)
to authorize the PSC to reform the Saranac PPA.
On March 14, 1995, Saranac intervened in opposition to the Petition
asserting, inter alia, that the Saranac PPA fully complied with PURPA, that
NYSEG's action was untimely and that the FERC lacked authority to modify the
Saranac PPA. On March 15, 1995, CE Generation intervened also in opposition to
the Petition and asserted similar arguments. On April 12, 1995, the FERC by a
unanimous (5-0) decision issued an order denying the various forms of relief
requested by NYSEG and finding that the rates rquired under the Saranac PPA
were consistent with PURPA and the FERC's regulations. On May 11, 1995, NYSEG
requested rehearing of the order and, by order issued July 19, 1995, the FERC
unanimously (5-0) denied NYSEG's request. On June 14, 1995, NYSEG petitioned
the United States Court of Appeals for the District of Columbia Circuit (the
Court of Appeals) for review of FERC's April 12, 1995 order. FERC moved to
dismiss NYSEG's petition for review of July 28, 1995. On July 11, 1997, the
Court of Appeals dismissed NYSEG's appeal from FERC's denial of the petition on
jurisdictional grounds.
F-22
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
On August 7, 1997, NYSEG filed a complaint in the U.S. District Court for
the Northern District of New York against the FERC, the PSC (and the Chairman,
Deputy Chairman and the Commissioners of the PSC as individuals in their
official capacity), Saranac and Lockport Energy Associations, L.P. (Lockport)
concerning the power purchase agreements that NYSEG entered into with Saranac
and Lockport.
NYSEG's suit asserts that the PSC and the FERC improperly implemented
PURPA in authorizing the pricing terms that NYSEG, Saranac and Lockport agreed
to in those contracts. The action raises similar legal arguments to those
rejected by the FERC in its April and July 1995 orders. NYSEG in addition asks
for retroactive reformation of the contracts as of the date of commercial
operation and seeks a refund of $281 million from Saranac. Saranac and other
parties have filed motions to dismiss and oral arguments on those motions were
heard on March 2, 1998. The case was recently reassigned to a new judge and new
oral arguments have been scheduled for March 3, 1999. Saranac believes that
NYSEG's claims are without merit for, among other reasons, the same reasons
described in the FERC's orders.
NIAGARA--In March 1994, NorCon Power commenced an action against Niagara
in the Southern District of New York. In its complaint, NorCon requested a
declaratory judgment that Niagara has no right to demand additional security or
"adequate assurances" from Niagara of NorCon's future performance under a power
purchase agreement (the "Agreement") between the parties on the basis of a
demand letter dated February 4, 1994 from Niagara (the "Demand Letter") and a
permanent injunction enjoining Niagara from terminating or attempting to
terminate the Agreement for the reasons set forth in the Demand Letter. Niagara
filed a counterclaim for a declaratory judgment that Niagara had a right to
demand adequate assurances of NorCon's future performance under the Agreement,
Niagara properly exercised its right to demand "adequate assurances," and
NorCon's failure to provide "adequate assurances" constituted a repudiation of
the Agreement, and by reason of NorCon's repudiation, Niagara was relieved of
its obligations under the Agreement. On or about November 7, 1994, NorCon moved
for summary judgment. In a decision dated February 7, 1996, the Court granted
summary judgement in NorCon's favor, granting NorCon its requested declaratory
and injunctive relief and dismissing Niagara's counterclaim. On March 6, 1996,
Niagara filed a Notice of Appeal of the Court's decision (the "Appeal").
Judgment was entered in NorCon's favor on March 21, 1996. The Federal appellate
court certified a state law question of law to the New York Court of
Appeals on March 26, 1997. The state court has since issued its ruling that in
appropriate circumstances adequate assurance may be requested. On December 31,
1998, the case was remanded to the trial court for further proceedings. CE
Generation believes that NorCon will not be required to provide additional
security beyond that currently provided under the Agreement and intends to
vigorously defend this action against Niagara.
EDISON--In February 1998, Del Ranch and Elmore ("plaintiffs") filed an
action for breach of contract, fraud and unlawful discrimination relating to
the long-term contracts between plaintiffs and Edison for purchase and sale of
geothermal power. Among other claims, plaintiffs contend that Edison failed to
pay the correct "forecast" price for energy purchased from plaintiffs during
1998. Plantiffs seek compensatory damages of about $6 million and additional
punitive damages. Edison's demurrer to the frauds claim was recently overruled
by the Superior Court. Both sides are engaged in early discovery proceedings
and no trial date has yet been set. Plantiff's intend to pursue this action
vigorously. Plantiffs further believe there are good grounds to support their
claims, and that they should ultimately prevail on the merits at trial.
13. TRANSACTIONS WITH MEHC
MEHC provides certain administrative services to CE Generation, and MEHC's
executive, financial, legal, tax and other corporate staff departments perform
certain services for CE Generation.
F-23
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
Expenses incurred by MEHC and allocated to CE Generation are estimated based on
the individual services and expense items provided. Management reviewed all MEHC
costs for the three years ended December 31, 1998 by department, which included
a review of all MEHC personnel positions and duties. Management believes that an
average of such costs for expense allocation is reasonable. Allocated expenses
totaled approximately $3,000 for each of 1998, 1997, and 1996, and are included
in General and Administration expenses.
An analysis of CE Generation's net investment and advances is as follows:
<TABLE>
<CAPTION>
1998 1997 1996
------------ ------------- -----------
<S> <C> <C> <C>
Balance, beginning of year .................................. $ 464,140 $ 454,903 $ 233,425
Net income ................................................. 93,778 69,996 46,211
Purchase and contribution of FSRI stock from MEHC .......... -- -- 232,500
Distribution to MEHC, net of advances ...................... (20,971) (60,759) (57,233)
--------- --------- ---------
Balance, end of year ........................................ $ 536,947 $ 464,140 $ 454,903
========= ========= =========
</TABLE>
14. ADDITIONAL CASH FLOW INFORMATION
In conjunction with the acquisition of FSRI and Partnership Interest
Acquisition, liabilities were assumed as follows:
<TABLE>
<S> <C>
Fair value of assets .................... $ 546,377
Cash paid, net of cash acquired ......... (264,324)
----------
Liabilities assumed ..................... $ 282,053
==========
</TABLE>
Approximately $207,000 of the cash paid represents MEHC's acquisition of
FSRI, net of cash acquired, which was simultaneously pushed down to CE
Generation. For cash flow purposes, the acquisition is reflected as an
acquisition by CE Generation and as advances from MEHC.
15. SUBSEQUENT EVENTS
On March 2, 1999, CE Generation issued $400,000 of 7.416% Senior Secured
Bonds due 2018. The net proceeds from this financing were used for the
following purposes:
o to repay Magma's 9 7/8% Secured Note Due 2003 payable to MEHC in the
aggregate principal amount of $200 million, at a repayment price
(including its premium) equal to approximately $220 million;
o to make payments to MEHC aggregating approximately $122 million in
return for MEHC's transfer of certain assets to CE Generation. MEHC will
use these funds to prefund future equity contributions for various
construction projects;
o to repay approximately $49 million outstanding principal and interest
on a promissory note to MEHC;
o to make payments to MEHC aggregating up to approximately $4 million in
return for MEHC's transfers of certain assets to us which related to
MEHC's development costs for Salton Sea Unit V, the CE Turbo project and
the zinc facility; and
o to pay transaction costs and fees associated with the offer and sale
of the old securities.
F-24
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(AMOUNTS IN THOUSANDS)
These securities are senior secured debt which rank equally in right of
payment with CE Generation's other senior secured debt permitted under the
indenture for the securities, share equally in the collateral with CE
Generation's other senior secured debt permitted under the indenture for the
securities, and rank senior to any of CE Generation's subordinated debt
permitted under the indenture for the securities. These securities are
effectively subordinated to the existing project financing debt and all other
debt of CE Generation's consolidated subsidiaries.
The Senior Secured Bonds are primarily secured by the following
collateral:
o all available cash flow (as defined);
o a pledge of 99% of the equity interests in Salton Sea Power and all of
CE Generation's equity interests in its other consolidated subsidiaries,
with the exception of Magma Power Company (Magma) and subsidiaries;
o upon the redemption of, or earlier release of security interests under,
Magma's 9 7/8% promissory notes, a pledge of all of the capital stock of
Magma;
o a pledge of all of the capital stock of SECI Holding Inc.;
o a grant of a lien on and security interest in the depository accounts;
and
o to the extent possible, a grant of a lien on and security interest in
all of CE Generation's other tangible and intangible property, to the
extent assignable (other than the capital stock of Magma, which will be
pledged upon the redemption of, or earlier release of security interests
under, Magma's 9 7/8% promissory notes).
MEHC's obligation to make payments on Magma's 9 7/8% promissory notes is
secured by a pledge of the capital stock of Magma and a lien on dividends and
distributions in respect of such Magma stock. On March 3, 1999, MEHC
repurchased $195.8 million in aggregate principal amount of its 9 7/8%
Notes in connection with a tender offer for a repurchase price (including
premium) of $215.4 million. In connection with the corresponding reduction of
$195.8 million of the principal outstanding under Magma's 9 7/8% promissory
notes, $215.4 million of the proceeds of the old securities were paid to MEHC.
As a result of the 9 7/8% note repurchase offer, the outstanding principal
amount of Magma 9 7/8% promissory notes was reduced from $200 million to
approximately $4.2 million. MEHC intends to redeem the remaining outstanding
Magma's 9 7/8% promissory notes on June 30, 2000, which is the first day upon
which an optional redemption is permitted under the trust indenture for Magma's
9 7/8% promissory notes. A portion of the net proceeds of these securities, in
the amount of approximately $4.2 million, has been paid to MidAmerican and
placed into a restricted account held by the depository bank which is
maintained solely for the purpose of paying the remaining amounts due to the
secured parties. These proceeds are being used to pay interest on, and effect
the redemption (or the earlier repurchase) of the remaining outstanding
principal of, Magma's 9 7/8% promissory notes. At the time of this redemption,
the collateral agent is expected to obtain a pledge of all of Magma's capital
stock.
F-25
<PAGE>
CE GENERATION, LLC
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 1999 AND DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
---------------- -------------
<S> <C> <C>
ASSETS
Cash and cash equivalents .......................................... $ 83,981 $ 25,774
Restricted cash .................................................... 17,257 26,877
Accounts receivable ................................................ 61,971 67,629
Prepaid expenses ................................................... 8,424 11,677
Inventory .......................................................... 17,028 15,442
Deferred income taxes .............................................. 6,529 31,753
Other assets ....................................................... 1,105 4,629
---------- ----------
Total current assets ............................................ 196,295 183,781
Restricted cash .................................................... 35,554 101,676
Properties, plants, contracts and equipment, net ................... 982,258 893,492
Equity investments ................................................. 119,913 125,036
Excess of cost over fair value of net assets acquired, net ......... 288,286 310,700
Note receivable from related party ................................. 140,520 140,520
Deferred financing charges and other assets ........................ 16,556 27,180
---------- ----------
Total assets .................................................... $1,779,382 $1,782,385
========== ==========
LIABILITIES AND EQUITY
LIABILITIES:
Accounts payable and other accrued liabilities ..................... $ 58,758 $ 37,940
Current portion of long term debt .................................. 65,332 72,104
---------- ----------
Total current liabilities ....................................... 124,090 110,044
Project loan ....................................................... 65,926 76,261
Salton Sea notes and bonds ......................................... 546,468 568,980
Senior secured bonds ............................................... 400,000 --
Notes payable to related party ..................................... -- 247,681
Deferred income taxes .............................................. 261,832 240,602
---------- ----------
Other long term liabilities ........................................ 1,599 1,870
---------- ----------
Total liabilities ............................................... 1,399,915 1,245,438
Member's Equity .................................................... 379,467 --
Net investment and advances ........................................ -- 536,947
---------- ----------
379,467 536,947
---------- ----------
Total liabilities and equity ....................................... $1,779,382 $1,782,385
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-26
<PAGE>
CE GENERATION, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
REVENUE:
Sales of electricity and steam .................. $ 231,613 $293,485
Equity earnings in subsidiaries ................. 17,718 8,635
Interest and other income ....................... 17,665 21,823
--------- --------
Total revenues ............................... 266,996 323,943
--------- --------
COST AND EXPENSES:
Plant operations ................................ 84,848 84,100
General and administration ...................... 3,333 3,814
Depreciation and amortization ................... 43,400 71,901
Interest expense ................................ 58,343 54,784
Less interest capitalized ....................... (2,614) --
--------- --------
Total expenses ............................... 187,310 214,599
--------- --------
Income before provision for income taxes ......... 79,686 109,344
Provision for income taxes ....................... 30,520 39,364
--------- --------
Income before extraordinary item ................. 49,166 69,980
Extraordinary item, net of tax ................... (17,478) --
--------- --------
Net income ....................................... $ 31,688 $ 69,980
========= ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-27
<PAGE>
CE GENERATION, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(AMOUNTS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................................... $ 31,688 $ 69,980
ADJUSTMENTS TO RECONCILE CASH FLOWS FROM OPERATING
ACTIVITIES:
Depreciation and amortization ................................ 43,400 71,901
Provision for deferred income taxes .......................... 46,454 (4,609)
Equity earnings in subsidiaries .............................. (17,718) (8,635)
CHANGES IN OTHER ITEMS:
Accounts receivable ........................................ 5,658 (28,096)
Decrease (increase) in inventory ........................... (1,586) (2,087)
Accounts payable and other accrued liabilities ............. 20,547 11,627
Other assets ............................................... 26,971 3,774
---------- ---------
Net cash flows from operating activities ................. 155,414 113,855
---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ....................................... (119,322) (28,471)
Distributions from equity investments ...................... 22,841 13,455
Decrease (increase) in restricted cash ..................... 66,122 (1,024)
---------- ---------
Net cash flows from investing activities ................. (30,359) (16,040)
---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of Salton Sea notes and bonds .................... (28,918) (53,469)
Proceeds from Senior Secured Notes ......................... 400,000 --
Repayment of project loans ................................. (10,701) (9,603)
Repayment of note payable to related party ................. (247,681) (131)
Deferred charge relating to debt financing ................. -- (1,561)
Decrease (increase) in restricted cash ..................... 9,620 --
Advances (to) from MidAmerican Energy Holdings Company,
net ....................................................... (189,168) 13,465
---------- ---------
Net cash flows from financing activities ................. (66,848) (51,299)
---------- ---------
Net increase (decrease) in cash and cash equivalents ......... 58,207 46,516
Cash and cash equivalents at beginning of year ............... 25,774 23,684
---------- ---------
Cash and cash equivalents at end of year ..................... $ 83,981 $ 70,200
========== =========
SUPPLEMENTAL DISCLOSURE:
Interest paid .............................................. $ 37,620 $ 45,186
========== =========
Income taxes paid .......................................... $ 9,125 $ 1,001
========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-28
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
A. FORMATION
On February 8, 1999, MidAmerican Energy Holdings Company (formerly
CalEnergy Company, Inc.) ("MEHC") created a new subsidiary, CE Generation, LLC,
and subsequently transferred its interest in MEHC's power generation assets of
the Imperial Valley Projects and the Gas Projects to CE Generation.
On March 3, 1999, MEHC closed the sale of 50% of its ownership interests
in CE Generation to El Paso Power Holding Company. El Paso is an affiliate of
El Paso Energy Corporation. The purchase price consisted of $236.1 million in
cash plus the assumption of MEHC's obligation to make equity contributions
totaling $23.5 million for the construction of Salton Sea Unit V and the CE
Turbo project. CE Generation's limited liability company operating agreement
provides that MEHC and El Paso each are entitled to appoint 50% of the
directors and are entitled to 50% of the distributions that CE Generation
makes.
In connection with this sale to El Paso, MEHC agreed to provide
administrative services, including accounting, legal, personnel and cash
management services, to CE Generation under an administrative services
agreement. MEHC is reimbursed for its actual costs and expenses of providing
the services. CE Generation incurred approximately $1.5 million under this
agreement through September 30, 1999. El Paso agreed to provide power marketing
and fuel management services to CE Generation in return for reimbursement of
its actual costs and expenses of providing the services. CE Generation has not
incurred any costs under this agreement through September 30, 1999. These
agreements each have an initial term of one year and continue thereafter from
year to year until terminated by either party. CE Generation also entered into
an agreement with MEHC and El Paso to provide CE Generation with a right of
first refusal to participate in the development of any future geothermal power
projects or combined geothermal power and mineral recovery projects proposed by
MEHC in the area of the geothermal reservoir that currently supplies geothermal
resources to the Imperial Valley projects in return for the payment of a
royalty to MEHC. If CE Generation elects not to participate, the agreement
gives MEHC the right to develop the new project upon a showing that there are
sufficient geothermal resources for both the new project and our existing
projects.
CE Generation has an amount due to MEHC of approximately $2.1 million at
September 30, 1999, included in accounts payable and other accrued liabilities
in the balance sheet. These amounts are settled periodically throughout the
year.
B. GENERAL
The September 30, 1999 and 1998 consolidated financial statements included
herein have been prepared by CE Generation, without audit, pursuant to the
rules and regulations of the securities and Exchange Commission. Certain
information and disclosures normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed
or omitted pursuant to such rules and regulations. In the opinion of CE
Generation, all adjustments (consisting only of normal recurring accruals) have
been made to present fairly the financial position, the results of operations
and the changes in cash flows for the periods presented. Although CE Generation
believes that the disclosures are adequate to make the information presented
not misleading, it is suggested that these financial statements be read in
conjunction with the December 31, 1998 consolidated financial statements.
C. EXTRAORDINARY ITEM
On January 29, 1999, MEHC commenced a cash offer for all of its
outstanding 9-7/8% Limited Recourse Senior Secured Notes Due 2003. MEHC
received tenders from holders of an aggregate of approximately $195.8 million
principal which were paid on March 3, 1999, at a redemption price of 110.025%
plus accrued interest. The intercompany note to MidAmerican Energy Holdings
Company, including the redemption premium, was repaid by CE Generation,
resulting in an extraordinary loss of approximately $17.5 million, net of tax.
F-29
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
D. SENIOR SECURED BONDS
On March 2, 1999, CE Generation closed the sale of $400 million aggregate
principal amount of its 7.416% Senior Secured Bonds due 2018 and distributed
the proceeds to MEHC. Annual repayments of the bonds are $0, $10.4 million,
$12.6 million, $20.6 million, and $18 million for 1999 through 2003,
respectively, and $338.4 million thereafter. The estimated fair value of the
Senior Secured Bonds is $363.4 million at September 30, 1999.
The Senior Secured Bonds are secured by the following collateral:
o all available cash flow of the Subsidiaries deposited with the
depositary bank;
o a pledge of 99% of the equity interests in Salton Sea Power Company and
all of the equity interests in CE Texas Gas LLC, the Subsidiaries (other
than Magma Power Company) and California Energy Yuma Corporation;
o upon the redemption of, or earlier release of security interests under,
Magma's 9 7/8% promissory notes, a pledge of all of the capital stock of
Magma;
o a pledge of all of the capital stock of SECI Holdings Inc.;
o a grant of a lien on and security interest in the depositary accounts;
and
o a grant of a lien on and security interest in all of CE Generation's
other tangible and intangible property.
CE Generation is required to maintain a balance in the debt service
reserve account equal to the maximum semiannual principal and interest payment
on the Senior Secured Bonds. CE Generation can fulfill this requirement by
depositing cash into the debt service reserve account and/or posting a letter
of credit for the debt service reserve account. On March 2, 1999, CE Generation
posted a letter of credit issued by Credit Suisse First Boston in the amount of
approximately $24 million to satisfy its debt service reserve obligations.
Monies on deposit in the debt service reserve account and drawings on debt
service reserve letters of credit will be used to make principal and interest
payments on the Senior Secured Bonds and debt service reserve bonds and
interest payments on debt service reserve letter of credit loans.
CE Generation is permitted to redeem all or any portion of the Senior
Secured Bonds at any time prior to maturity at a redemption price equal to:
o 100% of the principal amount of the Senior Secured Bonds being
redeemed; plus
o accrued and unpaid interest on the Senior Secured Bonds being
redeemed; plus
o a yield maintenance premium which is based on the rates of comparable
treasury securities plus 50 basis points.
CE Generation is obligated to redeem Senior Secured Bonds at par plus
accrued interest plus a yield maintenance premium in the following
circumstances:
o if any Subsidiary receives more than $15,000,000 of available cash
flow representing refinancing proceeds or asset sale proceeds;
o if CE Generation receives more than $15,000,000 of proceeds from the
sale of its interest in a Subsidiary and the sale was not
specifically permitted under the indenture for the Senior Secured
Bonds; or
o if any Subsidiary receives more than $15,000,000 of proceeds from the
sale of its interest in a project company and the sale was not
specifically permitted under the indenture.
F-30
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
However, CE Generation may not have to use all of the proceeds to redeem Senior
Secured Bonds in the foregoing circumstances if the rating agencies confirm the
ratings for the Senior Secured Bonds.
CE Generation is obligated to redeem Senior Secured Bonds at par plus
accrued interest if any Subsidiary receives more than $15,000,000 of available
cash flow representing insurance proceeds, eminent domain proceeds, title
insurance proceeds or proceeds from the buy-out of a power purchase agreement.
However, CE Generation may not have to use all available cash flow representing
buy-out proceeds to redeem Senior Secured Bonds if the rating agencies confirm
the ratings for the Senior Secured Bonds.
E. INCOME TAXES
CE Generation has elected to be taxed as a "C" Corporation for federal
income tax reporting purposes.
F. MEMBERS' EQUITY
At February 8, 1999, CE Generation was created by MEHC and the balance of
net investments and advances and earnings through February 8, 1999, were
contributed to CE Generation in exchange for full ownership. Prior to MEHC's
sale of 50% of CE Generation's membership, CE Generation disbursed, net of
additional contributions, approximately $182.6 million to MEHC.
Members' equity comprised the following at September 30, 1999 (in
thousands):
<TABLE>
<S> <C>
Net investment and advances, beginning of year ........................ $ 536,947
Distribution to MEHC, net of advances ................................. (6,575)
Net income through February 8, 1999 ................................... 6,526
----------
Capital contribution by MEHC at February 8, 1999 .................... 536,898
Distribution to MEHC, net of contributions ............................ (182,593)
Members' net income from February 9, 1999 to September 30, 1999 ....... 25,162
----------
Members' equity, September 30, 1999 ................................. $ 379,467
==========
</TABLE>
G. SUBSEQUENT EVENT
On December 2, 1999, CE Generation's indirect subsidiary, NorCon Power
Partners, L.P., reached agreement with Niagara Mohawk Power Corporation to
dismiss the outstanding litigation between NorCon and Niagara. At the same
time, NorCon transferred the NorCon project to General Electric Capital
Corporation and entered into agreements with third parties to terminate some of
NorCon's contracts and to assign the rest of its contracts to a subsidiary of
General Electric Capital. General Electric Capital also agreed to be
responsible for other third party claims made against NorCon related to the
NorCon project. Thus, after December 2, 1999, neither NorCon nor any of CE
Generation's other subsidiaries owns an interest in the NorCon project and the
NorCon project contracts are no longer in effect or have been assigned to third
parties.
As CE Generation's share of NorCon's earnings comprise less than 5% of the
equity earnings in subsidiaries for the nine months ended September 30, 1999
and CE Generation's share of NorCon's net assets is less than 1% of the equity
investments at September 30, 1999, the transfer of the NorCon project to
General Electric Capital is not expected to have any significant impact on CE
Generation's results of operations, financial condition or liquidity.
F-31
<PAGE>
CE GENERATION, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(UNAUDITED)
H. PENDING ACCOUNTING POLICY CHANGES
In 2000, CE Generation will change its method of accounting for major
maintenance costs from the accrual method to the deferral method pending any
change in current authoritative guidance. As of September 30, 1999, the
cumulative effect of this change would result in a one-time increase in net
income of approximately $9.7 million. CE Generation does not expect the
continuing impact of this change to have a material impact on its results of
operations.
F-32
<PAGE>
INDEPENDENT AUDITORS' REPORT
Board of Directors and Shareholder
Magma Power Company
Omaha, Nebraska
We have audited the accompanying consolidated balance sheets of Magma
Power Company and subsidiaries, (a wholly-owned subsidiary of MidAmerican
Energy Holdings Company, successor of CalEnergy Company, Inc.), as of December
31, 1998 and 1997 and the related consolidated statements of operations,
stockholder's equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Magma Power Company and
subsidiaries at December 31, 1998 and 1997 and the 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.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
January 28, 1999 (March 3, 1999 as to Note 11)
F-33
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 1998 AND 1997
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
ASSETS
Cash and cash equivalents ............................................ $ 54,661 $ 14,051
Restricted cash ...................................................... 25,147 51,835
Accounts receivable .................................................. 90,395 57,411
Due from parent ...................................................... -- 80,924
Prepaid expenses ..................................................... 21,677 17,766
Inventory ............................................................ 11,802 8,680
Deferred income taxes ................................................ -- 27,900
Other assets ......................................................... 6,999 5,270
---------- ----------
Total current assets .............................................. 210,681 263,837
Restricted cash ...................................................... 215,696 --
Properties, plants, contracts and equipment, net ..................... 1,212,322 1,207,605
Excess of cost over fair value of net assets acquired, net ........... 283,552 291,303
Deferred charges and other assets .................................... 36,808 38,072
---------- ----------
Total assets ...................................................... $1,959,059 $1,800,817
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
LIABILITIES:
Accounts payable and accrued liabilities ............................. $ 45,418 $ 31,969
Current portion of long-term debt .................................... 80,396 106,938
Due to parent ........................................................ 43,673 --
Deferred income taxes -- current ..................................... 1,221 --
---------- ----------
Total current liabilities ......................................... 170,708 138,907
Malitbog loans ....................................................... 131,246 176,657
Salton Sea notes and bonds ........................................... 568,980 341,816
Note payable to related party ........................................ 200,000 200,000
Deferred income taxes ................................................ 245,558 256,146
Other long-term liabilities .......................................... 930 804
---------- ----------
Total liabilities ................................................. 1,317,422 1,114,330
---------- ----------
DEFERRED INCOME ...................................................... 32,147 12,396
COMMITMENTS AND CONTINGENCIES (Note 10)
STOCKHOLDER'S EQUITY:
Preferred stock -- par value $0.10 per share, authorized 1,000 shares -- --
Common stock -- par value $0.10 per share, authorized 30,000 shares,
outstanding 100 shares .............................................. -- --
Additional paid in capital ........................................... 501,626 501,626
Retained earnings .................................................... 107,864 172,465
---------- ----------
Total stockholder's equity ........................................ 609,490 674,091
---------- ----------
Total liabilities and stockholder's equity ........................ $1,959,059 $1,800,817
========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-34
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
REVENUE:
Sales of electricity and steam .................. $ 370,470 $ 328,248 $ 249,293
Royalty income .................................. 2,284 3,489 6,846
Interest and other income ....................... 28,072 3,978 9,368
--------- --------- ---------
Total revenues ............................... 400,826 335,715 265,507
--------- --------- ---------
COST AND EXPENSES:
Plant operations ................................ 70,624 72,196 67,350
General and administration ...................... 1,820 1,380 503
Depreciation and amortization ................... 105,876 89,134 69,853
Interest expense ................................ 76,850 72,386 67,652
Less interest capitalized ....................... (20,934) (20,549) (27,382)
--------- --------- ---------
Total expenses ............................... 234,236 214,547 177,976
--------- --------- ---------
Income before provision for income taxes ......... 166,590 121,168 87,531
Provision for income taxes ....................... 61,191 45,361 25,489
--------- --------- ---------
Net income ....................................... $ 105,399 $ 75,807 $ 62,042
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-35
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
OUTSTANDING ADDITIONAL
COMMON COMMON PAID-IN RETAINED
SHARES STOCK CAPITAL EARNINGS TOTAL
------------- -------- ----------- ------------- -------------
<S> <C> <C> <C> <C> <C>
BALANCE, January 1, 1996 ........... 100 $-- $501,626 $ 34,616 $ 536,242
Net income ........................ -- -- -- 62,042 62,042
--- --- -------- ---------- ----------
BALANCE, December 31, 1996 ......... 100 -- 501,626 96,658 598,284
Net income ........................ -- -- -- 75,807 75,807
--- --- -------- ---------- ----------
BALANCE, December 31, 1997 ......... 100 -- 501,626 172,465 674,091
Distribution ...................... -- -- -- (170,000) (170,000)
Net income ........................ -- -- -- 105,399 105,399
--- --- -------- ---------- ----------
BALANCE, December 31, 1998 ......... 100 $-- $501,626 $ 107,864 $ 609,490
=== === ======== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-36
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997 1996
------------- ------------ -------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..................................................... $ 105,399 $ 75,807 $ 62,042
ADJUSTMENTS TO RECONCILE NET CASH FLOWS FROM OPERATING
ACTIVITIES:
Depreciation and amortization .................................. 105,876 89,134 69,853
Provision for deferred income taxes ............................ 18,533 17,277 7,277
CHANGES IN OTHER ITEMS:
Accounts receivable .......................................... (32,984) (12,445) (7,735)
Decrease (increase) in inventory ............................. (3,122) 3,725 (5,743)
Accounts payable and other accrued liabilities ............... 33,326 (19,508) 3,325
Other assets ................................................. 567 984 14,147
---------- ---------- ----------
Net cash flows from operating activities .................. 227,595 154,974 143,166
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................... (102,842) (50,907) (190,152)
Purchase of Partnership Interest, net of cash acquired ......... -- -- (58,044)
Decrease (increase) in restricted cash ......................... (215,696) 14,044 43,172
---------- ---------- ----------
Net cash flows from investing activities .................. (318,538) (36,863) (205,024)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Due from parent ................................................ 124,597 (12,230) (53,203)
Proceeds from debt offerings ................................... 285,000 -- 135,000
Repayment of Salton Sea notes and bonds ........................ (106,938) (90,228) (48,106)
Repayment of project loans ..................................... (22,851) -- (102,999)
Proceeds from construction and other loans ..................... -- 38,776 101,018
Distribution to parent ......................................... (170,000) -- --
Deferred charge relating to debt financing ..................... (4,943) (11,623) (11,749)
Decrease (increase) in restricted cash ......................... 26,688 (42,184) 15,899
---------- ---------- ----------
Net cash flows from financing activities .................. 131,553 (117,489) 35,860
---------- ---------- ----------
Net increase (decrease) in cash and cash equivalents ............ 40,610 622 (25,998)
Cash and cash equivalents at beginning of year .................. 14,051 13,429 39,427
---------- ---------- ----------
Cash and cash equivalents at end of year ........................ $ 54,661 $ 14,051 $ 13,429
========== ========== ==========
Interest paid (net of amounts capitalized) ...................... $ 54,048 $ 50,802 $ 49,129
========== ========== ==========
Income taxes paid ............................................... $ 42,658 $ 28,084 $ 18,212
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-37
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(DOLLARS AND SHARES IN THOUSANDS)
1. BUSINESS
Magma Power Company (the "Company" or "Magma"), a wholly-owned subsidiary
of MidAmerican Energy Holdings Company ("MEHC"), the successor of CalEnergy
Company, Inc. (CalEnergy), is primarily engaged in the exploration for and
development of geothermal resources and conversion of such resources into
electrical power and steam for sale to electric utilities, and the development
of other environmentally responsible forms of power generation.
The Company currently operates eight and is constructing two geothermal
power plants in the Imperial Valley in California. On April 17, 1996 the
Company completed the acquisition of Edison Mission Energy's partnership
interests (the "Partnership Interest Acquisition") in four geothermal operating
facilities in California for a cash purchase price of $71,000 including
acquisition costs. The four projects, Vulcan, Hoch (Del Ranch), Leathers and
Elmore are located in the Imperial Valley of California. Prior to this
transaction, the Company was a 50% owner of these facilities. The remaining
four plants are the Salton Sea Project which are wholly-owned by subsidiaries
of the Company. These geothermal power plants consist of the Salton Sea I,
Salton Sea II, Salton Sea III, and Salton Sea IV. The Salton Sea IV project
commenced operations in June 1996. In 1998, the Company began construction of
the Salton Sea Unit V and CE Turbo projects which are scheduled to commence
commercial operation in fiscal 2000.
In 1995 the Company, through its wholly-owned subsidiary, Visayas
Geothermal Power Company ("VGPC"), began construction of the Malitbog
Geothermal Project on the island of Leyte in the Republic of the Philippines.
Unit I was deemed complete on July 25, 1996. Units II and III were deemed
complete on July 25, 1997.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries. Prior to the Partnership Interest
Acquisition in 1996, the consolidated financial statements include the
Company's proportionate share of the joint ventures in which it had an
undivided interest in the assets and was proportionately liable for its share
of liabilities. All significant inter-enterprise transactions and accounts have
been eliminated. The results of operations of the Company include the Company's
proportionate share of the results of operations of entities acquired as of the
date of acquisition.
The consolidated financial statements reflect the acquisition by CalEnergy
and the resulting push down to the Company of the accounting as a purchase
business combination.
Management believes the financial statements reflect all material costs
associated with the Company's operations.
CASH EQUIVALENTS--The Company considers all investment instruments
purchased with an original maturity of three months or less to be cash
equivalents. Restricted cash is not considered a cash equivalent.
RESTRICTED CASH--The restricted cash balance is composed of restricted
accounts for debt service and capital expenditures. The debt service reserve
funds are legally restricted as to their use and require the maintenance of
specific minimum balances equal to the net debt service payment.
The capital expenditure funds are restricted for use in the construction
of Salton Sea V, the CE Turbo Project and the construction of new brine
facilities at the Imperial Valley Projects, which resulted from the sale on
October 13, 1998 by Salton Sea Funding Corporation of $285,000 aggregate amount
of 7.475% Senior Secured Series F Bonds due November 30, 2018 (see Note 6).
F-38
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
WELL COSTS--The cost of drilling and equipping production wells and other
direct costs, are capitalized and amortized on a straight-line basis over their
estimated useful lives when production commences. The estimated useful lives of
production wells are twenty years.
DEFERRED WELL AND REWORK COSTS-- Geothermal rework costs are deferred and
amortized over the estimated period between reworks ranging from 18 months to
24 months. These deferred costs, net of accumulated amortization, are $6,709
and $4,811 at December 31, 1998 and 1997, respectively, and are included in
other assets.
PROPERTIES, PLANTS, CONTRACTS, EQUIPMENT AND DEPRECIATION--The cost of
major additions and betterments are capitalized, while replacements,
maintenance, and repairs that do not improve or extend the lives of the
respective assets are expensed.
Depreciation of the operating power plant costs, net of salvage value, is
computed on the straight line method over the estimated useful life of 30
years. Depreciation of furniture, fixtures and equipment is computed on the
straight line method over the estimated useful lives of the related assets,
which range from three to ten years.
The Magma and Partnership Interest Acquisitions by the Company have been
accounted for as purchase business combinations. All identifiable assets
acquired and liabilities assumed were assigned a portion of the cost of
acquiring the respective companies, equal to their fair values at the date of
the acquisition and include the following:
o Power sales agreements are amortized separately over (1) the remaining
portion of the scheduled price periods of the power sales agreements and
(2) the 20 year avoided cost periods of the power sales agreements using
the straight line method.
o The carrying value of the mineral reserves will be amortized upon
commencement of commercial operation.
EXCESS OF COST OVER FAIR VALUE--Total acquisition costs in excess of the
fair values assigned to the net assets acquired are amortized over a 40 year
period using the straight line method. Accumulated amortization was $30,217 and
$22,487 at December 31, 1998 and 1997, respectively.
CAPITALIZATION OF INTEREST AND DEFERRED FINANCING COSTS--Prior to the
commencement of operations, interest is capitalized on the costs of the plants
and geothermal resource development to the extent incurred. Capitalized
interest and other deferred charges are amortized over the lives of the related
assets.
Deferred financing costs are amortized over the term of the related
financing using the effective interest method.
REVENUE RECOGNITION--Revenues are recorded based upon electricity and
steam delivered to the end of the month. See Note 4 for contractual terms of
power sales agreements. Royalties earned from providing geothermal resources to
power plants operated by other geothermal power producers are recorded when
delivered.
INCOME TAXES--The Company has historically been included in the
consolidated income tax returns of MEHC. The Company's provision for income
taxes is computed on a separate return basis. The Company recognizes deferred
tax assets and liabilities based on the difference between the financial
statement and tax bases of assets and liabilities using estimated tax rates in
effect for the year in which the differences are expected to reverse.
F-39
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
FAIR VALUES OF FINANCIAL INSTRUMENTS--Fair values have been estimated
based on quoted market prices for debt issues actively traded or on market
prices of similar instruments and/or valuation techniques using market
assumptions.
IMPAIRMENT OF LONG-LIVED ASSETS--The Company reviews long-lived assets and
certain identifiable intangibles 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.
START-UP COSTS--In 1998, the Company adopted SOP No. 98-5, Reporting on
the Costs of Start-Up Activities, which requires costs of start-up activities
and organization costs be expensed as incurred. Such adoption had no
significant effect on the Company.
CHANGE IN ACCOUNTING ESTIMATE--During the year ended December 31, 1998, the
Company modified the amortization method to amortize the fair value adjustments
associated with the scheduled price periods of the four plants acquired in the
Imperial Valley. The Company modified its amortization method from the weighted
average of the scheduled price periods to amortization of the fair value
adjustments over the scheduled price periods of the individual plant. The change
in accounting estimate included increasing the accumulated amortization of the
aggregate fair value adjustment associated with the scheduled price periods of
the four plants acquired in the Imperial Valley. The impact of the change was to
decrease 1998 net income by $4.7 million. This change will not have a
significant impact on future periods as the scheduled price period terminates in
1999.
USE OF ESTIMATES--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.
ACCOUNTING PRONOUNCEMENTS--In June 1998, the FASB issued SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, which estabilshed
accounting and reporting standards for derivative instruments and for hedging
activities. It requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. This statement is effective for all fiscal quarters
of fiscal years beginning after June 15, 2000. The Company has not yet
determined the impact of this accounting pronouncement.
3. ACQUISITIONS
MAGMA POWER COMPANY--On January 10, 1995, CalEnergy acquired approximately
51% of the outstanding shares of common stock of the Company through a cash
tender offer and completed the acquisition on February 24, 1995 by acquiring
the remaining 49% of outstanding shares of common stock through a merger (the
"Magma Acquisition").
The Magma Acquisition has been accounted for as a purchase business
combination. All identifiable assets acquired and liabilities assumed were
assigned a portion of the cost of acquiring Magma, equal to their fair values
at the date of the acquisition.
EDISON MISSION ENERGY'S PARTNERSHIP INTEREST--On April 17, 1996 the
Company completed the acquisition of Edison Mission Energy's partnership
interests (the "Partnership Interest Acquisition") in four geothermal operating
facilities in California for a cash purchase price of $71,000 including
F-40
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
acquisition costs. The four projects, Vulcan, Hoch (Del Ranch), Leathers and
Elmore are located in the Imperial Valley of California. Prior to this
transaction, the Company was a 50% owner of these facilities and consolidated
these entities using the proportional consolidation method.
The Partnership Interest Acquisition has been accounted for as a purchase
business combination. All identifiable assets acquired and liabilities assumed
were assigned a portion of the cost of acquiring the Partnership Interest,
equal to their fair values at the date of the acquisition.
Unaudited pro forma combined revenue and net income of the Company and the
Partnership Interest for the twelve months ended December 31, 1996, as if the
acquisition had occurred at the beginning of 1996 after giving effect to
certain pro forma adjustments related to the acquisition were $284,193 and
$63,135, respectively.
4. PROPERTIES, PLANTS, CONTRACTS AND EQUIPMENT
Properties, plants, contracts and equipment comprise the following at
December 31:
<TABLE>
<CAPTION>
1998 1997
--------------- ---------------
<S> <C> <C>
Power plants ............................................ $ 768,155 $ 741,853
Wells and resource development .......................... 137,399 124,500
Power sales agreements .................................. 264,371 264,371
Licenses and equipment .................................. 46,290 46,290
----------- -----------
Total operating facilities .............................. 1,216,215 1,177,014
Less accumulated depreciation and amortization .......... (284,664) (185,085)
----------- -----------
Net operating facilities ................................ 931,551 991,929
Mineral reserves ........................................ 240,114 211,674
Construction in progress:
Other development ..................................... 40,657 4,002
----------- -----------
Total ................................................ $ 1,212,322 $ 1,207,605
=========== ===========
</TABLE>
IMPERIAL VALLEY PROJECT OPERATING FACILITIES--The Partnership Project and
the Salton Sea Project are collectively referred to as the Imperial Valley
Project. The following table sets out information regarding the Company's
projects:
<TABLE>
<CAPTION>
COMMERCIAL
PROJECT OPERATION CAPACITY
- ------------------ ----------- ---------
<S> <C> <C>
Vulcan 1986 34 MW
Del Ranch 1989 38 MW
Elmore 1989 38 MW
Leathers 1990 38 MW
Salton Sea I 1987 10 MW
Salton Sea II 1990 20 MW
Salton Sea III 1989 49.8 MW
Salton Sea IV 1996 39.6 MW
Salton Sea V 2000 49 MW
CE Turbo 2000 10 MW
</TABLE>
SIGNIFICANT CUSTOMERS AND CONTRACTS--All of the Company's sales of
electricity from the Imperial Valley Project, which comprise approximately 74%
of 1998 and 1997 electricity and steam revenues, are to Southern California
Edison Company ("Edison") and are under long-term power purchase
F-41
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
contracts. Accounts receivable, which are primarily from Edison, are primarily
uncollateralized receivables from long-term power purchase contracts described
below. If the customers were unable to perform, the Company could incur an
accounting loss equal to the entire receivable balance of $90,395 and $57,411 at
December 31, 1998 and 1997, respectively.
The current Partnership Projects sell all electricity generated by the
respective plants pursuant to four long-term standard offer no. 4, or SO4,
Agreements between the projects and Edison that are based on this standard
form. These SO4 Agreements provide for capacity payments, capacity bonus
payments and energy payments. Edison makes fixed annual capacity and capacity
bonus payments to the Projects to the extent that capacity factors exceed
certain benchmarks. The price for capacity and capacity bonus payments is fixed
for the life of the SO4 Agreements. Energy is sold at increasing scheduled
rates for the first ten years after firm operation and thereafter at a rate
which is based on the cost that Southern California Edison avoids by purchasing
energy from the project instead of obtaining the energy from other sources.
Southern California Edison's avoided cost is currently determined by an
approved interim formula which adjusts historic costs by an inflation/deflation
factor representing monthly changes in the cost of natural gas at the
California border and adjustment factors based on the time the day, week and
year in which the energy is delivered. Consequently, under this methodology,
energy payments under the SO4 agreements will fluctuate based on the time of
generation and monthly changes in average fuel costs in the California energy
market. Legislation recently adopted in California establishes that price
qualifying facilities receive as energy payments would be modified from the
current short-run avoided cost basis to the clearing price estabilshed by the
PX once specified conditions are met. As the main condition, the legislation
requires that the California Public Utilities Commission must first issue an
order determining that the PX is functioning properly for the purposes of
determininig the short-run avoided cost energy payments to be made to
non-utility power generators. Additionally, a project company may, upon
appropriate notice to Southern California Edison, exercise a one-time option to
elect to thereafter receive energy payments based upon the clearing price from
the PX.
The PX is a nonprofit public benefit corporation formed under California
law to provide a competitive marketplace where buyers and sellers of power,
including utilities, end-use customers, independent power producers and power
marketers, complete wholesale trades through an electronic auction. The PX
currently operates two markets: (1) a day ahead market which is comprised of
twenty-four separate concurrent auctions for each hour of the following day and
(2) an hour ahead market for each hour of each day for which bids are due two
hours before each hour. In each market, the PX receives bids from buyers and
sellers and, based on the bids, establishes the market clearing price for each
hour and schedules deliveries from sellers whose bids did not exceed the market
clearing price to buyers whose bids were not less than the market clearing
price. All trades are executed at the market clearing price.
The scheduled energy price periods of the Partnership Project SO4
agreements extended until February 1996, December 1998 and December 1998 for
each of the Vulcan, Del Ranch and Elmore Partnerships, respectively, and extend
until December 1999 for the Leathers Partnership. Del Ranch and Elmore
Parnerships' SO4 agreements provided for energy rates of 14.6 cents per kWh in
1998. Leathers Partnership SO4 agreement provides for an energy rate of 14.6
cents per kWh in 1998 and 15.6 cents per kWh in 1999. The weighted average
energy rate for all of the Partnership Projects' SO4 agreements was 11.7 cents
per kWh in 1998.
Salton Sea I sells electricity to Edison pursuant to a 30-year negotiated
power purchase agreement, as amended (the "Salton Sea I PPA"), which provides
for capacity and energy payments.
F-42
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
The energy payment is calculated using a Base Price which is subject to
quarterly adjustments based on a basket of indices. The time period weighted
average energy payment for Salton Sea I was 5.4 cents per kWh during 1998. As
the Salton Sea I PPA is not an SO4 Agreement, the energy payments do not revert
to Edison's Avoided Cost of Energy. The capacity payment is approximately $1,100
per annum.
Salton Sea II and Salton Sea III sell electricity to Edison pursuant to
30-year modified SO4 Agreements that provide for capacity payments, capacity
bonus payments and energy payments. The price for contract capacity and contract
capacity bonus payments is fixed for the life of the modified SO4 Agreements.
The energy payments for the first ten year period, which periods expire in April
2000 and February 1999, respectively, are levelized at a time period weighted
average of 10.6 per kWh and 9.8 per kWh for Salton Sea II and Salton Sea III,
respectively. Thereafter, the monthly energy payments will be at Edison's
Avoided Cost of Energy. For Salton Sea II only, Edison is entitled to receive,
at no cost, 5% of all energy delivered in excess of 80% of contract capacity
through September 30, 2004. The annual capacity and bonus payments for Salton
Sea II and Salton Sea III are approximately $3,300 and $9,700, respectively.
Salton Sea IV sells electricity to Edison pursuant to a modified SO4
agreement which provides for contract capacity payments on 34 MW of capacity at
two different rates based on the respective contract capacities deemed
attributable to the original Salton Sea PPA option (20 MW) and to the original
Fish Lake PPA (14 MW). The capacity payment price for the 20 MW portion adjusts
quarterly based upon specified indices and the capacity payment price for the
14 MW portion is a fixed levelized rate. The energy payment (for deliveries up
to a rate of 39.6 MW) is at a fixed price for 55.6% of the total energy
delivered by Salton Sea IV and is based on an energy payment schedule for 44.4%
of the total energy delivered by Salton Sea IV. The contract has a 30-year term
but Edison is not required to purchase the 20 MW of capacity and energy
originally attributable to the Salton Sea I PPA option after September 30,
2017, the original termination date of the Salton Sea I PPA.
For the years ended December 31, 1998, 1997 and 1996, Edison's average
Avoided Cost of Energy was 3.0 cents, 3.3 cents and 2.5 cents per kWh,
respectively, 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 Company cannot predict the
likely level of Avoided Cost of Energy or PX prices under the SO4 Agreements
and the modified SO4 Agreements at the expiration of the scheduled payment
periods. The revenues generated by each of the projects operating under SO4
Agreements could decline significantly after the expiration of the respective
scheduled payment periods.
The Imperial Valley Projects other than Salton Sea Unit I receive
transmission service from the Imperial Irrigation District to deliver
electricity to Southern California Edison near Mirage, California. These
projects pay a rate based on the Imperial Irrigation District's cost of service
which was $1.52 per month per kilowatt of service provided for 1998 and is
recalculated annually. The transmission service and interconnection agreements
expire in 2015 for the Partnership Projects, 2019 for Salton Sea Unit III, 2020
for Salton Sea Unit II and 2026 for Salton Sea Unit IV. Salton Sea Unit V and
the CE Turbo projects have entered into 30-year agreements with similar terms
with the Imperial Irrigation District. Salton Sea Unit I delivers energy to
Southern California Edison at the project site and has no transmission service
agreement with the Imperial Irrigation District.
The Partnership Project pays royalties based on both energy revenues and
total electricity revenues. Del Ranch and Leathers pay royalties of 5% of
energy revenues and 1% of total electricity revenue. Elmore pays royalties of
5% of energy revenues. Vulcan pays royalties of 4.167% of energy revenues.
F-43
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
The Salton Sea Project's weighted average royalty expense in 1998, 1997
and 1996 was approximately 4.8%, 6.1% and 5.2%, respectively. The royalties are
paid to numerous recipients based on varying percentages of electrical revenue
or steam production multiplied by published indices.
ROYALTIES--Royalty expense for the years ended December 31, 1998, 1997 and
1996, which is included in plant operations in the consolidated statements of
operations, comprise the following:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Vulcan ..................... $ 363 $ 326 $ 361
Leathers ................... 2,811 2,694 2,203
Elmore ..................... 2,192 2,213 1,883
Del Ranch .................. 2,870 2,650 2,255
Salton Sea I & II .......... 810 1,206 634
Salton Sea III ............. 1,637 2,439 1,334
Salton Sea IV .............. 2,645 2,815 1,558
-------- -------- --------
Total ...................... $ 13,328 $ 14,343 $ 10,228
======== ======== ========
</TABLE>
The Partnership Project pays royalties based on both energy revenues and
total electricity revenues. Hoch (Del Ranch) and Leathers pay royalties of
approximately 5% of energy revenues and 1% of total electricity revenue. Elmore
pays royalties of approximately 5% of energy revenues. Vulcan pays royalties of
4.167% of energy revenues.
The Salton Sea Project's weighted average royalty expense in 1998 and 1997
was approximately 4.8% and 6.1%, respectively. The royalties are paid to
numerous recipients based on varying percentages of electrical revenue or steam
production multiplied by published indices.
5. MALITBOG LOANS
On April 8, 1998, the Company converted the construction project financing
for its Malitbog geothermal power project to term loans. The Overseas Private
Investment Corporation ("OPIC") is providing term loan financing of $54,868
that was fixed as of June 15, 1998 at an interest rate of 9.176%. A syndicate
of international commercial banks is providing term loan financing of $98,938
at a variable interest rate based on LIBOR (7.47% at December 31, 1998). Annual
repayments of the Malitbog loans for the years beginning January 1, 1999 and
thereafter are as follows:
<TABLE>
<S> <C>
1999 ............... $ 22,560
2000 ............... 22,560
2001 ............... 22,560
2002 ............... 22,560
2003 ............... 22,560
Thereafter ......... 41,006
--------
$153,806
========
</TABLE>
6. NOTES AND BONDS
Each of the Company's direct or indirect subsidiaries is organized as a
legal entity separate and apart from the Company and its other subsidiaries.
Pursuant to separate project financing agreements, the assets of each
subsidiary are pledged or encumbered to support or otherwise provide the
security
F-44
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
for their own project or subsidiary debt. It should not be assumed
that any asset of any such subsidiary will be available to satisfy the
obligations of the Company or any of its other such subsidiaries; provided,
however, that unrestricted cash or other assets which are available for
distribution may, subject to applicable law and the terms of financing
arrangements of such parties, be advanced, loaned, paid as dividends or
otherwise distributed or contributed to the Company or affiliates thereof.
"Subsidiaries" means all of the Company's direct or indirect subsidiaries (1)
owning interests in the Imperial Valley and Malitbog projects or (2) owning
interests in the subsidiaries that own interests in the foregoing projects.
SALTON SEA NOTES AND BONDS--The Salton Sea Funding Corporation, a wholly
owned subsidiary of the Company, (the "Funding Corporation") debt securities
are as follows:
<TABLE>
<CAPTION>
SENIOR FINAL DECEMBER 31,
SECURED MATURITY -------------------------
SERIES DATE RATE 1998 1997
--------- ------------------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
July 21, 1995 ......... A Notes May 30, 2000 6.69% $ 48,436 $ 97,354
July 21, 1995 ......... B Bonds May 30, 2005 7.37 106,980 133,000
July 21, 1995 ......... C Bonds May 30, 2010 7.84 109,250 109,250
June 20, 1996 ......... D Notes May 30, 2000 7.02 12,150 44,150
June 20, 1996 ......... E Bonds May 30, 2011 8.30 65,000 65,000
July 30, 1999 ......... F Bonds November 30, 2018 7.475 285,000 --
--------- ---------
$ 626,816 $ 448,754
========= =========
</TABLE>
Principal and interest payments are made in semi-annual installments. The
Salton Sea Notes and Bonds are nonrecourse to the Company.
The net revenues, equity distributions and royalties from the Partnership
Projects are used to pay principal and interest payments on outstanding senior
secured bonds issued by the Funding Corporation, the final series of which is
scheduled to mature in November 2018. The Funding Corporation Debt is
guaranteed by certain subsidiaries of Magma and secured by the capital stock of
the Funding Corporation. The proceeds of the Funding Corporation Debt were
loaned by the Funding Corporation pursuant to loan agreements and notes (the
"Imperial Valley Project Loans") to certain subsidiaries of Magma and used for
construction of certain Imperial Valley Projects, refinancing of certain
indebtedness and other purposes. Debt service on the Imperial Valley Project
Loans is used to repay debt service on the Funding Corporation Debt. The
Imperial Valley Project Loans and the guarantees of the Funding Corporation
Debt are secured by substantially all of the assets of the guarantors,
including the Imperial Valley Projects, and by the equity interests in the
guarantors.
The proceeds of Series F of the Funding Corporation debt are being used in
part to construct the Zinc Facility, and the direct and indirect owners of the
Zinc Facility (the "Zinc Guarantors", which will include Salton Sea Minerals
Corp. and Minerals LLC), are among the guarantors of the Funding Corporation
debt. In connection with the Divestiture, MEHC will guarantee the payment by
the Zinc Guarantors of a specified portion of the scheduled debt service on the
Imperial Valley Project Loans, including the current principal amount of
$140,520 and associated interest.
Pursuant to a depository agreement, Funding Corporation established a debt
service reserve fund in the form of a letter of credit in the amount of $70,430
from which scheduled interest and principal payments can be made.
F-45
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
Annual repayments of the Salton Sea Notes and Bonds for the years
beginning January 1, 1999 and thereafter are as follows:
<TABLE>
<S> <C>
1999 ............... $ 57,836
2000 ............... 25,072
2001 ............... 23,658
2002 ............... 28,572
2003 ............... 28,086
Thereafter ......... 463,592
---------
$ 626,816
=========
</TABLE>
The Company's ability to obtain distributions from its investment in the
Salton Sea Projects and Partnership Projects is subject to the following
conditions:
o the depository accounts for the Salton Sea Notes and Bonds must be
fully funded;
o there cannot have occurred any default or event of default under the
Salton Sea Notes and Bonds;
o the historical debt service coverage ratio of Salton Sea Funding
Corporation for the prior four fiscal quarters must be at least 1.4
to 1.0, if the distribution occurs prior to 2000, or 1.5 to 1.0, if
the distribution occurs during or after 2000;
o there must be sufficient geothermal resources to operate the Salton
Sea projects at their required levels; and
o each Salton Sea project under consturction cannot have failed to be
complete by its guaranteed substantial completion date, unless a
sufficient portion of the Salton Sea Notes and Bonds have been
redeemed or a ratings confirmation has been obtained.
7. RELATED PARTY TRANSACTIONS
On July 21, 1995, CalEnergy issued $200,000 of 9 7/8% Limited Recourse
Senior Secured Notes Due 2003 (the "Notes"). Interest on the Notes is payable
on June 30 and December 30 of each year, commencing December 1995. The Notes
are secured by an assignment and pledge of 100% of the outstanding capital
stock of Magma and are recourse only to such Magma capital stock, CalEnergy's
interest in a secured Magma note and general assets of CalEnergy equal to the
Restricted Payment Recourse Amount (as defined in the Note Indenture) which was
$0 at December 31, 1998.
On or after June 30, 2000, the Notes are redeemable at the option of
CalEnergy, in whole or in part, initially at a redemption price of 104.9375%
declining to 100% on June 30, 2002 and thereafter, plus accrued interest to the
date of redemption (see Note 11).
The due from and due to parent balances in the Company's financial
statements are the result of MEHC's central cash management policy. MEHC's
policy is to have Magma distribute all available cash to the parent company and
have the parent company remit payment for most expenses incurred by Magma. As a
result, the due from and due to parent balances are simply a function of the
timing of cash receipts and cash distributions between MEHC and Magma.
F-46
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
8. INCOME TAXES
Provision for income tax is comprised of the following at December 31:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ---------- ----------
<S> <C> <C> <C>
Currently payable:
State ........... $ 13,443 $ 7,488 $ 6,420
Federal ......... 29,215 20,596 11,792
-------- -------- --------
42,658 28,084 18,212
Deferred:
State ........... 237 1,342 1,232
Federal ......... 15,748 15,207 4,908
Foreign ......... 2,548 728 1,137
-------- -------- --------
18,533 17,277 7,277
-------- -------- --------
Total ......... $ 61,191 $ 45,361 $ 25,489
======== ======== ========
</TABLE>
The deferred expense is primarily temporary differences associated with
depreciation and amortization of certain assets.
A reconciliation of the federal statutory tax rate to the effective tax
rate applicable to income before provision for income taxes follows:
<TABLE>
<CAPTION>
1998 1997 1996
----------- ----------- -----------
<S> <C> <C> <C>
Federal statutory rate .................................... 35.00% 35.00% 35.00%
Percentage depletion in excess of cost depletion .......... (3.80) (4.30) ( 5.15)
Investment and energy tax credits ......................... (1.33) (0.84) (12.30)
State taxes, net of federal tax effect .................... 4.75 4.74 4.26
Goodwill amortization ..................................... 1.63 2.24 3.10
Tax effect of foreign income .............................. 0.48 0.60 1.30
Other ..................................................... -- -- 2.91
----- ----- ------
36.73% 37.44% 29.12%
===== ===== ======
</TABLE>
Deferred tax liabilities (assets) are comprised of the following at
December 31:
<TABLE>
<CAPTION>
1998 1997
------------ ------------
<S> <C> <C>
Depreciation and amortization, net .......................... $ 251,859 $ 249,622
Unremitted foreign earnings ................................. 21,464 14,112
Other ....................................................... 91 77
--------- ---------
273,414 263,811
Accruals not currently deductible for tax purposes .......... (13,171) (2,304)
Tax credits ................................................. (7,023) (19,692)
Jr. SO4 royalty receivable .................................. -- (5,865)
Deferred income ............................................. (6,301) (7,588)
Other ....................................................... (140) (116)
--------- ---------
(26,635) (35,565)
--------- ---------
Net deferred taxes .......................................... $ 246,779 $ 228,246
========= =========
</TABLE>
F-47
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Although management uses its best
judgment in estimating the fair value of these financial instruments, there are
inherent limitations in any estimation technique. Therefore, the fair value
estimates presented herein are not necessarily indicative of the amounts which
the Company could realize in a current transaction.
The fair value of all debt issues listed on exchanges, including the note
payable to related party which is based on a debt issue listed on an exchange,
has been estimated based on the quoted market prices. The remaining note
payable to related party, which is not based on market prices, and the project
loan are estimated to have a fair value equal to the carrying value.
The carrying amounts in the table below are included in the consolidated
balance sheets under the indicated captions.
<TABLE>
<CAPTION>
1998 1997
-------------------------- ---------------------------
ESTIMATED ESTIMATED
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
------------ ----------- ------------ ------------
<S> <C> <C> <C> <C>
Construction and project loans ......... $ 153,806 $ 153,806 $ 176,657 $ 176,657
Salton Sea notes and bonds ............. 626,816 646,397 448,754 463,720
Note payable to related party .......... 200,000 217,900 200,000 217,829
</TABLE>
10. COMMITMENTS AND CONTINGENCIES
Salton Sea Unit V is obligated to supply the electricity demands of the
Zinc Recovery Project at the price available to Salton Sea Unit V from the PX
less the wheeling costs to the PX.
Salton Sea Power, L.L.C., one of our indirect wholly-owned subsidiaries,
is constructing Salton Sea Unit V. Salton Sea Unit V will be a 49 net megawatt
geothermal power plant which will sell approximately one-third of its net
output to the zinc facility, which will be retained by MidAmerican. The
remainder will be sold through the California power exchange.
Salton Sea Unit V is being constructed pursuant to a date certain, fixed
price, turnkey engineering, procurement and construction contract by Stone &
Webster Engineering Corporation. Salton Sea Unit V is scheduled to commence
commercial operation in mid-2000. Total project costs of Salton Sea Unit V are
expected to be approximately $119,067 which will be funded by $76,281 of debt
from Salton Sea Funding Corporation and $42,786 from equity contributions.
CE Turbo LLC, one of our indirect wholly-owned subsidiaries, is
constructing the CE Turbo project. The CE Turbo project will have a capacity of
10 net megawatts. The net output of the CE Turbo project will be sold to the
zinc facility or sold through the California power exchange.
The partnership projects are upgrading the geothermal brine processing
facilities at the Vulcan and Del Ranch projects with the region 2 brine
facilities construction.
The CE Turbo project and the region 2 brine facilities construction are
being constructed by Stone & Webster pursuant to a date certain, fixed price,
turnkey engineering, procurement and construction contract. The obligations of
Stone & Webster are guaranteed by Stone & Webster, Incorporated. The CE Turbo
project is scheduled to commence initial operations in early-2000 and the
F-48
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996 (CONTINUED)
(DOLLARS AND SHARES IN THOUSANDS)
region 2 brine facilities construction is scheduled to be completed in
early-2000. Total project costs for both the CE Turbo project and the region 2
brine facilities construction are expected to be approximately $63,747 which
will be funded by $55,602 of debt from Salton Sea Funding Corporation and
$8,145 from equity contributions.
11. SUBSEQUENT EVENTS
On February 8, 1999, MidAmerican created a new subsidiary, CE Generation
LLC ("CE Generation") and subsequently transferred its interest in the Company
and its power generation assets in the Imperial Valley ("Contributed
Subsidiaries") to CE Generation, with VGPC and Minerals, LLC being retained by
MidAmerican ("Excluded Subsidiaries"). During the years ended December 31,
1998, 1997 and 1996, the Excluded Subsidiaries' revenues and net income were
$80,877, $42,288 and $13,293, respectively, and $17,039, $14,350 and $16,203,
respectively. On March 3, 1999, MidAmerican closed the sale of 50% of its
ownership interests in CE Generation to an affiliate of El Paso Energy
Corporation.
On January 29, 1999, MEHC commenced a cash offer for all of its
outstanding 9 7/8% Limited Recourse Senior Secured Notes Due 2003. MEHC
received tenders from holders of an aggregate of approximately $195.8 million
principal which were paid on March 3, 1999, at a redemption price of 110.025%
plus accrued interest, resulting in an extraordinary loss of approximately
$17.5 million, net of tax.
F-49
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED BALANCE SHEETS
AS OF SEPTEMBER 30, 1999 AND DECEMBER 31, 1998
(DOLLARS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
--------------- -------------
<S> <C> <C>
ASSETS
Cash and cash equivalents ............................................ $ 36,408 $ 54,661
Restricted cash ...................................................... 10,892 25,147
Accounts receivable .................................................. 51,065 90,395
Due from parent ...................................................... 15,485 --
Prepaid expenses ..................................................... 7,787 21,677
Inventory ............................................................ 13,322 11,802
Other assets ......................................................... 1,105 6,999
----------- -----------
Total current assets .............................................. 136,064 210,681
Restricted cash ...................................................... 34,173 215,696
Note receivable from related party ................................... 140,520 --
Properties, plants, contracts and equipment, net ..................... 799,470 1,212,322
Excess of cost over fair value of net assets acquired, net ........... 202,740 283,552
Deferred charges and other assets .................................... 14,702 36,808
----------- -----------
Total assets ...................................................... $ 1,327,669 $ 1,959,059
=========== ===========
LIABILITIES AND STOCKHOLDER'S EQUITY
LIABILITIES:
Accounts payable and accrued liabilities ............................. $ 39,377 $ 45,418
Current portion of long-term debt .................................... 51,430 80,396
Due to parent ........................................................ -- 43,673
Deferred income taxes -- current ..................................... -- 1,221
----------- -----------
Total current liabilities ......................................... 90,807 170,708
Malitbog loans ....................................................... -- 131,246
Salton Sea notes and bonds ........................................... 546,468 568,980
Note payable to related party ........................................ -- 200,000
Deferred income taxes ................................................ 163,103 245,558
Other long-term liabilities .......................................... 1,009 930
----------- -----------
Total liabilities ................................................. 801,387 1,317,422
----------- -----------
DEFERRED INCOME ...................................................... -- 32,147
STOCKHOLDER'S EQUITY:
Preferred stock -- par value $0.10 per share, authorized 1,000 shares -- --
Common stock -- par value $0.10 per share, authorized 30,000 shares,
outstanding 100 shares .............................................. -- --
Additional paid in capital ........................................... 501,626 501,626
Retained earnings .................................................... 24,656 107,864
----------- -----------
Total stockholder's equity ........................................ 526,282 609,490
----------- -----------
Total liabilities and stockholder's equity ........................ $ 1,327,669 $ 1,959,059
=========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-50
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
REVENUE:
Sales of electricity and steam ......................................... $ 158,470 $ 276,232
Royalty income ......................................................... 1,689 1,785
Interest and other income .............................................. 11,968 18,671
--------- ---------
Total revenues ....................................................... 172,127 296,688
--------- ---------
COST AND EXPENSES:
Plant operations ....................................................... 44,971 51,084
General and administration ............................................. 1,327 1,564
Depreciation and amortization .......................................... 33,278 79,778
Interest expense ....................................................... 35,450 54,885
Less interest capitalized .............................................. (4,440) (15,313)
--------- ---------
Total expenses ....................................................... 110,586 171,998
--------- ---------
Income before provision for income taxes and extraordinary item ......... 61,541 124,690
Provision for income taxes .............................................. 14,524 43,642
--------- ---------
Income before extraordinary item ........................................ 47,017 81,048
Extraordinary item, net of tax .......................................... (17,478) --
--------- ---------
Net income .............................................................. $ 29,539 $ 81,048
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-51
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
------------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ........................................................... $ 29,539 $ 81,048
ADJUSTMENTS TO RECONCILE NET CASH FLOWS FROM OPERATING ACTIVITIES:
Depreciation and amortization ........................................ 33,278 79,778
Provision for deferred income taxes .................................. (6,579) 13,900
Extraordinary item, net of tax ....................................... 17,478 --
CHANGES IN OTHER ITEMS:
Accounts receivable ................................................ 4,839 (39,217)
Decrease (increase) in inventory ................................... (1,520) (2,105)
Accounts payable and other accrued liabilities ..................... (14,119) 46,430
Other assets ....................................................... 15,202 (704)
---------- ---------
Net cash flows from operating activities ........................ 78,118 179,130
---------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ................................................. (82,519) (58,410)
Cash distributed in spin-off ......................................... (677) --
Decrease (increase) in restricted cash ............................... 69,866 --
---------- ---------
Net cash flows from investing activities ........................ (13,330) (58,410)
---------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Due from affiliate ................................................... (74,164) (10,109)
Repayment of Salton Sea notes and bonds .............................. (28,918) (53,469)
Repayment of note payable to related party ........................... (221,619) --
Repayment of construction and other loans ............................ -- (17,211)
Distribution to parent ............................................... (41,774) --
Contribution from parent ............................................. 269,179 --
Deferred charge relating to debt financing ........................... -- (1,561)
Decrease (increase) in restricted cash ............................... 14,255 29,022
---------- ---------
Net cash flows from financing activities ........................ (83,041) (53,328)
---------- ---------
Net increase (decrease) in cash and cash equivalents .................. (18,253) 67,392
Cash and cash equivalents at beginning of period ...................... 54,661 14,051
---------- ---------
Cash and cash equivalents at end of period ............................ $ 36,408 $ 81,443
========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-52
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
(DOLLARS AND SHARES IN THOUSANDS)
(UNAUDITED)
1. BUSINESS
Magma Power Company (the "Company" or "Magma"), a wholly-owned subsidiary
of CE Generation, LLC, defined below, is primarily engaged in the exploration
for and development of geothermal resources and conversion of such resources
into electrical power and steam for sale to electric utilities, and the
development of other environmentally responsible forms of power generation. The
Company currently operates eight geothermal power plants in the Imperial Valley
in California.
On February 8, 1999, MidAmerican Energy Holdings Company ("MidAmerican")
created a new subsidiary, CE Generation LLC ("CE Generation") and subsequently
transferred its interest in the Company and its power generation assets in the
Imperial Valley ("Contributed Subsidiaries") to CE Generation, with Visayas
Geothermal Power Company and Minerals, LLC being retained by MidAmerican
("Excluded Subsidiaries"). On March 3, 1999, MidAmerican closed the sale of 50%
of its ownership interests in CE Generation to an affiliate of El Paso Energy
Corporation.
The September 30, 1999 and 1998 consolidated financial statements included
herein have been prepared by the Company, without audit, pursuant to the rules
and regulations of the Securities and Exchange Commission. Certain information
and disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted pursuant to such rules and regulations. In the opinion of the Company,
all adjustments (consisting only of normal recurring accruals) have been made
to present fairly the financial position, the results of operations and the
changes in cash flows for the periods presented. Although the Company believes
that the disclosures are adequate to make the information presented not
misleading, it is suggested that these financial statements be read in
conjunction with the December 31, 1998 consolidated financial statements.
2. EXTRAORDINARY ITEM
On January 29, 1999, MidAmerican commenced a cash offer for all of its
outstanding 9 7/8% Limited Recourse Senior Secured Notes due 2003. The Company
received tenders from holders of an aggregate of approximately $195.8 million
principal which were paid on March 3, 1999, at a redemption price of 110.025%
plus accrued interest resulting in an extraordinary loss of approximately $17.5
million, net of tax.
3. STOCKHOLDER'S EQUITY
Stockholder's equity comprised the following at September 30, 1999:
<TABLE>
<S> <C>
Stockholder's equity, beginning of year ................................. $ 609,490
Distributions of equity interest in Excluded Subsidiaries to MidAmerican (340,152)
Other distribution to MidAmerican ....................................... (41,774)
Contribution from MidAmerican ........................................... 269,179
Net income .............................................................. 29,539
----------
Stockholder's equity, September 30, 1999 ................................ $ 526,282
==========
</TABLE>
F-53
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Falcon Seaboard Resources, Inc.
We have audited the accompanying consolidated balance sheets of Falcon
Seaboard Resources, Inc. (an indirect wholly owned subsidiary of MidAmerican
Energy Holdings Company, the successor of CalEnergy Company, Inc.) and
subsidiaries as of December 31, 1998 and 1997, and the related consolidated
statements of operations, changes in stockholder's equity and cash flows for
the years ended December 31, 1998 and 1997 and for the periods from August 7,
1996 through December 31, 1996 (successor) and January 1, 1996 through August
6, 1996 (predecessor). These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Falcon Seaboard Resources,
Inc. and subsidiaries at December 31, 1998 and 1997, and the results of their
operations and their cash flows for the years ended December 31, 1998 and 1997
and for the periods from August 7, 1996 through December 31, 1996 and January
1, 1996 through August 6, 1996 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
January 28, 1999 (March 3, 1999 as to Note 9)
F-54
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(AN INDIRECT WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
1998 1997
------------- ------------
<S> <C> <C>
ASSETS
Cash and cash equivalents .......................................... $ 11,844 $ 9,940
Restricted cash .................................................... 5,917 6,597
Accounts receivable ................................................ 7,100 7,866
Amounts due from affiliates, net ................................... -- 48,662
Inventory .......................................................... 3,640 3,571
Deferred income taxes .............................................. 2,188 1,324
Prepaids ........................................................... 292 290
--------- ---------
Total current assets .............................................. 30,981 78,250
Properties, plant, and contracts:
Land ............................................................... 358 358
Cogeneration facility .............................................. 163,389 163,338
Furniture, fixtures and equipment .................................. 1,602 1,441
--------- ---------
165,349 165,137
Accumulated depreciation and amortization .......................... (25,046) (14,660)
--------- ---------
Properties, plants and contracts, net .............................. 140,303 150,477
Restricted cash .................................................... 1,307 310
Excess of cost over fair value of net assets acquired, net ......... 88,429 94,252
Investments in partnerships ........................................ 125,036 131,207
Deferred charges and other assets .................................. 2,573 5,469
--------- ---------
Total assets .................................................... $ 388,629 $ 459,965
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
LIABILITIES:
Accounts payable ................................................... $ 366 $ 346
Accrued liabilities ................................................ 6,435 9,321
Current portion of long-term debt .................................. 14,268 12,805
Amounts due to affiliates, net ..................................... 28,696 --
--------- ---------
Total current liabilities ......................................... 49,765 22,472
Deferred income taxes .............................................. 79,183 92,565
Project financing debt ............................................. 76,261 90,529
Other long-term liabilities ........................................ 940 2,794
--------- ---------
Total liabilities ............................................... 206,149 208,360
Commitments and Contingencies (Notes 5 and 6)
STOCKHOLDER'S EQUITY:
Common stock, $.01 par value; 1,000,000 shares authorized,
1,192 shares issued and outstanding ............................... -- --
Additional paid in capital ......................................... 182,480 232,500
Retained earnings .................................................. -- 19,105
--------- ---------
Total stockholder's equity ......................................... 182,480 251,605
--------- ---------
Total liabilities and stockholder's equity ......................... $ 388,629 $ 459,965
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-55
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(AN INDIRECT WHOLLY-OWNED SUBISIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND
FOR THE PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996
AND JANUARY 1, 1996 THROUGH AUGUST 6, 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SUCCESSOR PREDECESSOR
----------------------------------------------- ------------------
AUGUST 7, 1996 - JANUARY 1, 1996 -
1998 1997 DECEMBER 31, 1996 AUGUST 6, 1996
----------- ----------- ------------------- ------------------
<S> <C> <C> <C> <C>
REVENUES:
Sales of electricity and steam ..... $ 80,375 $ 77,405 $ 27,346 $ 46,642
Sales of oil and gas ............... -- -- -- 1,485
Equity earnings of partnerships..... 10,732 14,542 4,263 15,305
Interest and other income .......... 3,694 4,325 2,705 5,323
-------- -------- -------- --------
Total revenues ................... 94,801 96,272 34,314 68,755
COSTS AND EXPENSES:
Plant operations ................... 37,765 39,388 16,240 43,322
Depreciation and amortization ...... 17,033 15,841 6,584 4,796
Loss from write-off of oil and
gas investments .................. -- -- -- 11,183
Interest expense ................... 11,854 12,995 5,908 7,471
-------- -------- -------- --------
Total costs and expenses ......... 66,652 68,224 28,732 66,772
-------- -------- -------- --------
Income before income tax
expense .......................... 28,149 28,048 5,582 1,983
Income tax expense ................. 12,273 11,698 2,827 684
-------- -------- -------- --------
Net income ......................... $ 15,876 $ 16,350 $ 2,755 $ 1,299
======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-56
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(AN INDIRECT WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY FOR THE YEARS ENDED
DECEMBER 31, 1998 AND 1997 AND FOR THE PERIODS FROM AUGUST 7, 1996
THROUGH DECEMBER 31, 1996 AND JANUARY 1, 1996 THROUGH AUGUST 6, 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
FOREIGN
COMMON STOCK ADDITIONAL CURRENCY
----------------- PAID-IN TRANSLATION RETAINED
SHARES AMOUNT CAPITAL ADJUSTMENT EARNINGS TOTAL
-------- -------- ------------ ------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
PREDECESSOR:
BALANCE, December 31, 1995 ................ 1,192 $ -- $ 205 $ (185) $ 3,198 $ 3,218
Net income prior to acquisition ......... -- -- -- -- 1,299 1,299
----- ---- --------- ------- --------- ---------
BALANCE, August 6, 1996 ................... 1,192 -- 205 (185) 4,497 4,517
SUCCESSOR:
Distribution of net assets to
parent (Note 3) ........................ -- -- -- 185 (23,611) (23,426)
Purchase accounting push-down
adjustment, net ........................ -- -- 232,295 -- 19,114 251,409
Net income after acquisition ............ -- -- -- -- 2,755 2,755
----- ---- --------- ------- --------- ---------
BALANCE, December 31, 1996 ................ 1,192 -- 232,500 -- 2,755 235,255
Net income .............................. -- -- -- -- 16,350 16,350
----- ---- --------- ------- --------- ---------
BALANCE, December 31, 1997 ................ 1,192 -- 232,500 -- 19,105 251,605
Distribution ............................ -- -- (50,020) -- (34,981) (85,001)
Net income .............................. -- -- -- -- 15,876 15,876
----- ---- --------- ------- --------- ---------
BALANCE, December 31, 1998 ................ 1,192 $ -- $ 182,480 $ -- $ -- $ 182,480
===== ==== ========= ======= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-57
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(AN INDIRECT WHOLLY-OWNED SUBSIDIARY OF MIDAMERICAN ENERGY HOLDINGS COMPANY)
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED
DECEMBER 31, 1998 AND 1997 AND FOR THE PERIODS FROM AUGUST 7, 1996
THROUGH DECEMBER 31, 1996 AND JANUARY 1, 1996 THROUGH AUGUST 6, 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SUCCESSOR PREDECESSOR
------------------------------------------- ------------------
AUGUST 7, 1996 - JANUARY 1, 1996 -
1998 1997 DECEMBER 31, 1996 AUGUST 6, 1996
----------- ----------- ------------------- ------------------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ................................. $ 15,876 $ 16,350 $ 2,755 $ 1,299
ADJUSTMENTS TO RECONCILE CASH FLOWS
FROM OPERATING ACTIVITIES:
Depreciation and amortization .............. 13,211 13,149 5,011 4,755
Amortization of excess of cost over fair
value of net assets acquired ............. 3,822 2,692 1,573 41
Loss from write-off of oil and gas
investments .............................. -- -- -- 11,183
Deferred income taxes ...................... (14,246) (3,157) (487) (432)
Equity earnings of partnerships ............ (10,732) (14,542) (4,263) (15,305)
CHANGES IN OTHER ITEMS:
Deferred revenue ........................... -- -- 187 (187)
Accounts receivable ........................ 766 (1,339) (120) (473)
Deferred charges and other assets .......... (1,000) (1,601) 1,369 (2,327)
Accounts payable and accrued
liabilities .............................. (4,720) 3,135 (3,474) 870
--------- --------- -------- ---------
Net cash flows from operating
activities ............................ 2,977 14,687 2,551 (576)
--------- --------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ....................... (212) (409) (34) (220)
Cash distributed in spin off ............... -- -- -- (287)
Distributions from equity investments ...... 16,903 23,960 8,295 13,535
Decrease (increase) in restricted cash ..... (997) 1,076 198 (584)
--------- --------- -------- ---------
Net cash flows from investing
activities ............................ 15,694 24,627 8,459 12,444
--------- --------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of debt ......................... (12,805) (11,237) (4,187) (6,857)
Distribution to parent ..................... (82,000) -- -- --
Amounts due to/from affiliates ............. 77,358 (26,708) (21,146) (835)
Decrease (increase) in restricted cash ..... 680 (97) (2) 27
--------- --------- ----------- ---------
Net cash flows from financing
activities ............................ (16,767) (38,042) (25,335) (7,665)
--------- --------- ---------- ---------
Net increase (decrease) in cash and
cash equivalents ......................... 1,904 1,272 (14,325) 4,203
Cash and cash equivalents,
Beginning of period ...................... 9,940 8,668 22,993 18,790
--------- --------- ---------- ---------
Cash and cash equivalents,
End of period ............................ $ 11,844 $ 9,940 $ 8,668 $ 22,993
========= ========= ========== =========
SUPPLEMENTAL DISCLOSURE:
Interest paid ............................ $ 11,707 $ 12,995 $ 6,781 $ 7,180
========= ========= ========== =========
Income taxes paid ........................ $ 6,982 $ 1,237 $ 1,190 $ 3,235
========= ========= ========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-58
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996
(DOLLARS IN THOUSANDS)
1. BUSINESS
Falcon Seaboard Resources, Inc. ("FSRI" or the "Company") is a holding
company that invests primarily through its wholly owned subsidiaries Falcon
Seaboard Pipeline Corporation, Falcon Seaboard Power Corporation ("FSPC"), and
Falcon Seaboard Oil Company ("FSOC"). As of December 31, 1998, FSRI was an
indirect wholly owned subsidiary of MidAmerican Energy Holdings Company, the
successor of CalEnergy Company, Inc. ("MidAmerican"). See Note 9.
Falcon Seaboard Pipeline Corporation, through its operating subsidiaries,
acquires, develops, owns and operates natural gas properties for the benefit of
affiliated power projects.
FSPC, through its subsidiaries, was formed to develop, design, own and
operate cogeneration and independent power plants. FSPC is the parent company
to Falcon Power Operating Company ("FPOC"), Northern Consolidated Power, Inc.
("Norcon") and Saranac Energy Company, Inc. ("SECI"). FPOC provides operations
and maintenance services to the independent power plants owned by the Company
and affiliated partnerships. Norcon holds general and limited partnership
interests in a 79.9 megawatt cogeneration facility which began operations in
December 1992. SECI holds general and limited partnership interests in a 240
megawatt cogeneration facility, which began operations in June 1994, and a
natural gas pipeline that supplies fuel to the facility, which began operations
in January 1994.
FSOC acquires, develops, owns and operates natural gas properties and is
the parent company of Power Resources, Inc. ("PRI"), which owns and operates a
200 megawatt cogeneration facility.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION--The accompanying consolidated financial statements
include the operations and accounts of FSRI and its wholly owned subsidiaries.
All significant intercompany transactions and balances have been eliminated in
consolidation. Subsequent to August 6, 1996, the financial statements reflect
the acquisition of FSRI by MidAmerican. The period from January 1, 1996 through
August 6, 1996 represents the predecessor's historical cost basis.
Management believes the financial statements reflect all material costs
associated with the Company's operations.
REVENUE RECOGNITION--Revenue from cogeneration activities is recognized
when electrical and steam output is delivered in accordance with contract
terms.
RESTRICTED CASH--Restricted cash represents amounts for major maintenance
expenditures and a debt protection reserve account. The debt service funds are
legally restricted as to their use and require maintenance of specific minimum
balances equal to the next debt service payment.
PROPERTY, PLANTS, CONTRACTS AND DEPRECIATION--Property, plants and
contracts are stated at the cost pushed down from MidAmerican which reflects
the estimated fair value at the date of acquisition. Depreciation expense is
computed using the straight line or accelerated methods of accounting over the
following useful lives:
<TABLE>
<S> <C>
Furniture, fixtures and equipment ......... 5 - 30 years
Cogeneration facility ..................... 6 - 30 years
</TABLE>
IMPAIRMENT OF LONG-LIVED ASSETS--The Company reviews long-lived assets and
certain identifiable intangibles for impairment whenever events or changes in
circumstances indicate that the carrying
F-59
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
amount of an asset may not be recoverable. An impairment loss would be
recognized whenever evidence exists that the carrying value is not recoverable.
During the period from January 1, 1996 through August 6, 1996, the Company
recognized an $11,183 loss from the write-off of the carrying amount of its oil
and gas investments. These properties had been accounted for under the full
cost method of accounting. The oil and gas properties were spun off by FSRI to
its former parent prior to the MidAmerican acquisition. See Note 3.
EXCESS OF COST OVER FAIR VALUE--Total acquisition costs in excess of the
fair values assigned to the net assets acquired are being amortized on a
straight line basis over 25 years. At December 31, 1998 and 1997, accumulated
amortization of the excess of cost over fair value was $10,216 and $4,393,
respectively.
INVESTMENTS--The Company's investments in Saranac and Norcon are accounted
for using the equity method of accounting since the Company has the ability to
exercise significant influence over the investees' operating and financial
policies through its managing general partnership interests. At December 31,
1998 and 1997, the carrying amount of the Company's investment in Saranac
differs from its underlying equity in net assets of Saranac by $108,788 (net of
accumulated amortization of $24,824) and $119,060 (net of accumulated
amortization of $14,552), respectively. This difference, which represents the
adjustment to record the fair value of the investment at the date of
acquisition, is being amortized on a straight-line basis over approximately 13
years, the remaining portion of the power sales agreement at the date of
acquisition.
MAINTENANCE AND REPAIR RESERVES--A maintenance and repair reserve is
recorded monthly based on the Company's long-term scheduled major maintenance
plans for the PRI cogeneration facility and is included in accrued liabilities.
Other maintenance and repairs are charged to expense as incurred.
INCOME TAXES--The Company is included in the consolidated income tax
returns of MidAmerican and affiliates. The provision for income taxes is
computed on a separate return basis, with the associated current income tax
asset or liability being recorded in the amounts due from affiliates. The
Company recognizes deferred tax assets and liabilities based on the difference
between the financial statement and tax bases of the assets and liabilities
using estimated tax rates in effect for the year in which the differences are
expected to reverse.
DEFERRED FINANCING COSTS--Costs associated with securing PRI's term loan
were capitalized and are being amortized using the effective interest method
over the period the term loan is outstanding.
CASH EQUIVALENTS--Cash equivalents represent short-term, highly liquid
investments with an original maturity of less than three months. Restricted
cash is not considered a cash equivalent.
USE OF ESTIMATES--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.
FINANCIAL INSTRUMENTS--The Company utilizes swap agreements to manage
market risks and reduce its exposure resulting from fluctuations in interest
rates. For interest rate swap agreements, the net cash amounts paid or received
on the agreements are accrued and recognized as an adjustment to interest
expense. The Company's practice is not to hold or issue financial instruments
for trading purposes. These instruments are either exchange traded or with
counterparties of high credit quality; therefore, the risk of nonperformance by
the counterparties is considered negligible.
F-60
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
Fair values of financial instruments have been estimated using available
market information and other valuation techniques. Unless otherwise noted, the
estimated fair value amounts do not differ significantly from recorded values.
NEW ACCOUNTING PRONOUNCEMENT--In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standard
("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities,
which established accounting and reporting standards for derivative instruments
and for hedging activities. It requires that an entity recognize all
derivatives as either assets or liabilities in the statement of financial
position and measure those instruments at fair value. This statement is
effective for all fiscal quarters of fiscal years beginning after June 15,
2000. The Company is in the process of evaluating the impact of this accounting
pronouncement.
START-UP COSTS--In 1998, the Company adopted Statement of Position No.
98-5, Reporting on the Costs of Start-Up Activities, which requires costs of
start-up activities and organization costs be expensed as incurred. Such
adoption had no significant effect on the Company.
3. ACQUISITION
On August 7, 1996, MidAmerican completed the acquisition of FSRI for
approximately $226,000. The transaction was accounted for as a purchase
business combination. All identifiable assets acquired and liabilities assumed
were assigned a portion of the cost of acquiring FSRI, equal to their fair
values at the date of acquisition.
In connection with the acquisition of FSRI, several entities and
properties were spun off from FSRI including Falcon Seaboard Energy Corporation
(except for its subsidiary, Falcon Seaboard Gas Company), Falcon Seaboard
Pipeline Corporation, Falcon Seaboard Energy Services, Inc., and the oil and
natural gas properties held by FSOC.
4. INVESTMENT IN PARTNERSHIPS
The Company indirectly holds noncontrolling general and limited
partnership interests in two partnerships, Saranac Power Partners, L.P.
("Saranac"), and Norcon Power Partners, L.P. ("Norcon"), which were formed to
build, own and operate natural gas fired combined cycle cogeneration
facilities. The lenders to these partnerships have recourse only against these
facilities and the income and revenues therefrom. The Company has a current
approximate 45% economic interest in Saranac and a current 20% economic
interest in Norcon. The Company will have an approximate 80% economic interest
in each of these partnerships after outside limited partners' returns, as
defined in the Partnership agreements, are achieved. The Saranac outside
limited partners, TPC Saranac and General Electric Capital Company, must
achieve after tax returns of approximately 8.35% and 7.252%, respectively.
NorCon's partner, TPC NorCon, must achieve a pre-tax return of approximately
16.5%.
The following is a summary of aggregated financial information for all
investments owned by the Company which are accounted for under the equity
method at December 31, 1998 and 1997:
<TABLE>
<CAPTION>
1998 1997
----------- -----------
<S> <C> <C>
Assets ............... $414,546 $434,028
Liabilities .......... 306,234 326,230
Net income ........... 44,338 47,478
</TABLE>
F-61
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
Saranac's total revenue for the years ended December 31, 1998, 1997 and
1996 were $141,876, $146,954 and $140,396, respectively. NorCon's total
revenues for the years ended December 31, 1998, 1997 and 1998 were $52,268,
$50,908 and $44,893, respectively.
Saranac has project financing through a 14 year note payable agreement with
a lender with a principal amount outstanding of $189,282 at December 31, 1998.
The note agreement is collateralized by all of the assets of Saranac. Saranac is
restricted by the terms of the payable agreement from making distributions or
withdrawing any capital amounts without the consent of the lender. Under terms
of the note payable agreement, distributions may be made to the partners in
accordance with the terms of the Saranac partnership agreement. Distributions
are made monthly and quarterly to the extent of the partnership's excess cash
balances.
Each of the Saranac partners has an interest in cash distributions by
Saranac which changes when certain after-tax rates of return are achieved by GE
Capital and the TPC Saranac partners on their contributions to Saranac. The
cash distributions of Saranac are divided into three levels: (1) distributions
in fixed amounts payable during the first 15 years of operation of the Saranac
project, which are applied first to pay debt service4 and other amounts due
under the Saranac project financing documents and any refinancing loans, with
the remainder paid to GE Capital to enable it to achieve a certain base rate of
return; (2) distributions of the Saranac available cash remaining after payment
of the level 1 distributions during the first 15 years of operation of the
Saranac project; (3) distributions after the first 15 years of operation of the
Saranac project. During the first 15 years of operation of the Saranac project,
Saranac Energy will receive 63.51% of the level 2 distributions until TPC
Saranac partners achieve an 8.35% rate of return and, after such return is
achieved (which we expect to occur in 2000), Saranac Energy will receive 81.18%
of the level 2 distributions. After the first 15 years of operation of the
Saranac project, Saranac Energy will receive 68% of the level 3 distributions
until GE Capital achieves a certain supplemental rate of return and,
thereafter, Saranac Energy will receive 75% of the level 3 distributions.
NorCon has projected financing under a note payable comprised of senior
and junior debt with a total principal amount outstanding at December 31, 1998
of $104,524. The note payable is collateralized by NorCon's assets. Under the
terms of the note payable agreement, NorCon is allowed to make distributions
after certain funds have been established; principally, a minimum of $500 must
be maintained in the Project's revenue account. Distributions are made monthly
and quarterly to the extent of the partnership's excess cash balances.
There were no undistributed earnings in equity investments at December 31,
1998.
5. PROJECT FINANCING DEBT
PRI has project financing debt with a consortium of banks with interest
and principal due quarterly over a 15 year period, beginning March 31, 1989.
The original principal carried a variable interest rate based on the London
Interbank Offer Rate ("LIBOR") with a .85% interest margin through the 5th
anniversary of the loan, a 1.00% interest margin from the 5th anniversary
through the 12th anniversary of the loan and a 1.25% interest margin from the
12th anniversary through the end of the loan. The loan is collateralized by an
assignment of all revenues received by PRI, a lien on substantially all of its
real and personal property and a pledge of its capital stock.
Effective June 5, 1989, PRI entered into an interest rate swap agreement
with the lender as a means of hedging floating interest rate exposure related
to its 15-year term loan. The swap agreement
F-62
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
was for initial notional amounts of $55,000 and $110,000, declining in
correspondence with the principal balances, and effectively fixed the interest
rates at 9.385% and 9.625%, respectively, excluding the interest rate margin.
The swap agreements are settled in cash based on the difference between a fixed
and floating (index based) price for the underlying debt. The notional value of
these financial instruments were $90,529 and $103,334 at December 31, 1998 and
1997, respectively. PRI would be exposed to credit loss in the event of
nonperformance by the lender under the interest rate swap agreement. However,
PRI does not anticipate nonperformance by the lender. The estimated cost to
terminate the interest rate swap agreement, based on termination values obtained
from the lender, was $9,904 and $10,550 at December 31, 1998 and 1997,
respectively.
The interest rate can be increased by payments under a Compensation
Agreement included in PRI's term loan. The Compensation Agreement, which
entitles two of the term lenders to receive quarterly payments equivalent to a
percentage of PRI's discretionary cash flow ("DCF") as separately defined in
the agreement, became effective initially for a 13-year period ending December
31, 2003. Under certain conditions relating to the amount of PRI's cash flow
and the restrictions on cash distributions, PRI has the option to replace the
payment obligation in a quarter with a payment to be calculated in a future
quarter and added to the end of the initial term of the agreement. The
Compensation Agreement entitles the lenders to payments totaling 10% of DCF for
the first ten years, 7.5% of DCF for the next three years and 10% of DCF for
each quarter added to the initial term of the agreement. PRI recorded
additional interest expense of $1,177 and $1,091 for the years ended December
31, 1998 and 1997, respectively, related to amounts owed under the Compensation
Agreement.
Scheduled maturities of project financing debt for the year ending
December 31 are as follows:
<TABLE>
<S> <C>
1999 .................. $14,268
2000 .................. 16,087
2001 .................. 18,119
2002 .................. 20,312
2003 .................. 21,743
-------
Total ................. $90,529
=======
</TABLE>
Under PRI's term loan agreement, certain covenants and debt service
coverage ratios must be met before cash distributions can be made to FSOC. PRI
was in compliance with these requirements at December 31,1998.
6. COMMITMENTS AND CONTINGENCIES
PRI has contracted to purchase natural gas for its cogeneration facility
under two separate agreements, an 8-year agreement for up to 40,000 MMBTU per
day which expires in December 2003 and a 15-year agreement for 3,600 MMBTU per
day which expires in June 2003. These agreements include annual price
adjustments, and the 15-year agreement includes a provision which allows the
seller to terminate the agreement with a two-year written notice. As of
December 31, 1998, the seller had not elected to terminate this agreement;
therefore, the minimum volumes under the 15-year and 8-year agreements for the
years ending December 31, are included in the future minimum payments under
these contracts as follows:
F-63
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
<TABLE>
<S> <C>
1999 .................. $ 22,611
2000 .................. 23,308
2001 .................. 23,608
2002 .................. 24,285
2003 .................. 24,854
--------
Total ................. $118,666
========
</TABLE>
The Company's affiliates cogeneration facilities are qualifying facilities
under the Public Utility Regulatory Policies Act of 1978 ("PURPA") and their
contracts for the sale of electricity are subject to regulations under PURPA.
In order to promote open competition in the industry, legislation has been
proposed in the U.S. Congress that calls for either a repeal of PURPA on a
prospective basis or the significant restructuring of the regulations governing
the electric industry, including sections of PURPA. Current federal legislative
proposals would not abrogate, amend, or modify existing contracts with electric
utilities. The ultimate outcome of any proposed legislation is unknown at this
time.
Saranac has a contract to purchase natural gas from a third party, for its
cogeneration facility for a period of 15 years for an amount up to 51,000
MMBTU's per day. The price for such deliveries is a stated rate, escalated
annually at a rate of 4%.
All of PRI's sales of electricity and steam are made to two customers
under long-term contracts which expire in 2003.
The PRI Project sells electricity to Texas Utilities Electric Company
(TUEC) pursuant to a 15 year negotiated power purchase agreement (the Power
Resources PPA), which provides for capacity and energy payments. Capacity
payments and energy payments, which in 1998 are $3,138 per month and 3.0
centers per kWh, respectively, escalate at 3.5% annually for the remaining term
of the Power Resources PPA. The Power Resources PPA expires in September 2003.
PRI sells steam to Fina Oil and Chemical under a 15 year agreement. PRI has
agreed to supply Fina with up to 150,000 pounds per hour of steam. As long as
PRI meets its supply obligations, Fina is required to purchase at least the
minimum amount of steam per year required to allow the PRI Project to maintain
its qualifying facility status under PURPA.
The Saranac Project sells electricity to New York State Electric & Gas
pursuant to a 15 year negotiated power purchase agreement (the Saranac PPA),
which provides for capacity and energy payments. Capacity payments, which in
1998 total 2.3 cents per kWh, are received for electricity produced during
"peak hours" as defined in the Saranac PPA and escalate at approximately 4.1%
annually for the remaining term of the contract. Energy payments, which
averaged 6.7 cents per kWh in 1998, escalate at approximately 4.4% annually for
the remaining term of the Saranac PPA. The Saranac PPA expires in June of 2009.
Saranac sells steam to Georgia-Pacific and Tenneco Packaging under long-term
steam sales agreements. The Company believes that these agreements will enable
Saranac to sell the minimum annual quantity of steam necessary for the Saranac
Project to maintain its qualifying facility status under PURPA for the term of
the Saranac PPA.
The NorCon Project sells electricity to Niagara Mohawk Power Corporation
(Niagara) pursuant to a 25 year negotiated power purchase agreement (the NorCon
PPA) which provides for energy payments calculated pursuant to an adjusting
formula based on Niagara's ongoing Tariff Avoided Cost and the contractual
Long-Run Avoided Cost. The NorCon PPA term extends through December 2017.
NorCon sells steam to Welch Foods, Inc. under an agreement that expires in
December 2012. Welch is required to purchase at least the minimum amount of
steam per year required to maintain the
F-64
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
NorCon Project's qualifying facility status under the Public Utility Regulatory
Policies Act of 1978. If NorCon fails to deliver steam, it will be liable for
liquidated damages, limited to $10,000 per occurrence. NorCon's aggregate
liability over the term of the steam purchase agreement is subject to an
escalating cap, which starts at $2.0 million and increases to $3.2 million by
the 20th year of the contract.
Accounts receivable, which are primarily from TUEC, are primarily
uncollateralized receivables from long-term power purchase contracts described
above. If TUEC was unable to perform, FSRI could incur an accounting loss equal
to $6,981 and $7,866 at December 31, 1998 and 1997, respectively.
7. INCOME TAXES
The components of income tax expense (benefit) for the year ended December
31, 1998 and 1997 and for the periods from August 7, 1996 though December 31,
1996 and January 1, 1996 through August 6, 1996 are as follows:
<TABLE>
<CAPTION>
SUCCESSOR PREDECESSOR
------------------------------------------ ------------
AUGUST 7, JANUARY 1,
1996-- 1996--
DECEMBER 31, AUGUST 6,
1998 1997 1996 1996
------------ ---------- -------------- ------------
<S> <C> <C> <C> <C>
Current ............................ $ 26,519 $ 14,855 $3,314 $1,116
Deferred ........................... (14,246) (3,157) (487) (432)
--------- -------- ------ ------
Total income tax expense ......... $ 12,273 $ 11,698 $2,827 $ 684
========= ======== ====== ======
</TABLE>
At December 31, 1998 and 1997, temporary differences result primarily from
accruals, alternative minimum tax credit carryforwards and depreciation. At
December 31, 1998, and 1997, the Company had deferred tax assets and
liabilities as shown below:
<TABLE>
<CAPTION>
1998 1997
------------- -------------
<S> <C> <C>
Deferred tax asset .................. $ (2,188) $ (1,324)
Deferred tax liability .............. 79,183 92,565
--------- ---------
Net deferred tax liability .......... $ 76,995 $ 91,241
========= =========
</TABLE>
8. RELATED PARTY TRANSACTIONS
Amounts due from affiliates at December 31, 1998 and 1997, primarily
represent balances with MidAmerican for cash management purposes. The due to
affiliates balance at December 31, 1998 includes $3,001 in unpaid
distributions to MEHC.
FPOC has contracted with Norcon and Saranac to provide operations and
maintenance ("O&M") services to their cogeneration facilities and pipeline. The
Norcon and Saranac O&M agreements for the cogeneration facilities expire
January 1, 2009, and July 1, 2010, respectively. The O&M agreement for the
pipeline expires June 20, 2010. The O&M agreements provide for monthly and
quarterly fees which are subject to escalation provisions and reimbursement of
certain costs as specified in the applicable agreements. The amounts due under
these agreements are included in the amounts due from affiliates in the
accompanying balance sheets.
F-65
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998 AND 1997 AND FOR THE
PERIODS FROM AUGUST 7, 1996 THROUGH DECEMBER 31, 1996 AND
JANUARY 1, 1996 THROUGH AUGUST 6, 1996 (CONTINUED)
(DOLLARS IN THOUSANDS)
The due from and due to parent balances in the Company's financial
statements are the result of MidAmerican's central cash management policy.
MidAmerican's policy is to have FSRI distribute all available cash to the parent
company and have the parent company remit payment for most expenses incurred by
FSRI. As a result, the due from and due to parent balances are simply a function
of the timing of cash receipts and cash distributions between MidAmerican and
FSRI.
9. SUBSEQUENT EVENTS
On February 8, 1999 MidAmerican created a new subsidiary CE Generation LLC
("CE Generation") and subsequently transferred its interest in FSRI and other
power generation assets to CE Generation.
On March 3, 1999, MidAmerican sold 50% of its interest in CE Generation to
an affiliate of El Paso Energy Corporation.
10. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. Although management uses its best
judgment in estimating the fair value of these financial instruments, there are
inherent limitations in any estimation technique. Therefore, the fair value
estimates presented herein are not necessarily indicative of the amounts which
FSRI could realize in a current transaction.
The project loan is estimated to have a fair value equal to the carrying
value.
The carrying amounts in the table below are included in the consolidated
balance sheets under the indicated captions:
<TABLE>
<CAPTION>
1998 1997
------------------------ ---------------------------
ESTIMATED ESTIMATED
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
---------- ----------- ------------ ------------
<S> <C> <C> <C> <C>
Financial Liabilities:
Project loan ............... 90,529 90,529 $ 103,334 $ 103,334
Interest rate swap ......... -- (9,904) -- (10,550)
------ ------ --------- ---------
</TABLE>
F-66
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 1999 AND DECEMBER 31, 1998
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
--------------- -------------
ASSETS
<S> <C> <C>
Cash and cash equivalents .......................................... $ 18,390 $ 11,844
Restricted cash .................................................... 6,365 5,917
Accounts receivable ................................................ 6,617 7,100
Amounts due from affiliates ........................................ 19,973 --
Inventory .......................................................... 3,706 3,640
Deferred income taxes .............................................. 2,188 2,188
Prepaids ........................................................... 220 292
--------- ---------
Total current assets .............................................. 57,459 30,981
Properties, plants and contracts:
Land ............................................................... 358 358
Cogeneration facility .............................................. 164,337 163,389
Furniture, fixtures and equipment .................................. 1,602 1,602
--------- ---------
166,297 165,349
Accumulated depreciation and amortization .......................... (33,016) (25,046)
--------- ---------
Properties, plants and contracts, net .............................. 133,281 140,303
Restricted cash .................................................... 1,381 1,307
Excess of cost over fair value of net assets acquired, net ......... 85,546 88,429
Investments in partnerships ........................................ 119,913 125,036
Deferred charges and other assets .................................. 1,854 2,573
--------- ---------
Total assets .................................................... $ 399,434 $ 388,629
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
LIABILITIES:
Accounts payable ................................................... $ 38 $ 366
Accrued liabilities ................................................ 6,056 6,435
Current portion of long term debt .................................. 14,268 14,268
--------- ---------
Total current liabilities ....................................... 20,362 21,069
Deferred income taxes .............................................. 111,298 79,183
Project financing debt ............................................. 65,560 76,261
Amounts due to affiliates, net ..................................... -- 28,696
Other long term liabilities ........................................ 590 940
--------- ---------
Total liabilities ............................................... 197,810 206,149
STOCKHOLDER'S EQUITY:
Common stock ....................................................... -- --
Additional paid-in capital ......................................... 182,480 182,480
Retained earnings .................................................. 19,144 --
--------- ---------
Total stockholder's equity ......................................... 201,624 182,480
--------- ---------
Total liabilities and stockholder's equity ......................... $ 399,434 $ 388,629
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-67
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
REVENUES:
Sales of electricity and steam .......... $ 63,893 $ 58,594
Equity earnings of partnerships ......... 17,718 8,635
Interest and other income ............... 3,212 2,718
-------- --------
Total revenues ........................ 84,823 69,947
-------- --------
COSTS AND EXPENSES:
Plant operations ........................ 29,878 27,524
Depreciation and amortization ........... 11,363 11,880
Interest expense ........................ 7,574 8,859
-------- --------
Total costs and expenses .............. 48,815 48,263
-------- --------
Income before income tax expense ......... 36,008 21,684
Income tax expense ....................... 12,603 7,589
-------- --------
Net income ............................... $ 23,405 $ 14,095
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-68
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
(DOLLARS IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................. $ 23,405 $ 14,095
ADJUSTMENTS TO RECONCILE CASH FLOW FROM OPERATING ACTIVITIES:
Depreciation and amortization ............................... 8,480 9,012
Amortization of excess of cost over fair value of net assets
acquired .................................................. 2,883 2,868
Deferred income taxes ....................................... 32,115 7,564
Equity earnings of partnerships ............................. (17,718) (8,635)
CHANGES IN OTHER ITEMS:
Accounts receivable ....................................... 483 699
Deferred charges and other assets ......................... 215 (628)
Accounts payable and accrued liabilities .................. (1,057) (3,972)
--------- ---------
Net cash flows from operating activities ............... 48,806 21,003
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................ (948) (204)
Distributions from equity investments ....................... 22,841 13,485
Decrease (increase) in restricted cash ...................... (74) (2,055)
Net cash flows from investing activities ............... 21,819 11,226
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of debt .......................................... (10,701) (9,603)
Amounts due from affiliates ................................. (45,668) (26,360)
Distribution to parent ...................................... (7,262)
Decrease (increase) in restricted cash ...................... (448) 1,031
--------- ---------
Net cash flows from financing activities ............... (64,079) (34,932)
--------- ---------
Net increase (decrease) in cash and cash equivalents ......... 6,546 (2,703)
--------- ---------
Cash and cash equivalents, beginning of period ............... 11,844 9,940
--------- ---------
Cash and cash equivalents, end of period ..................... $ 18,390 $ 7,237
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-69
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF CE GENERATION, LLC)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND 1998
A. GENERAL
The September 30, 1999 and 1998 consolidated financial statements included
herein have been prepared by the Company, without audit, pursuant to the rules
and regulations of the Securities and Exchange Commission. Certain information
and disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted pursuant to such rules and regulations. In the opinion of the Company,
all adjustments (consisting only of normal recurring accruals) have been made
to present fairly the financial position, the results of operations and the
changes in cash flows for the periods presented. Although the Company believes
that the disclosures are adequate to make the information presented not
misleading, it is suggested that these financial statements be read in
conjunction with the December 31, 1998 consolidated financial statements.
B. SUBSEQUENT EVENT
On December 2, 1999, the Company's indirect subsidiary, NorCon Power
Partners, L.P., reached agreement with Niagara Mohawk Power Corporation to
dismiss the outstanding litigation between NorCon and Niagara. At the same
time, NorCon transferred the NorCon project to General Electric Capital
Corporation and entered into agreements with third parties to terminate some of
NorCon's contracts and to assign the rest of its contracts to a subsidiary of
General Electric Capital. General Electric Capital also agreed to be
responsible for other third party claims made against NorCon related to the
NorCon project. Thus, after December 2, 1999, neither NorCon nor any of the
Company's other subsidiaries owns an interest in the NorCon project and the
NorCon project contracts are no longer in effect or have been assigned to third
parties.
As the Company's share of NorCon's earnings comprise less than 5% of the
equity earnings in subsidiaries for the nine months ended September 30, 1999
and the Company's share of NorCon's net assets is less than 1% of the equity
investments at September 30, 1999, the transfer of the NorCon project to
General Electric Capital is not expected to have any significant impact on the
Company's results of operations, financial condition or liquidity.
C. PENDING ACCOUNTING POLICY CHANGES
In 2000, the Company will change its method of accounting for major
maintenance costs from the accrual method to the deferral method pending any
change in current authoritative guidance. As of September 30, 1999, the
cumulative effect of this change would result in a one-time increase in net
income of approximately $9.0 million. The Company does not expect the continuing
impact of this change to have a material impact on its results of operations.
F-70
<PAGE>
UNAUDITED PRO FORMA CONDENSED FINANCIAL DATA
The following unaudited pro forma condensed financial data are based on
the historical consolidated financial statements of Magma Power Company and
subsidiaries ("Magma"), adjusted to give effect on a pro forma basis to the
split-off of Magma's interest in Visayas Geothermal Power Company ("VGPC") and
Minerals, LLC (collectively, the "Split-Off") on February 8, 1999. These
statements should be read in conjunction with the historical financial
statements and notes thereto which are included in this Registration Statement.
A pro forma balance sheet is not presented as the split-off of Magma's
interest in Minerals, LLC and VGPC is reflected in the September 30, 1999
balance sheet.
Magma's actual consolidated financial statements reflect the effects of
the split-off at February 8, 1999. The unaudited pro forma condensed financial
statements neither purport to represent what the results of operations actually
would have been had the split-off and related transactions in fact occurred on
the assumed dates, nor to project the results of operations for any future
period.
F-71
<PAGE>
UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998
<TABLE>
<CAPTION>
(1) PRO FORMA
MAGMA SPLIT-OFF AS ADJUSTED
------------ -------------- ------------
<S> <C> <C> <C>
REVENUES:
Sales of electricity and steam ........... $ 370,470 $ (76,692) $ 293,778
Royalty income ........................... 2,284 -- 2,284
Interest and other income ................ 28,072 (4,185) 23,887
--------- ---------- ---------
Total revenues ......................... 400,826 (80,877) 319,949
--------- ---------- ---------
COST AND EXPENSES:
Plant operations ......................... 70,624 (7,110) 63,514
General and administration ............... 1,820 -- 1,820
Depreciation and amortization ............ 105,876 (27,659) 78,217
Interest expense ......................... 76,850 (19,337) 57,513
Less interest capitalized ................ (20,934) 20,587 (347)
--------- ---------- ---------
Total expenses ......................... 234,236 (33,519) 200,717
--------- ---------- ---------
INCOME BEFORE PROVISION FOR INCOME
TAXES .................................... 166,590 (47,358) 119,232
PROVISION FOR INCOME TAXES ................ 61,191 (30,319) 30,872
--------- ---------- ---------
INCOME FROM CONTINUING OPERATIONS ......... $ 105,399 $ (17,039) $ 88,360
========= ========== =========
</TABLE>
See notes to unaudited pro forma condensed financial data
F-72
<PAGE>
UNAUDITED PRO FORMA CONDENSED STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
<TABLE>
<CAPTION>
(2) PRO FORMA
MAGMA SPLIT-OFF AS ADJUSTED
------------ ------------- ------------
<S> <C> <C> <C>
REVENUES:
Sales of electricity and steam ........... $ 158,470 $ (6,659) $ 151,811
Royalty income ........................... 1,689 -- 1,689
Interest and other income ................ 11,968 (624) 11,344
--------- --------- ---------
Total revenues ......................... 172,127 (7,283) 164,844
--------- --------- ---------
COST AND EXPENSES:
Operating expense ........................ 38,704 (421) 38,283
General and administration ............... 7,594 -- 7,594
Depreciation and amortization ............ 33,278 (2,325) 30,953
Interest expense ......................... 35,450 (2,242) 33,208
Less interest capitalized ................ (4,440) 1,826 (2,614)
--------- --------- ---------
Total expenses ......................... 110,586 (3,162) 107,424
--------- --------- ---------
INCOME BEFORE TAXES ....................... 61,541 (4,121) 57,420
INCOME TAX EXPENSE ........................ 14,524 -- 14,524
--------- --------- ---------
INCOME FROM CONTINUING OPERATIONS ......... $ 47,017 $ (4,121) $ 42,896
========= ========= =========
</TABLE>
See notes to unaudited pro forma condensed financial data
F-73
<PAGE>
NOTES TO UNAUDITED PRO FORMA CONDENSED FINANCIAL DATA
1. Represents the results of operations for the Excluded Subsidiaries for the
period January 1, 1998 through December 31, 1998.
2. Represents the results of operations for the Excluded Subsidiaries for the
period January 1, 1999 through February 8, 1999.
F-74
<PAGE>
APPENDIX A
POWER GENERATION PROJECTS
INDEPENDENT ENGINEER'S REPORT
CE GENERATION CONSOLIDATED PROFORMA ANALYSIS
PREPARED FOR
CE GENERATION, LLC
FEBRUARY 24, 1999
FLUOR DANIEL, INC.
IRVINE, CALIFORNIA
A-1
<PAGE>
SECTION 1.0
OVERVIEW
Fluor Daniel, Inc. (Fluor Daniel) has reviewed information related to the
CE Generation (CEG) Projects and has prepared a summary of resulting debt
coverage ratios for both a Base Case and selected sensitivity cases as
hereinafter defined. The CEG projects for which financial results are presented
consist of the following:
o The Imperial Valley Projects: Salton Sea Unit I, Unit II, Unit III,
Unit IV, Vulcan, Del Ranch, Elmore, and Leathers which are presently
in operation. Also included are two units under construction, Salton
Sea Unit V and CE Turbo, as well as additional Magma Royalties.
o The Gas-Fired Projects: Yuma, PRI, and Saranac.
o Falcon Seaboard Gas Company
o Falcon Power Operating Company
Fluor Daniel completed a review of the Consolidated Financial Model
created by CEG and used to compute consolidated debt coverage ratios. The
Consolidated Financial Model incorporates financial results of four detailed
project-specific financial models: Imperial, Yuma, PRI, and Saranac.
Fluor Daniel initially reviewed the Imperial financial model in October
1998 and has again reviewed this model as well as a model, for Magma Royalties.
R.W. Beck has independently generated financial results for the Gas-Fired
Projects and Falcon Power Operating Company. C.C. Pace provided the cash flow
forecasts for Falcon Seaboard Gas Company that have also been incorporated into
the Consolidated Financial Model.
SECTION 2.0
CONCLUSIONS
After a review of the Consolidated Financial Model and an examination of
the supporting financial models, Fluor Daniel concludes:
o The Consolidated Financial Model, prepared by CEG, accurately
represents the results of the four project-specific models that
contain the detailed project assumptions
o The Consolidated Financial Model, that is based on the Base Case
assumptions recommended by CE Generation and R.W. Beck, indicates that
revenues appear to be adequate to provide sufficient cash flow for
debt service, with Base Case debt service coverage ratios calculated
from 1999 through 2018 of 2.59 minimum and 3.08 average.
o The financial projections remain stable across a defined range of
sensitivities and avoided cost assumptions, specified further below.
SECTION 3.0
CONSOLIDATED FINANCIAL PROJECTIONS AND DEBT COVERAGE RATIOS
3.1 BASE CASE RESULTS
Fluor Daniel has reviewed the Consolidated Financial Model and has
analyzed the ability of CEG to pay anticipated debt service on the securities
over the next 20 years. The results are summarized in the table of debt
coverage ratios presented below. In addition, Fluor Daniel has performed a
series of selected sensitivity analyses that are also listed on the table and
described in more detail in the next section.
A-2
<PAGE>
SUMMARY OF DEBT COVERAGE RATIOS
<TABLE>
<CAPTION>
SCENARIO MINIMUM COVERAGE AVERAGE COVERAGE
- -------- ---------------- ----------------
<S> <C> <C>
Base Case ...................... 2.59 3.08
Higher O&M ..................... 2.43 2.82
Increased Heat Rate ............ 2.48 3.02
Reduced Availability ........... 2.13 2.73
Low Power Price 1 .............. 2.56 2.94
Low Power Price 2 .............. 2.46 2.78
SCE Low Avoided Cost ........... 2.64 3.14
SCE Mid Avoided Cost ........... 2.69 3.52
SCE High Avoided Cost .......... 2.89 4.98
</TABLE>
The Consolidated Financial Model used to compute debt coverages contains a
twenty year projection of cash flow items beginning in year 1999. These items
include revenues, expenses, initial and long term capital expenditures,
royalties, and financing cash flows. The consolidated model brings forward the
relevant cash flow items from the detailed project models and consolidates the
results for measuring aggregate debt service coverage.
Specifically, as directed by CEG, the debt coverage ratios are calculated
by bringing forward revenues and expenses from the Imperial Valley, PRI, and
Yuma projects and then determining operating income by subtraction. From this
result, all capital expenditures from Imperial Valley, PRI and Yuma and net
construction cash flows from the respective projects are subtracted. Subtracted
next are all project-level debt service payments for Imperial Valley and PRI.
An adjustment is made for additions and releases of funds from PRI. Next, cash
flows from Saranac, Falcon Power Operating Company and Falcon Seaboard Gas
Company are added to operating income. Finally, LOC and trustee fees are
substracted resulting in cash available for debt service. The debt coverage
ratio is the ratio of cash available for debt service to total CE Generation
debt service.
The Base Case Consolidated Financial Model, shown as Exhibit 1, indicates
that cash flows from the CEG Projects are reasonable and should be sufficient
to cover the projected annual operating expenses, post-completion capital
expenditures, and debt service for the Securities. Base Case average debt
coverage is 3.08 and minimum debt coverage is 2.59.
3.2 BASE CASE ASSUMPTIONS
Among the many assumptions used for the analysis, CEG provided the
assumptions regarding the pricing, term, and amortization of principal for the
new Securities. The Securities will be long term bonds priced at an assumed
annual interest rate of 7.42 percent. The final maturity is 20 years from
issuance with an average life of approximately 11.9 years.
Henwood Energy Services prepared the forecasts of spot electricity prices
used for the Imperial Valley and Yuma Projects. CC Pace projected natural gas
prices for Saranac and PRI. Based upon representations of CEG and/or R.W. Beck,
regarding specific elements of geothermal and gas projects, Operations and
Maintenance (O&M) escalation was assumed to be 2.5% per year for the geothermal
projects and 2.7% per year for the Gas-Fired projects.
SECTION 4.0
SENSITIVITY ANALYSIS
Fluor Daniel, in conjunction with R.W. Beck, created and modeled certain
sensitivity cases under CEG's direction to analyze the ability of the project
to maintain debt coverage levels under several different scenarios. The four
variables adjusted for this analysis are increased O&M expense, reduced fuel
efficiency, reduced plant availability, reduced fuel efficiency for the
Gas-Fired plants, increased fuel cost for the Gas-Fired projects, and power
price sensitivities for Imperial Valley and Yuma. The results of this analysis
are presented below.
A-3
<PAGE>
4.1 HIGHER O&M
To test the sensitivity of CEG debt coverage ratios to changes in project
operating costs, the level of O&M costs for all projects was raised by 10%.
This sensitivity resulted in average debt coverage of 2.82 and minimum debt
coverage of 2.43.
4.2 INCREASED HEAT RATE
As a further sensitivity, the fuel efficiency in the gas-fired power
plants was reduced through a 5% increase in the plant heat rate. The increased
heat rate reduced average debt coverage to 3.02 and minimum coverage to 2.48.
4.3 REDUCED AVAILABILITY
The impact of reduced availability on project debt coverage ratios was
tested by reducing the annual availability of all projects from their existing
Base Case level by 5%. This sensitivity resulted in average debt coverage of
2.73 and minimum debt coverage of 2.13.
4.4 POWER PRICE
Henwood Energy Services prepared the forecast of future spot-market
electric energy prices used in the financial projections for the Imperial
Valley and Yuma projects. As a downside case, Henwood also prepared two cases
based on assumptions of lower natural gas prices (10 or 15 percent). The lower
natural gas forecasts were used by Henwood to forecast the corresponding lower
electrical energy prices.
Use of the low power price 1 (10% lower gas price) forecast reduced the
average CEG debt coverage to 2.94 and minimum coverage to 2.56. The low power
price 2 case (15% lower gas price) resulted in an average coverage of 2.78 and
minimum coverage of 2.46.
Three more power price scenarios were run to test debt coverages using
projections of avoided costs made by Southern California Edison in 1995. The
first scenario, SCE Low, resulted in an average debt coverage ratio of 3.14 and
minimum coverage of 2.64. The SCE Mid price scenario produced an average
coverage of 3.52 and minimum of 2.69. Finally, the SCE High scenario resulted
in average debt coverage of 4.98 and minimum coverage of 2.89.
A-4
<PAGE>
4.5 BREAKEVEN ANALYSIS
The following table presents the Power Exchange electric price that
maintains project debt service at a level of 1.0 or higher.
<TABLE>
<CAPTION>
BREAKEVEN (CENTS/KWH)
---------------------
YEAR NOMINAL 1999 BASE
- ---- ------- ---------
<S> <C> <C>
1999 ............................................... 0.00 0.00
2000 ............................................... 0.00 0.00
2001 ............................................... 0.00 0.00
2002 ............................................... 0.22 0.20
2003 ............................................... 0.63 0.57
2004 ............................................... 1.01 0.89
2005 ............................................... 1.32 1.14
2006 ............................................... 1.16 0.97
2007 ............................................... 1.39 1.14
2008 ............................................... 0.95 0.76
2009 ............................................... 1.36 1.06
2010 ............................................... 2.32 1.77
2011 ............................................... 2.13 1.58
2012 ............................................... 1.77 1.29
2013 ............................................... 2.18 1.54
2014 ............................................... 1.82 1.25
2015 ............................................... 2.06 1.39
2016 ............................................... 2.05 1.35
2017 ............................................... 2.28 1.46
2018 ............................................... 2.09 1.31
</TABLE>
A-5
<PAGE>
ASSUMPTIONS, QUALIFICATIONS AND REVIEW DOCUMENTS
THIS REPORT WAS PREPARED BY FLUOR DANIEL, INC. EXPRESSLY FOR USE BY CE
GENERATION. IT IS FLUOR DANIEL'S UNDERSTANDING THAT THIS REPORT WILL BE INCLUDED
IN THE PUBLIC OFFERING MEMORANDUM AND SUBSEQUENT PROSPECTUS FOR THE OFFERING OF
THE BONDS, AS DESCRIBED HEREIN. NEITHER FLUOR DANIEL NOR ANY PERSON ACTING IN
ITS BEHALF, MAKES ANY WARRANTY, EXPRESS OR IMPLIED, OR ASSUMES ANY LIABILITY
WITH RESPECT TO THE USE OF ANY INFORMATION, TECHNOLOGY, ENGINEERING, OR METHODS
DISCLOSED IN THIS REPORT, EXCEPT FOR SUCH LIABILITY AS MAY ARISE UNDER THE
FEDERAL SECURITIES LAWS.
In the preparation of this Report and the opinions contained therein,
Fluor Daniel 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 for the purpose of this Report, they are dependent
upon future events and actual conditions may differ from those assumed. In
addition, we have used and relied exclusively upon the information specified
below. Neither CE Generation nor Fluor Daniel Inc. has made an analysis,
verified, or rendered an independent judgment of the validity of the
information provided by others. While it is believed that the information
contained herein will be reliable under the conditions and subject to the
limitations set forth herein, neither CE Generation nor Fluor Daniel, Inc.
guarantee the accuracy thereof. Further, 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. Except for the
sensitivity analyses presented herein, no other sensitivities were performed.
This Report summarizes our work up to date of the Report. Thus, changed
conditions occurring or becoming known after such date could affect the
material presented to the extent of such changes.
The principal assumptions and considerations utilized by Fluor Daniel in
developing the results and conclusions presented in this report include the
following:
o The projected interest rates on the Securities, reinvestment rates,
cost of arranging the financing and the amortization schedule of the
Securities used in the debt service coverage analysis have been
provided to Fluor Daniel.
o CE Generation provided 1998 financial statements for the CE Generation
and other cost accounting information as well as future projections of
cost, expenses, prices, and other key assumptions.
o Brine quantities and depletion rates were provided by GeothermEx.
o The electricity pricing forecast was provided by Henwood Energy
Services.
o Fluor Daniel has not undertaken an independent review with all
regulatory agencies which could under any circumstances have
jurisdictions over or interests pertaining to the project
REVIEW DOCUMENTS
DOCUMENT
DATE DOCUMENT
---- --------
9/21/98 Proforma Cost Report
7/18/95 Salton Sea Funding Corporation Confidential Offering Circular
6/17/96 Salton Sea Funding Corporation Confidential Offering Circular
3/31/93 Technology Transfer Agreement -- Units I, II, & III
7/28/98 Second Amended and Restated Waste Disposal Agreement --
Units I, II, III, & IV
11/24/93 Ground Lease -- Units I & II
9/25/90 Plant Connection Agreement -- Unit II
A-6
<PAGE>
DOCUMENT
DATE DOCUMENT
---- --------
7/20/88 Plant Connection Agreement -- Unit III
3/31/93 Ground Lease -- Units III & IV
7/14/95 Plant Connection Agreement -- Unit IV
6/9/88 Plant Connection Agreement -- Del Ranch, L.P.
3/14/88 Ground Lease -- Del Ranch, L.P.
3/14/88 Technology Transfer Agreement -- Del Ranch, L.P.
6/9/88 Plant Connection Agreement -- Elmore, L.P.
3/14/88 Ground Lease -- Elmore, L.P.
3/14/88 Technology Transfer Agreement -- Elmore, L.P.
9/25/89 Plant Connection Agreement -- Leathers, L.P.
10/26/88 Ground Lease -- Leathers, L.P.
8/15/88 Technology Transfer Agreement -- Leathers, L.P.
12/6/88 Plant Connection Agreement -- Vulcan Power Company
4/14/98 IID Construction Agreement -- Salton Sea Unit V
4/1/98 IID Plant Connection Agreement -- Salton Sea Unit V
4/14/98 IID Transmission Services Agreement -- Salton Sea Unit V
7/30/98 Lump Sum Cost Proposal -- Salton Sea Unit V Project Schedule
8/5/98 Imperial Valley Operating Statistics
8/98 GeothermEx Report -- Assessment of the Resource Supply
8/5/98 BHP Royalty Agreement and Amendment
8/5/98 California Energy Commission, State of California Energy Resources
Conservation and Development Commission Clearance/Acknowledgement
that the Desert Valley/Salton Sea Unit V Project is not subject to
the Commission's jurisdiction.
9/2/98 Salton Sea Unit V Engineering, Procurement, and Construction Contract
9/11/98 Region II Upgrade Engineering, Procurement, and Construction Contract
8/12/98 Amendments to Power Purchase Agreement
3/31/98 Securities and Exchange Commission Form 10-Q
12/31/97 Securities and Exchange Commission Form 10-K
1/26/99 Consolidated and Project-Specific financial models
2/10/99 Mammoth Royalties Agreements
2/12/99 Responses to Fluor Daniel Data Requests
2/8/99 Excerpts from CalEnergy Operating Company 10 Year Plan
A-7
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Base Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 222,320 $ 168,258 $ 163,615 $ 175,747 $ 180,487 $ 185,522
PRI 83,498 86,128 88,997 91,887 71,866 --
Yuma 20,817 21,140 19,782 22,079 22,579 22,248
------------------------------------------------------------------------
Total Revenues 326,635 275,526 272,394 289,713 274,932 207,770
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 55,448 49,737 50,462 52,366 51,852 51,319
PRI 51,081 51,687 53,094 54,503 42,015 --
Yuma 13,731 16,472 13,797 14,230 16,725 14,432
------------------------------------------------------------------------
Total Expenses 120,260 117,896 117,353 121,099 110,592 65,751
OPERATING INCOME FROM CONSOLIDATED PROJECTS 206,376 157,630 155,040 168,614 164,340 142,019
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,409 1,002 715 516 351 --
Yuma 179 9 6 23 40 40
------------------------------------------------------------------------
Total Capital Expenditures 23,113 22,170 18,026 7,873 18,170 15,638
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 23,810 30,031 34,951 34,791 36,563 38,304
Falcon Power Operating Company 3,271 3,361 3,452 3,547 3,317 2,399
Falcon Seaboard Gas Company (3) 8,959 9,226 9,530 9,847 3,435 --
------------------------------------------------------------------------
Total Other Revenues 36,040 42,618 47,933 48,185 43,315 40,703
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 114,618 102,576 107,174 129,490 124,788 113,210
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 4.61 2.59 2.61 2.71 2.85 2.89
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 190,156 $ 183,391 $ 181,318 $ 187,934
PRI -- -- -- --
Yuma 23,459 23,408 23,531 24,590
---------------------------------------------
Total Revenues 213,615 206,799 204,849 212,524
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,997 52,726 53,260 54,305
PRI -- -- -- --
Yuma 14,880 15,118 19,613 16,310
---------------------------------------------
Total Expenses 67,877 67,844 72,873 70,615
OPERATING INCOME FROM CONSOLIDATED PROJECTS 145,738 138,955 131,975 141,909
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 40 40 40 40
---------------------------------------------
Total Capital Expenditures 26,132 14,602 16,255 7,649
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
---------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
---------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
---------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 40,549 41,525 40,605 49,062
Falcon Power Operating Company 2,464 2,531 2,599 2,669
Falcon Seaboard Gas Company (3) -- -- -- --
---------------------------------------------
Total Other Revenues 43,013 44,056 43,204 51,731
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 111,532 121,719 115,108 141,145
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
---------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.91 2.94 2.96 2.98
</TABLE>
Minimum DCR (1999 - 2018) 2.59
Average DCR (1999 - 2018) 3.08
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-8
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Base Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- -------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $185,550 $189,055 $ 188,223 $188,701 $194,037 $197,086
PRI -- -- -- -- -- --
Yuma 24,238 22,959 22,978 22,927 23,735 23,818
---------------------------------------------------------------
Total Revenues 209,788 212,014 211,201 211,628 217,772 220,904
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,804 55,109 55,556 55,087 58,568 58,332
PRI -- -- -- -- -- --
Yuma 16,817 15,971 19,020 16,993 17,531 17,817
---------------------------------------------------------------
Total Expenses 69,621 71,080 74,576 72,080 76,099 76,149
OPERATING INCOME FROM CONSOLIDATED PROJECTS 140,167 140,934 136,625 139,548 141,672 144,754
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 40 40 40 40 40 40
---------------------------------------------------------------
Total Capital Expenditures 17,706 10,496 14,610 8,984 18,238 7,569
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
---------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI
---------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
---------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 43,219 -- -- -- -- --
Falcon Power Operating Company 1,371 -- -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
---------------------------------------------------------------
Total Other Revenues 44,590 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 126,289 91,538 91,918 105,070 101,111 113,300
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
---------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 3.02 3.06 3.08 3.11 3.14 3.16
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
------- ------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 200,915 $ 200,536 $197,715 $197,521
PRI -- -- -- --
Yuma 24,365 24,476 24,940 25,336
------------------------------------------
Total Revenues 225,280 225,012 222,655 222,857
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 59,839 59,145 60,019 60,035
PRI -- -- -- --
Yuma 22,643 19,254 19,864 20,464
------------------------------------------
Total Expenses 82,482 78,399 79,883 80,499
OPERATING INCOME FROM CONSOLIDATED PROJECTS 142,798 146,613 142,772 142,358
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 40 40 40 40
------------------------------------------
Total Capital Expenditures 6,467 8,868 10,076 8,355
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company -- -- -- --
Falcon Seaboard Gas Company (3)
------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 112,190 113,598 110,580 123,047
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 3.19 3.22 3.25 3.26
</TABLE>
Minimum DCR (1999 - 2018) 2.59
Average DCR (1999 - 2018) 3.08
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-9
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Higher O&M Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 222,222 $ 168,172 $ 163,528 $ 175,656 $ 180,396 $ 185,449
PRI 83,498 86,128 88,997 91,887 71,866 --
Yuma 20,817 21,140 19,782 22,079 22,579 22,248
---------------------------------------------------------------------------
Total Revenues 326,537 275,440 272,307 289,622 274,841 207,697
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 58,490 52,567 53,311 55,324 54,835 54,330
PRI 52,198 52,763 54,205 55,639 42,890 --
Yuma 14,195 17,179 14,201 14,644 17,353 14,863
---------------------------------------------------------------------------
Total Expenses 124,883 122,509 121,717 125,607 115,078 69,193
OPERATING INCOME FROM CONSOLIDATED PROJECTS 201,655 152,931 150,590 164,015 159,763 138,504
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,550 1,102 787 568 386 --
Yuma 197 10 7 25 44 44
---------------------------------------------------------------------------
Total Capital Expenditures 23,272 22,271 18,099 7,927 18,209 15,642
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
---------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
---------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
---------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 22,424 28,305 33,068 32,849 34,556 36,234
Falcon Power Operating Company 3,598 3,696 3,797 3,901 3,649 2,639
Falcon Seaboard Gas Company (3) 8,959 9,226 9,530 9,847 3,435 --
---------------------------------------------------------------------------
Total Other Revenues 34,981 41,227 46,395 46,597 41,640 38,873
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 108,679 96,385 101,112 123,249 118,497 107,861
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
---------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 4.37 2.43 2.46 2.58 2.71 2.75
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 190,051 $ 183,287 $ 181,191 $ 187,778
PRI -- -- -- --
Yuma 23,459 23,408 23,531 24,590
-----------------------------------------------
Total Revenues 213,510 206,695 204,722 212,368
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 56,422 56,651 57,760 59,455
PRI -- -- -- --
Yuma 15,320 15,546 20,443 16,778
-----------------------------------------------
Total Expenses 71,742 72,197 78,203 76,233
OPERATING INCOME FROM CONSOLIDATED PROJECTS 141,769 134,498 126,519 136,134
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 44 44 44 44
-----------------------------------------------
Total Capital Expenditures 26,136 14,606 16,259 7,653
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-----------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
-----------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-----------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 38,414 39,318 38,326 46,720
Falcon Power Operating Company 2,710 2,784 2,859 2,936
Falcon Seaboard Gas Company (3) -- -- -- --
-----------------------------------------------
Total Other Revenues 41,124 42,102 41,185 49,656
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 105,670 115,304 107,628 133,291
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
-----------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.76 2.78 2.77 2.82
</TABLE>
Minimum DCR (1999 - 2018) 2.43
Average DCR (1999 - 2018) 2.82
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-10
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Higher O&M Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- --------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $185,384 $ 188,860 $ 188,004 $ 188,454 $193,753 $ 196,767
PRI -- -- -- -- -- --
Yuma 24,238 22,959 22,978 22,927 23,735 23,818
-----------------------------------------------------------------
Total Revenues 209,622 211,819 210,982 211,381 217,488 220,585
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 58,492 61,745 63,108 63,647 68,557 69,560
PRI -- -- -- -- -- --
Yuma 17,294 16,462 19,775 17,505 18,054 18,323
-----------------------------------------------------------------
Total Expenses 75,786 78,207 82,883 81,152 86,611 87,883
OPERATING INCOME FROM CONSOLIDATED PROJECTS 133,836 133,612 128,099 130,229 130,877 132,702
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 44 44 44 44 44 44
-----------------------------------------------------------------
Total Capital Expenditures 17,710 10,500 14,614 8,988 18,242 7,573
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
-----------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI -- -- -- -- -- --
-----------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
-----------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 42,017 -- -- -- -- --
Falcon Power Operating Company 1,508 -- -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
-----------------------------------------------------------------
Total Other Revenues 43,525 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 118,889 84,213 83,388 95,747 90,312 101,243
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
-----------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 2.85 2.82 2.80 2.83 2.81 2.82
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $200,551 $200,129 $197,254 $197,003
PRI -- -- -- --
Yuma 24,365 24,476 24,940 25,336
-------------------------------------------
Total Revenues 224,916 224,605 222,194 222,339
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 72,643 73,494 76,344 78,479
PRI -- -- -- --
Yuma 23,649 19,811 20,433 21,047
-------------------------------------------
Total Expenses 96,292 93,305 96,777 99,526
OPERATING INCOME FROM CONSOLIDATED PROJECTS 128,625 131,300 125,416 122,813
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 44 44 44 44
-------------------------------------------
Total Capital Expenditures 6,471 8,872 10,080 8,359
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
-------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- --
-------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 98,012 98,281 93,220 103,498
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
-------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 2.79 2.78 2.74 2.74
</TABLE>
Minimum DCR (1999 - 2018) 2.43
Average DCR (1999 - 2018) 2.82
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-11
<PAGE>
EXHIBIT I
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Increased Heat Rate Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 222,320 $ 168,258 $ 163,615 $ 175,747 $ 180,487 $ 185,522
PRI 83,498 86,128 88,997 91,887 71,866 --
Yuma 20,817 21,140 19,782 22,079 22,579 22,248
--------------------------------------------------------------------------
Total Revenues 326,635 275,526 272,394 289,713 274,932 207,770
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 55,448 49,737 50,462 52,366 51,852 51,319
PRI 52,537 53,153 54,582 56,014 43,183 --
Yuma 14,175 16,931 14,272 14,723 17,236 14,927
--------------------------------------------------------------------------
Total Expenses 122,160 119,821 119,316 123,103 112,271 66,246
OPERATING INCOME FROM CONSOLIDATED PROJECTS 204,476 155,705 153,077 166,610 162,661 141,524
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,409 1,002 715 516 351 --
Yuma 179 9 6 23 40 40
--------------------------------------------------------------------------
Total Capital Expenditures 23,113 22,170 18,026 7,873 18,170 15,638
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
--------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
--------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
--------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 22,061 27,824 32,511 32,246 33,904 35,530
Falcon Power Operating Company 3,271 3,361 3,452 3,547 3,317 2,399
Falcon Seaboard Gas Company (3) 8,959 9,226 9,530 9,847 3,435 --
--------------------------------------------------------------------------
Total Other Revenues 34,291 40,411 45,493 45,640 40,656 37,929
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 110,969 98,444 102,771 124,941 120,450 109,941
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
--------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 4.46 2.48 2.51 2.61 2.75 2.81
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 190,156 $ 183,391 $ 181,318 $ 187,934
PRI -- -- -- --
Yuma 23,459 23,408 23,531 24,590
-----------------------------------------------
Total Revenues 213,615 206,799 204,849 212,524
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,997 52,726 53,260 54,305
PRI -- -- -- --
Yuma 15,393 15,649 20,166 16,879
-----------------------------------------------
Total Expenses 68,390 68,375 73,426 71,184
OPERATING INCOME FROM CONSOLIDATED PROJECTS 145,225 138,424 131,422 141,340
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 40 40 40 40
-----------------------------------------------
Total Capital Expenditures 26,132 14,602 16,255 7,649
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-----------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
-----------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-----------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 37,653 38,505 37,453 45,774
Falcon Power Operating Company 2,464 2,531 2,599 2,669
Falcon Seaboard Gas Company (3) -- -- -- --
-----------------------------------------------
Total Other Revenues 40,117 41,036 40,052 48,443
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 108,123 118,168 111,403 137,288
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
-----------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.83 2.85 2.87 2.90
</TABLE>
Minimum DCR (1999 - 2018) 2.48
Average DCR (1999 - 2018) 3.02
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-12
<PAGE>
Exhibit I
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Increased Heat Rate Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $185,550 $189,055 $188,223 $188,701 $194,037 $197,086
PRI -- -- -- -- -- --
Yuma 24,238 22,959 22,978 22,927 23,735 23,818
----------------------------------------------------------------
Total Revenues 209,788 212,014 211,201 211,628 217,772 220,904
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,804 55,109 55,556 55,087 58,568 58,332
PRI -- -- -- --
Yuma 17,407 16,509 19,578 17,571 18,131 18,438
----------------------------------------------------------------
Total Expenses 70,211 71,618 75,134 72,658 76,699 76,770
OPERATING INCOME FROM CONSOLIDATED PROJECTS 139,577 140,396 136,067 138,970 141,072 144,133
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 40 40 40 40 40 40
----------------------------------------------------------------
Total Capital Expenditures 17,706 10,496 14,610 8,984 18,238 7,569
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
----------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI -- -- -- -- -- --
----------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
----------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 41,516 -- -- -- -- --
Falcon Power Operating Company 1,371 -- -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
----------------------------------------------------------------
Total Other Revenues 42,887 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 123,996 91,000 91,360 104,492 100,511 112,679
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
----------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 2.97 3.04 3.06 3.09 3.12 3.14
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $200,915 $200,536 $197,715 $197,521
PRI -- -- -- --
Yuma 24,365 24,476 24,940 25,336
------------------------------------------
Total Revenues 225,280 225,012 222,655 222,857
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 59,839 59,145 60,019 60,035
PRI -- -- -- --
Yuma 23,256 19,919 20,554 21,177
------------------------------------------
Total Expenses 83,095 79,064 80,573 81,212
OPERATING INCOME FROM CONSOLIDATED PROJECTS 142,185 145,948 142,082 141,645
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 40 40 40 40
------------------------------------------
Total Capital Expenditures 6,467 8,868 10,076 8,355
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- --
------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 111,577 112,933 109,890 122,334
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 3.17 3.20 3.23 3.24
</TABLE>
Minimum DCR (1999 - 2018) 2.48
Average DCR (1999 - 2018) 3.02
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-13
<PAGE>
EXHIBIT I
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Reduced Availability Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 213,742 $ 162,354 $ 157,889 $ 169,453 $ 173,918 $ 178,717
PRI 80,887 83,442 86,223 89,026 69,649 --
Yuma 19,748 20,056 18,770 20,949 21,423 21,106
--------------------------------------------------------------------------
Total Revenues 314,377 265,852 262,882 279,428 264,990 199,823
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 55,031 49,460 50,173 52,045 51,520 50,974
PRI 48,627 49,172 50,511 51,851 39,969 --
Yuma 13,085 15,992 13,300 13,517 14,135 16,027
--------------------------------------------------------------------------
Total Expenses 116,743 114,624 113,984 117,413 105,624 67,001
OPERATING INCOME FROM CONSOLIDATED PROJECTS 197,634 151,227 148,898 162,015 159,366 132,822
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,409 1,002 715 516 351 --
Yuma 179 9 6 23 40 40
--------------------------------------------------------------------------
Total Capital Expenditures 23,113 22,170 18,026 7,873 18,170 15,638
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
--------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
--------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
--------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 16,981 18,964 25,479 24,923 26,265 27,573
Falcon Power Operating Company 3,271 3,361 3,452 3,547 3,317 2,399
Falcon Seaboard Gas Company (3) 8,448 8,697 8,983 9,282 2,998 --
--------------------------------------------------------------------------
Total Other Revenues 28,700 31,022 37,914 37,752 32,580 29,972
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 98,536 84,577 91,013 112,457 109,080 93,281
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
--------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 3.96 2.13 2.22 2.35 2.49 2.38
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 184,433 $ 176,997 $ 174,725 $ 181,025
PRI -- -- -- --
Yuma 22,254 22,208 22,323 23,329
-----------------------------------------------
Total Revenues 206,687 199,205 197,048 204,354
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,631 52,382 52,916 53,941
PRI -- -- -- --
Yuma 14,344 14,784 19,034 15,714
-----------------------------------------------
Total Expenses 66,975 67,166 71,950 69,655
OPERATING INCOME FROM CONSOLIDATED PROJECTS 139,712 132,039 125,099 134,699
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 40 40 40 40
-----------------------------------------------
Total Capital Expenditures 26,132 14,602 16,255 7,649
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-----------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
-----------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-----------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 29,361 29,864 28,438 36,373
Falcon Power Operating Company 2,464 2,531 2,599 2,669
Falcon Seaboard Gas Company (3) -- -- -- --
-----------------------------------------------
Total Other Revenues 31,825 32,395 31,037 39,042
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 94,318 103,142 96,064 121,246
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
-----------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.46 2.49 2.47 2.56
</TABLE>
Minimum DCR (1999 - 2018) 2.13
Average DCR (1999 - 2018) 2.73
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-14
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Reduced Availability Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $178,760 $182,128 $181,309 $181,781 $186,836 $189,782
PRI -- -- -- -- -- --
Yuma 22,997 21,767 21,786 21,738 22,505 22,584
-----------------------------------------------------------------
Total Revenues 201,757 203,895 203,095 203,519 209,341 212,366
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,442 54,720 55,173 54,711 58,190 57,962
PRI -- -- -- -- -- --
Yuma 16,200 15,401 18,177 16,382 16,898 17,433
-----------------------------------------------------------------
Total Expenses 68,642 70,121 73,350 71,093 75,088 75,395
OPERATING INCOME FROM CONSOLIDATED PROJECTS 133,115 133,774 129,745 132,426 134,253 136,971
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 40 40 40 40 40 40
-----------------------------------------------------------------
Total Capital Expenditures 17,706 10,496 14,610 8,984 18,238 7,569
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
-----------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI -- -- -- -- -- --
-----------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
-----------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 36,583 -- -- -- -- --
Falcon Power Operating Company 1,371 -- -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
-----------------------------------------------------------------
Total Other Revenues 37,954 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 112,601 84,379 85,037 97,948 93,692 105,516
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
-----------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 2.70 2.82 2.85 2.90 2.91 2.94
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $193,391 $192,903 $189,976 $189,676
PRI -- -- -- --
Yuma 23,101 23,209 23,650 24,025
------------------------------------------
Total Revenues 216,492 216,112 213,626 213,701
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 59,458 58,756 59,628 59,632
PRI -- -- -- --
Yuma 17,109 23,281 19,134 19,709
------------------------------------------
Total Expenses 76,567 82,037 78,762 79,341
OPERATING INCOME FROM CONSOLIDATED PROJECTS 139,925 134,076 134,863 134,360
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 40 40 40 40
------------------------------------------
Total Capital Expenditures 6,467 8,868 10,076 8,355
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- --
------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 109,316 101,061 102,671 115,049
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 3.11 2.86 3.01 3.05
</TABLE>
Minimum DCR (1999 - 2018) 2.13
Average DCR (1999 - 2018) 2.73
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-15
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Low Power Price 2 Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 222,320 $ 167,959 $ 162,755 $ 164,637 $ 169,543 $ 176,429
PRI 83,498 86,128 88,997 91,887 71,866 --
Yuma 20,817 21,130 19,108 20,009 20,669 20,486
--------------------------------------------------------------------------
Total Revenues 326,635 275,217 270,860 276,533 262,078 196,915
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 55,448 49,721 50,420 51,716 51,332 50,882
PRI 51,081 51,687 53,094 54,503 42,015 --
Yuma 13,731 16,220 13,276 13,420 15,609 13,080
--------------------------------------------------------------------------
Total Expenses 120,260 117,628 116,790 119,639 108,956 63,962
OPERATING INCOME FROM CONSOLIDATED PROJECTS 206,376 157,589 154,070 156,894 153,122 132,953
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,409 1,002 715 516 351 --
Yuma 179 9 6 23 40 40
--------------------------------------------------------------------------
Total Capital Expenditures 23,113 22,170 18,026 7,873 18,170 15,638
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
--------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
--------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
--------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 23,810 30,031 34,951 34,791 36,563 38,304
Falcon Power Operating Company 3,271 3,361 3,452 3,547 3,317 2,399
Falcon Seaboard Gas Company (3) 8,959 9,226 9,530 9,847 3,435 --
--------------------------------------------------------------------------
Total Other Revenues 36,040 42,618 47,933 48,185 43,315 40,703
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 114,618 102,536 106,204 117,770 113,570 104,143
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
--------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 4.61 2.58 2.59 2.46 2.60 2.66
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 179,294 $ 173,202 $ 172,030 $ 173,653
PRI -- -- -- --
Yuma 21,778 22,003 22,231 22,456
-----------------------------------------------
Total Revenues 201,072 195,205 194,261 196,109
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,439 52,227 52,803 53,541
PRI -- -- -- --
Yuma 13,479 13,664 18,097 14,751
-----------------------------------------------
Total Expenses 65,918 65,891 70,900 68,292
OPERATING INCOME FROM CONSOLIDATED PROJECTS 135,154 129,314 123,361 127,817
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 40 40 40 40
-----------------------------------------------
Total Capital Expenditures 26,132 14,602 16,255 7,649
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-----------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
-----------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-----------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 40,549 41,525 40,605 49,062
Falcon Power Operating Company 2,464 2,531 2,599 2,669
Falcon Seaboard Gas Company (3) -- -- -- --
-----------------------------------------------
Total Other Revenues 43,013 44,056 43,204 51,731
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 100,948 112,078 106,494 127,053
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
-----------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.64 2.71 2.74 2.69
</TABLE>
Minimum DCR (1999 - 2018) 2.46
Average DCR (1999 - 2018) 2.78
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-16
<PAGE>
EXHIBIT I
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
Low Power Price 2 Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $173,813 $176,093 $175,760 $177,681 $178,750 $181,259
PRI -- -- -- -- -- --
Yuma 22,684 21,298 21,436 21,576 21,717 21,859
----------------------------------------------------------------
Total Revenues 196,497 197,391 197,196 199,257 200,467 203,118
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,244 54,417 54,927 54,536 57,757 57,555
PRI -- -- -- -- -- --
Yuma 15,199 14,483 17,476 15,392 15,872 16,095
----------------------------------------------------------------
Total Expenses 67,443 68,900 72,403 69,928 73,629 73,650
OPERATING INCOME FROM CONSOLIDATED PROJECTS 129,054 128,491 124,793 129,329 126,837 129,468
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 40 40 40 40 40 40
----------------------------------------------------------------
Total Capital Expenditures 17,706 10,496 14,610 8,984 18,238 7,569
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
----------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI -- -- -- -- -- --
----------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
----------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 43,219 -- -- -- -- --
Falcon Power Operating Company 1,371 -- -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
----------------------------------------------------------------
Total Other Revenues 44,590 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 115,176 79,095 80,086 94,851 86,277 98,014
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
----------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 2.76 2.64 2.69 2.81 2.68 2.73
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $183,359 $183,751 $179,898 $178,317
PRI -- -- -- --
Yuma 22,132 22,436 22,728 23,017
------------------------------------------
Total Revenues 205,491 206,187 202,626 201,334
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 58,955 58,329 59,128 59,074
PRI -- -- -- --
Yuma 20,950 17,401 17,946 18,477
------------------------------------------
Total Expenses 79,905 75,730 77,074 77,551
OPERATING INCOME FROM CONSOLIDATED PROJECTS 125,585 130,457 125,553 123,783
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 40 40 40 40
------------------------------------------
Total Capital Expenditures 6,467 8,868 10,076 8,355
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company -- -- -- --
Falcon Seaboard Gas Company (3) -- -- -- --
------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 94,977 97,443 93,360 104,473
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 2.70 2.76 2.74 2.77
</TABLE>
Minimum DCR (1999 - 2018) 2.46
Average DCR (1999 - 2018) 2.78
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-17
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
SCE Low Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 222,318 $ 170,790 $ 171,231 $ 177,615 $ 180,513 $ 184,216
PRI 83,498 86,128 88,997 91,887 71,866 --
Yuma 20,006 20,794 21,546 22,025 22,427 21,888
--------------------------------------------------------------------------
Total Revenues 325,822 277,712 281,774 291,527 274,806 206,104
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 55,448 49,886 50,879 52,392 51,848 51,242
PRI 51,081 51,687 53,094 54,503 42,015 --
Yuma 13,731 16,472 13,797 14,230 16,725 14,432
--------------------------------------------------------------------------
Total Expenses 120,260 118,045 117,770 121,125 110,588 65,674
OPERATING INCOME FROM CONSOLIDATED PROJECTS 205,563 159,667 164,004 170,402 164,218 140,431
LESS: CAPITAL EXPENDITURES
Imperial Valley 21,525 21,159 17,305 7,334 17,779 15,598
PRI 1,409 1,002 715 516 351 --
Yuma 179 9 6 23 40 40
--------------------------------------------------------------------------
Total Capital Expenditures 23,113 22,170 18,026 7,873 18,170 15,638
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures (142,812) (23,546) -- -- -- --
Proceeds from Financing 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
--------------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 82,740 51,546 53,451 55,115 53,349 53,433
PRI 21,561 23,381 23,796 23,975 23,188 --
--------------------------------------------------------------------------
Total Project Debt Service 104,301 74,927 77,247 79,090 76,537 53,433
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) (85) (128) (67) 183 12,328 --
--------------------------------------------------------------------------
Total Releases (85) (128) (67) 183 12,328 --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 23,810 30,031 34,951 34,791 36,563 38,304
Falcon Power Operating Company 3,271 3,361 3,452 3,547 3,317 2,399
Falcon Seaboard Gas Company (3) 8,959 9,226 9,530 9,847 3,435 --
--------------------------------------------------------------------------
Total Other Revenues 36,040 42,618 47,933 48,185 43,315 40,703
LESS: LOC / TRUSTEE FEES 299 447 460 528 488 442
TOTAL CASH AVAILABLE FOR DEBT SERVICE 113,805 104,613 116,138 131,278 124,666 111,621
CE GENERATING DEBT SERVICE
Interest 24,869 29,278 28,426 27,194 25,763 24,554
Principal Repayment -- 10,400 12,600 20,600 18,000 14,600
--------------------------------------------------------------------------
Total Debt Service 24,869 39,678 41,026 47,794 43,763 39,154
CE GENERATING DEBT COVERAGE 4.58 2.64 2.83 2.75 2.85 2.85
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $ 183,879 $ 178,620 $ 179,076 $ 182,181
PRI -- -- -- --
Yuma 22,266 22,679 23,132 23,544
-----------------------------------------------
Total Revenues 206,145 201,299 202,208 205,725
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,640 52,512 53,169 53,979
PRI -- -- -- --
Yuma 14,880 15,118 19,613 16,310
-----------------------------------------------
Total Expenses 67,520 67,630 72,782 70,289
OPERATING INCOME FROM CONSOLIDATED PROJECTS 138,625 133,669 129,426 135,437
LESS: CAPITAL EXPENDITURES
Imperial Valley 26,092 14,562 16,215 7,609
PRI -- -- -- --
Yuma 40 40 40 40
-----------------------------------------------
Total Capital Expenditures 26,132 14,602 16,255 7,649
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
-----------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 50,654 46,226 43,378 44,323
PRI -- -- -- --
-----------------------------------------------
Total Project Debt Service 50,654 46,226 43,378 44,323
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
-----------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 40,549 41,525 40,605 49,062
Falcon Power Operating Company 2,464 2,531 2,599 2,669
Falcon Seaboard Gas Company (3) -- -- -- --
-----------------------------------------------
Total Other Revenues 43,013 44,056 43,204 51,731
LESS: LOC / TRUSTEE FEES 433 464 438 523
TOTAL CASH AVAILABLE FOR DEBT SERVICE 104,419 116,433 112,559 134,673
CE GENERATING DEBT SERVICE
Interest 23,464 22,204 20,824 19,111
Principal Repayment 14,800 19,200 18,000 28,200
-----------------------------------------------
Total Debt Service 38,264 41,404 38,824 47,311
CE GENERATING DEBT COVERAGE 2.73 2.81 2.90 2,85
</TABLE>
Minimum DCR (1999 - 2018) 2.64
Average DCR (1999 - 2018) 3.14
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A- 18
<PAGE>
EXHIBIT 1
CE GENERATION, LLC
Pro Forma Financial Projections ($'000s)
SCE Low Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $183,925 $188,105 $189,866 $194,486 $198,002 $203,235
PRI -- -- -- -- -- --
Yuma 23,996 22,695 23,098 23,565 24,000 24,470
------------------------------------------------------------------
Total Revenues 207,921 210,800 212,964 218,051 222,002 227,705
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 52,771 55,057 55,668 55,420 58,745 58,675
PRI -- -- -- -- -- --
Yuma 16,817 15,971 19,020 16,993 17,531 17,817
------------------------------------------------------------------
Total Expenses 69,588 71,028 74,688 72,413 76,276 76,492
OPERATING INCOME FROM CONSOLIDATED PROJECTS 138,333 139,773 138,276 145,639 145,726 151,213
LESS: CAPITAL EXPENDITURES
Imperial Valley 17,666 10,456 14,570 8,944 18,198 7,529
PRI -- -- -- -- -- --
Yuma 40 40 40 40 40 40
------------------------------------------------------------------
Total Capital Expenditures 17,706 10,496 14,610 8,984 18,238 7,569
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- -- -- --
Proceeds from Financing -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
------------------------------------------------------------------
Total Imperial Valley Construction -- -- -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 40,294 38,551 29,749 25,106 21,951 23,477
PRI -- -- -- -- -- --
------------------------------------------------------------------
Total Project Debt Service 40,294 38,551 29,749 25,106 21,951 23,477
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- -- -- --
------------------------------------------------------------------
Total Releases -- -- -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) 43,219 -- -- -- -- --
Falcon Power Operating Company 1,371
Falcon Seaboard Gas Company (3) -- -- -- -- -- --
------------------------------------------------------------------
Total Other Revenues 44,590 -- -- -- -- --
LESS: LOC / TRUSTEE FEES 468 349 348 388 372 409
TOTAL CASH AVAILABLE FOR DEBT SERVICE 124,455 90,377 93,569 111,160 105,165 119,758
CE GENERATING DEBT SERVICE
Interest 17,153 15,715 14,624 13,301 11,786 10,072
Principal Repayment 24,600 14,200 15,200 20,480 20,400 25,800
------------------------------------------------------------------
Total Debt Service 41,753 29,915 29,824 33,781 32,186 35,872
CE GENERATING DEBT COVERAGE 2.98 3.02 3.14 3.29 3.27 3.34
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
-------- -------- -------- --------
<S> <C> <C> <C> <C>
CASH FROM PROJECTS
REVENUES FROM CONSOLIDATED PROJECTS
Imperial Valley $207,181 $209,662 $207,850 $208,974
PRI -- -- -- --
Yuma 24,953 25,425 25,890 26,368
------------------------------------------
Total Revenues 232,134 235,087 233,740 235,342
LESS: EXPENSES FROM CONSOLIDATED PROJECTS
Imperial Valley 60,144 59,624 60,523 60,615
PRI -- -- -- --
Yuma 22,643 19,254 19,864 20,464
------------------------------------------
Total Expenses 82,787 78,878 80,387 81,079
OPERATING INCOME FROM CONSOLIDATED PROJECTS 149,347 156,209 153,353 154,263
LESS: CAPITAL EXPENDITURES
Imperial Valley 6,427 8,828 10,036 8,315
PRI -- -- -- --
Yuma 40 40 40 40
------------------------------------------
Total Capital Expenditures 6,467 8,868 10,076 8,355
LESS: IMPERIAL VALLEY CONSTRUCTION CASH FLOWS
Construction Expenditures -- -- -- --
Proceeds from Financing -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------
Total Imperial Valley Construction -- -- -- --
LESS: CONSOLIDATED PROJECT LEVEL DEBT SERVICE
Imperial Valley 23,740 23,743 21,725 10,528
PRI -- -- -- --
------------------------------------------
Total Project Debt Service 23,740 23,743 21,725 10,528
PLUS: RELEASE/(ADDITION) OF RESTRICTED FUNDS
PRI (1) -- -- -- --
------------------------------------------
Total Releases -- -- -- --
PLUS: OTHER REVENUE CASH FLOWS
Saranac (2) -- -- -- --
Falcon Power Operating Company
Falcon Seaboard Gas Company (3) -- -- -- --
------------------------------------------
Total Other Revenues -- -- -- --
LESS: LOC / TRUSTEE FEES 402 403 391 427
TOTAL CASH AVAILABLE FOR DEBT SERVICE 118,739 123,194 121,161 134,952
CE GENERATING DEBT SERVICE
Interest 8,113 6,025 3,818 1,348
Principal Repayment 27,040 29,280 30,240 36,360
------------------------------------------
Total Debt Service 35,153 35,305 34,058 37,708
CE GENERATING DEBT COVERAGE 3.38 3.49 3.56 3.58
</TABLE>
Minimum DCR (1999 - 2018) 2.64
Average DCR (1999 - 2018) 3.14
(1) Changes in accounts held at PRI related to PRI debt (final year data
provided by CEG)
(2) Saranac cash flow based on partnership allocations after capital
expenditures and debt service
(3) Data provided by CC Pace
A-19
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
CE GENERATION LLC
NATURAL GAS PROJECTS
[R.W. Beck LOGO]
<PAGE>
[THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY]
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
CE GENERATION LLC NATURAL GAS PROJECTS
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PRI PROJECT.....................................................................................................B-4
Project Operator.............................................................................................B-4
The Project..................................................................................................B-4
The Project Site..........................................................................................B-4
Environmental Site Conditions.............................................................................B-4
Description of the Project................................................................................B-5
Review of Technology......................................................................................B-8
Reliability and Availability..............................................................................B-8
Status of Permits and Approvals...........................................................................B-8
Operating History............................................................................................B-9
Performance History.......................................................................................B-9
Operating Programs and Procedures........................................................................B-10
Regulatory Compliance....................................................................................B-10
Projected Operating Results.................................................................................B-12
Annual Operating Revenues................................................................................B-12
Annual Operating Expenses................................................................................B-13
Senior Debt Service......................................................................................B-14
Distributions to CE Generation...........................................................................B-14
SARANAC PROJECT................................................................................................B-14
Project Operator............................................................................................B-14
The Project.................................................................................................B-14
The Project Site.........................................................................................B-14
Environmental Site Conditions............................................................................B-15
Description of the Project...............................................................................B-15
Review of Technology.....................................................................................B-18
Reliability and Availability.............................................................................B-18
Status of Permits and Approvals..........................................................................B-18
Operating History...........................................................................................B-19
Performance History......................................................................................B-19
Operating Programs and Procedures........................................................................B-20
Regulatory Compliance....................................................................................B-20
Projected Operating Results.................................................................................B-22
Annual Operating Revenues................................................................................B-22
Annual Operating Expenses................................................................................B-23
Senior Debt Service......................................................................................B-24
Distributions to CE Generation...........................................................................B-24
YUMA PROJECT...................................................................................................B-24
Project Operator............................................................................................B-25
The Project.................................................................................................B-25
The Project Site.........................................................................................B-25
Environmental Site Conditions............................................................................B-25
Description of the Project...............................................................................B-25
Review of Technology.....................................................................................B-28
Reliability and Availability.............................................................................B-28
</TABLE>
B-i
<PAGE>
APPENDIX B
INDEPENDENT ENGINEER'S REPORT
CE GENERATION LLC NATURAL GAS PROJECTS
TABLE OF CONTENTS
(CONTINUED)
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Status of Permits and Approvals..........................................................................B-28
Operating History...........................................................................................B-29
Performance History......................................................................................B-29
Operating Programs and Procedures........................................................................B-30
Regulatory Compliance....................................................................................B-30
Projected Operating Results.................................................................................B-32
Annual Operating Revenues................................................................................B-32
Annual Operating Expenses................................................................................B-34
Distributions to CE Generation...........................................................................B-34
NORCON PROJECT.................................................................................................B-34
Project Operator............................................................................................B-35
The Project.................................................................................................B-35
The Project Site.........................................................................................B-35
Environmental Site Conditions............................................................................B-35
Description of the Project...............................................................................B-36
Review of Technology.....................................................................................B-38
Status of Permits and Approvals..........................................................................B-38
Regulatory Compliance.......................................................................................B-39
Projected Operating Results.................................................................................B-40
SUMMARY PROJECTED OPERATING RESULTS............................................................................B-41
Distributions from the Natural Gas Projects.................................................................B-41
Sensitivity Analyses........................................................................................B-41
Summary Comparison of Projected Operating Results...........................................................B-41
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
USED IN THE PROJECTION OF OPERATING RESULTS....................................................................B-42
CONCLUSIONS....................................................................................................B-43
EXHIBITS
EXHIBIT B-1 Base Case Projected Operating Results...........................................................B-46
EXHIBIT B-2 Sensitivity A - Increased Operating Expenses....................................................B-52
EXHIBIT B-3 Sensitivity B - Increased Heat Rate.............................................................B-57
EXHIBIT B-4 Sensitivity C - Reduced Availability............................................................B-62
EXHIBIT B-5 Sensitivity D - Yuma Low Gas 1..................................................................B-67
EXHIBIT B-6 Sensitivity E - Yuma Low Gas 2..................................................................B-70
EXHIBIT B-7 Sensitivity F - Yuma SCE Low SRAC...............................................................B-73
EXHIBIT B-8 Sensitivity G - Yuma SCE Median SRAC............................................................B-76
EXHIBIT B-9 Sensitivity H - Yuma SCE High SRAC..............................................................B-79
EXHIBIT B-10 Sensitivity I - Yuma Breakeven Electricity Price.................................................B-82
</TABLE>
Copyright (C)1999 R. W. Beck, Inc.
All rights reserved.
B-ii
<PAGE>
[R.W. Beck LOGO]
February 24, 1999
CE Generation LLC
302 South 36th Street
Suite 400
Omaha, Nebraska 68131
Subject: INDEPENDENT ENGINEER'S REPORT ON THE
CE GENERATION LLC NATURAL GAS PROJECTS
Ladies and Gentlemen:
Presented herein is the report (the "Report") of our review
and analyses of the Saranac Power Partners, L.P. Project located in Plattsburgh,
New York (the "Saranac Project"), the Yuma Cogeneration Associates Project
located in Yuma, Arizona (the "Yuma Project"), the Power Resources Inc. ("PRI")
Project located in Big Spring, Texas (the "PRI Project") and the NorCon Power
Partners, L.P. ("NorCon") Project located in Erie, Pennsylvania (the "NorCon
Project" and, collectively with the Saranac, Yuma and PRI Projects, the "Natural
Gas Projects"). The PRI, Saranac, and NorCon Projects are operated by Falcon
Power Operating Company ("FPOC"), a wholly-owned subsidiary of CE Generation.
The Natural Gas Projects are gas-fired combined-cycle electric generating
facilities currently in operation.
This Report has been prepared in connection with the issuance
by CE Generation LLC ("CE Generation") of approximately $400,000,000 principal
amount of 7.416% Senior Secured Bonds Due December 15, 2018 (the "Securities").
CE Generation is wholly-owned by CalEnergy Company, Inc. ("CalEnergy").
The PRI Project is a nominal 200 megawatt ("MW")
combined-cycle cogeneration facility located in Big Spring, Texas. The PRI
Project consists of two General Electric ("GE") Frame 7EA combustion turbine
generators ("CTGs") exhausting into individual heat recovery steam generators
("HRSGs") which provide steam to a single steam turbine generator ("STG") and to
Fina as process steam. Fina has a standby boiler which operates as the backup
steam source for process steam supply. The PRI Project is a Qualifying Facility
("QF") in accordance with Federal Energy Regulatory Commission ("FERC")
requirements and has been in operation since June 1988. The PRI Project sells
electric energy and capacity on a dispatchable basis to Texas Utilities Electric
Company ("TUEC") pursuant to the PRI Power Purchase Agreement dated July 30,
1986 (the "PRI PPA"), which has a term ending in September 2003. The PRI Project
sells steam to the adjacent Fina Oil and Chemical Company ("Fina") under a
Purchase and Steam Sales Agreement between PRI and Fina dated November 21, 1986
(the "PRI Steam Sales Agreement"), which has an initial term ending in September
2003. The PRI Project is operated by FPOC (the "PRI Operator") pursuant to the
PRI Operations and Maintenance Agreement between PRI and FPOC dated September 1,
1988 (the "PRI O&M Agreement"), which expires in January 2004.
The PRI Project has several fuel contracts in place. The PRI
Project has a fuel purchase agreement in place with Fina dated November 21, 1986
under which it is obligated to purchase an average of 3,600 million Btu per day
("MMBtu/day") of refinery gas (the "PRI Refinery Gas Contract"). The PRI
Refinery Gas Contract terminates on September 30, 2003, with the provision that
the PRI Refinery Gas Contract can be extended for a period of two years.
- -----------------------------------------------------------------------------
1125 Seventeenth Street, Suite 1900 Denver, CO 80202-2615
Phone (303) 299-5200 Fax (303) 297-2811
B-1
<PAGE>
Additional natural gas is delivered to the PRI Project
pursuant to a Gas Supply Agreement with Falcon Seaboard Gas Company ("FSGC")
dated December 30, 1988 (the "PRI Gas Supply Agreement"). FSGC is a wholly-owned
subsidiary of CE Generation. FSGC has a gas contract with Louis Dreyfus Natural
Gas Corporation ("Louis Dreyfus") dated December 1, 1988 (the "Louis Dreyfus Gas
Contract"), which expires October 1, 2003. The Louis Dreyfus Gas Contract
provides for FSGC to receive gas on a firm basis in accordance with a tiered
arrangement with Louis Dreyfus. FSGC has two Gas Transportation Contracts with
Westar, formerly Cabot Gas Supply, for interstate and intrastate transportation
dated December 1, 1988, as amended, (the "FSGC Gas Transportation Contracts").
The FSGC Gas Transportation Contracts expire on September 30, 2003.
The Saranac Project is a nominal 240 MW combined-cycle
cogeneration facility located in Plattsburgh, New York. The Saranac Project
consists of two GE Frame 7EA CTGs exhausting into individual HRSGs which provide
steam to a single STG and to the steam customers as process steam. A single
auxiliary boiler operates as the backup steam source for process steam supply.
It is a QF and has been in operation since June 1994. The Saranac Project sells
electric energy and capacity to New York State Electric and Gas Corporation
("NYSEG") pursuant to the Saranac Power Purchase Agreement, as amended, dated
April 27, 1990 (the "Saranac PPA"), which has a term ending in June 2009. The
Saranac Project sells steam to Georgia-Pacific under a 15-year steam sales
agreement dated December 21, 1992 (the "Georgia-Pacific Steam Sales Agreement")
and Tenneco Packaging ("Tenneco") under a steam sales agreement dated February
27, 1996 (the "Tenneco Steam Sales Agreement") which ends in June 2009. The
Saranac Project is operated by FPOC (the "Saranac Operator") pursuant to the
Saranac O&M Agreement dated September 30, 1994, as amended,(the "Saranac O&M
Agreement"). Natural gas is delivered to the Saranac Project pursuant to the
Saranac Gas Supply Agreement with Shell Canada dated May 20, 1992, as amended
(the "Saranac Gas Supply Agreement"), which expires in June 2009 and the
TransCanada Saranac Gas Transportation Agreement with TransCanada dated December
24, 1992 (the "Saranac Gas Transportation Agreement").
The Yuma Project is a nominal 50 MW combined-cycle
cogeneration facility located in Yuma, Arizona. It is a QF and has been in
operation since May 28, 1994. The Yuma Project consists of a single dual fuel
capable GE model 6B CTG, exhausting to a single Nooter-Eriksen three-pressure
HRSG which provides steam to a GE STG for additional electric generation, as
well as process steam and chiller steam to Queen Carpet, Inc. ("Queen Carpet").
One gas-fired auxiliary boiler is operated to provide process steam to Queen
Carpet when the HRSG is not operating. The Yuma Project sells electric energy
and capacity on a dispatchable basis to San Diego Gas and Electric ("SDG&E")
under the Yuma Standard Offer No. 2 Power Purchase Agreement dated March 7,
1990, as amended, (the "Yuma PPA"), which expires May 1, 2024. The Yuma Project
also sells process and chiller steam to Queen Carpet under two energy services
agreements. Process steam is sold under the Energy Services Agreement between
America-West Industries, Inc. and Yuma Cogeneration Associates dated April 2,
1993 (the "Yuma Process ESA"). Chiller steam is sold under the Energy Services
Agreement (Absorption Chiller Steam) between America-West Industries, Inc. and
Yuma Cogeneration Associates dated May 3, 1993 (the "Yuma Chiller ESA"). The
Yuma Process ESA and the Yuma Chiller ESA each have an initial term ending May
1, 2024. The Yuma Project is operated by Yuma Cogeneration Associates (the "Yuma
Operator"), a wholly-owned subsidiary of CE Generation.
Natural gas is supplied to the Yuma Project pursuant to the
Gas Supply and Transportation Services Master Agreement between Yuma
Cogeneration Associates and Southwest Gas Corporation ("SWG") dated November 21,
1992 (the "SWG Gas Supply and Transportation Agreement"). The initial term of
the SWG Gas Supply and Transportation Agreement expires December 31, 2008. Fuel
oil is purchased on a spot market basis.
The NorCon Project is a nominal 80 MW combined-cycle
cogeneration facility located near Erie, Pennsylvania. The NorCon Project
utilizes two GE LM5000 CTGs, each one exhausting to a Deltak HRSG which provides
steam for one Elliott STG. Each HRSG has a carbon monoxide ("CO") catalyst to
reduce CO emissions and each CTG uses steam injection to reduce nitrogen oxides
("NOx") emissions. Process steam is extracted from the STG and sent to the
facility owned by Welch Foods Inc. ("Welch") adjacent to the NorCon Project.
Additional steam is extracted and sent to an ammonia refrigeration plant ("ARP")
which cools ammonia for use as a
B-2
<PAGE>
refrigerant in the Welch facility. The NorCon Project has an auxiliary boiler
that can supply back-up process steam while Welch maintains its own centrifugal
refrigeration unit to back up the ARP. It is a QF and has been in operation
since December 1992. The NorCon Project sells electric energy and capacity to
Niagara Mohawk Power Corporation ("Niagara Mohawk") pursuant to the Power
Purchase Agreement dated April 28, 1989 (the "NorCon PPA"), which has an initial
term ending December 2017, and steam to Welch pursuant to the NorCon Thermal
Energy Purchase Agreement dated July 31, 1991 (the "NorCon Thermal Energy
Agreement"), which has an initial term ending in July 2011. The NorCon Project
is operated and maintained by FPOC (the "NorCon Operator"), a wholly-owned
subsidiary of CE Generation, pursuant to the Amended and Restated Operations and
Maintenance Agreement dated June 1, 1991 (the "NorCon O&M Agreement").
The NorCon Project's base fuel requirement of 16,480 MMBtu/day
is purchased from Louis Dreyfus pursuant to the Gas Sale and Purchase Agreement
dated January 29, 1992 (the "NorCon Gas Supply Agreement"), which has an initial
term ending in 2007. Small amounts of spot market gas are supplied either by
Louis Dreyfus or local suppliers. Natural gas is transported by National Fuel
Gas Supply Corporation pursuant to the Gas Transportation Letter Agreement dated
November 19, 1991 (the "NorCon Gas Transportation Agreement"), which has an
initial term ending in 2011.
During the preparation of this Report, we have reviewed the
various agreements related to the development of the Natural Gas Projects. These
agreements set forth the obligations of each of the parties with respect to the
operation of those Natural Gas Projects. As Independent Engineer, we have made
no determination as to the validity and enforceability of these agreements;
however, for the purposes of this Report, we have assumed these agreements will
be fully enforceable in accordance with their terms and that all parties will
comply with the provisions of their respective agreements.
During the course of our review, we have visited and made
general field observations of the Natural Gas Project sites as described later
herein (collectively, the "Natural Gas Project Sites"). The general field
observations were visual, above-ground examinations of selected areas, which we
deemed adequate to comment on the existing condition of those Natural Gas
Projects and the Natural Gas Project Sites and which were not in the detail
which would be necessary to reveal conditions with respect to safety, geological
or environmental conditions, the internal physical condition of any equipment,
or the conformance with agreements, codes, permits, rules, or regulations of any
party having jurisdiction with respect to the Natural Gas Projects or the
Natural Gas Project Sites.
In addition, with the exception of the NorCon Project, we have
reviewed: (1) the status of permits and approvals for the Natural Gas Projects
and compliance with those permits; (2) the historic and projected levels of
production of the Natural Gas Projects; (3) the historic and projected O&M
expenses of the Natural Gas Projects; (4) the historic and projected revenues of
the Natural Gas Projects; and (5) historical operating records of the Natural
Gas Projects. Based on our review, we have prepared a series of projections of
net operating revenue of the Natural Gas Projects and distributions to CE
Generation, which are attached as Exhibit B-1 to this Report (the "Projected
Operating Results"). The Projected Operating Results are based on the
assumptions described in this Report and the footnotes to Exhibits B-1. With
respect to the NorCon Project, we have reviewed only the status of permits and
compliance with those permits.
Certain analyses and projections relied upon for the purposes
of this Report were prepared by others. In developing the Projected Operating
Results, we have relied upon projections market prices for the Yuma Project
prepared by Henwood Energy Services, Inc. ("Henwood"), whose report is included
as Appendix E to the Confidential Offering Circular (the "Henwood Report"), and
a review of fuel supply and transportation contracts and projections of fuel
commodity and transportation costs for the Natural Gas Projects performed by
C.C. Pace Consulting, L.L.C. ("C.C. Pace"). In addition, Fluor Daniel, Inc.
("Fluor Daniel") has prepared a projection of sensitivity case electricity
pricing for the Yuma Project for one of the sensitivity cases. Based on their
experience in developing similar projections and performing similar reviews, we
believe it is reasonable to rely upon the review and projections prepared by
Henwood, C.C. Pace, and Fluor Daniel.
B-3
<PAGE>
PRI PROJECT
The PRI Project is a nominal 200 MW combined-cycle
cogeneration facility which commenced commercial operation in June 1988. The PRI
Project sells electric energy and capacity to TUEC pursuant to the PRI PPA while
selling process steam to Fina under the PRI Steam Sales Agreement.
The PRI Project consists of two dual fuel fired GE Frame 7EA
CTGs exhausting to separate HRSGs. The PRI Project uses natural gas as the
primary fuel. One CTG has been up-rated from a firing temperature of 2,020
degrees Fahrenheit ("(degree)F") to a firing temperature of 2,035(degree)F, and
the remaining Unit will be upgraded during its next major maintenance outage.
The two pressure level HRSGs produce high pressure ("HP") and low pressure
("LP") steam which is directed to a single STG for additional power generation.
Low pressure steam is extracted from the steam turbine for process steam to Fina
and for use in a common feedwater deaerator. HP steam is also injected into the
CTGs for NOx emissions control. Duct firing of the HRSGs is provided to generate
additional steam. Some jet "A" liquid fuel is stored on site for CTG backup
operation, testing, and diesel generator use. Jet "A" is produced in the Fina
steam host facility adjacent to the PRI Project.
PROJECT OPERATOR
The PRI Project is operated under the PRI O&M Agreement by the
PRI Operator. The PRI Operator commenced commercial operation and maintenance of
the PRI Project in June 1988.
THE PROJECT
THE PROJECT SITE
The PRI Project is located on 5.74 acres leased from Fina near
Big Spring, Texas adjacent to the existing Fina plant (the "PRI Project Site")
(see Figure B-1, PRI Project Site Plan). The PRI Project also owns approximately
20 acres adjacent to the leased site. The other wastewater disposal well is
located on a 4-acre tract about 4 miles away. The general area is industrial in
nature with the Sid Richardson, Ltd. carbon plant located nearby. The PRI
Project Site is easily accessible from Interstate 20 and the site elevation is
approximately 2,500 feet above sea level. The PRI Project Site is part of an
Industrial District Agreement with the City of Big Spring whereby the city
agrees not to annex the PRI Project Site and the PRI Project makes payments to
the city in lieu of annexation. The term of the Industrial District Agreement
expires on December 31, 2003.
ENVIRONMENTAL SITE CONDITIONS
We have not reviewed any reports of previous or recent
environmental investigations regarding the potential for site contamination
issues at the PRI Project Site. Because we did not conduct or review such
environmental reports, we can offer no opinion with respect to potential site
contamination at the PRI Project Site or potential future remediation costs
should contamination be found.
As of February 1999, the PRI Project was not listed on United
States Environmental Protection Agency's ("USEPA's") National Priorities List of
Superfund Sites or USEPA's Comprehensive Environmental Response Compensation
Liability Information System ("CERCLIS") List.
Visual inspections during our PRI Project Site visit of
January 28, 1999 indicated that the PRI Operator is following "good
housekeeping" procedures. We did not observe any unusual stained or soiled areas
and the PRI Operator maintains spill cleanup kits at various locations on the
PRI Project Site. The transformers, acid, and caustic tanks all have adequate
secondary containment.
We are not aware of any groundwater or soil contamination. The
PRI Operator stated that there are no soil or groundwater monitoring
requirements for the PRI Project Site, however, Fina has installed, monitors and
operates a number of groundwater monitoring wells in the area. There are two
groundwater monitoring wells near the PRI Project Site close to the north and
south leased boundaries.
B-4
<PAGE>
DESCRIPTION OF THE PROJECT
MECHANICAL EQUIPMENT AND SYSTEMS
The PRI Project utilizes two GE Frame 7EA CTGs firing natural
gas, steam injection to control NOx emissions and a blend of refinery off gas
produced by Fina. The generator is totally enclosed water air-cooled. The CTGs
are capable of firing jet "A" liquid fuel. The CTGs are supplied by GE with
auxiliary equipment required for an indoor installation.
Each CTG exhausts to a dedicated Deltak two-pressure level HRSG.
Each HRSG incorporates a Coen natural gas-fired duct burner to supplement steam
production during hot ambient temperatures or when one CTG is shut down. The PRI
Project delivers up to 150,000 pounds per hour ("pph") of steam at 650 pounds
per square inch, absolute ("psia") and 770(degree)F to Fina. No steam condensate
is returned by Fina to the PRI Project. TrEated water is returned for cooling
tower makeup.
The Hitachi-supplied STG is an induction/extraction condensing
unit capable of generating 75,000 kilowatts ("kW") at a throttle pressure of
1,200 pounds per square inch-gauge ("psig") and 940(Degree)F. The STG exhaust
steam is condensed in a water-cooled condenser located under the steam turbine.
Cooling water is provided by a three-cell induced draft cooling tower, and three
50 percent capacity circulating water pumps.
ENVIRONMENTAL CONTROL SYSTEMS
Steam injection is utilized in the CTGs to limit NOx emissions
to the permitted levels. No other emissions reduction equipment is utilized or
required.
The PRI Project wastewater, including boiler and cooling tower
blowdown, demineralizer wastes, and water recovered from the oily water
separation system, discharges to the west holding pond before being injected
into one of two underground formations with deepwell injection pumps.
Non-contaminated stormwater and reverse osmosis reject discharges to the east
holding pond for use as cooling tower makeup. Facility floor drains discharge to
oil/water separators and then to the west holding pond. PRI signed a water
transfer agreement with the Sid Richardson, Ltd. carbon plant dated April 28,
1997 (the "PRI Water Transfer Agreement") to take a specified amount of
wastewater from the PRI Project. This water is rarely supplied and when it is
supplied, the water flows into the east holding pond which is used for cooling
tower makeup. The PRI Water Transfer Agreement expires in April 2007.
ELECTRICAL AND CONTROL SYSTEMS
The electrical interface with the electric transmission grid
is at the substation located on the PRI Project Site. The generator outputs are
stepped up by 138 kV via step-up transformers located near the generators and
the 138 kV transformers are connected to a 345 kV switchyard located on the PRI
Project Site switchyard. The PRI Project output is connected to the TUEC system
on the high side of the 345 kV transformers.
The PRI Project has two diesel generators, one rated 1,350 kW
for "black start" capability, connected to the 4,160 volt switchgear and a
smaller maintenance generator connected to the 480 volt motor control center.
The 480 volt generator is used for emergency backup and startup. Jet "A" fuel
for the diesels is obtained from Fina.
The instrumentation and control system is a Foxboro Spectrum
Multistation distributed control system ("DCS") and is budgeted for replacement
with the Foxboro IA system beginning in April 1999 with completion scheduled in
October 1999. The existing Hitachi, HISEC 04-M dual processing unit, steam
turbine control system will be replaced and integrated into the new Foxboro IA
system. The CTGs are controlled by GE Mark IV speedtronic control systems. Water
Plant controls are Modicon programmable logic controllers ("PLCs"), which are
micoprocessor based with math functions.
B-5
<PAGE>
Figure B-1
PRI PROJECT
SITE PLAN
[GRAPHIC SHOWING SITE PLAN OF THE PRI PROJECT OMITTED]
B-6
<PAGE>
Every organization in the country is faced with a potential
problem on January 1, 2000, when the calendars on the millions of computers and
microprocessors in the country change from the year 99 to 00 and certain other
dates (for example, but not limited to, Leap Year and 9/9/99)(the "Y2K Issue").
The Y2K Issue occurs when computers or processors which use two-digit years
misinterpret the year 2000 to be "00," zero, 1900, or some other erroneous date.
The Y2K Issue has the potential to impact organizations like those of the
Natural Gas Projects in several different ways. First, it could impact the
instruments and controls within the major operating facilities such as the
Natural Gas Projects. Although the Y2K Issue has received considerable publicity
as it relates to computer information systems such as billing and financial
systems, the problems regarding process control or embedded systems in
operational equipment have received limited attention. This includes instrument
and control systems for power plants and SCADA systems for substation,
transmission and distribution facilities. The potential problems with these
operational facilities are significant as is the effort required to identify and
correct the problems.
Evaluation of the actual status of the Natural Gas Projects,
as well as other entities with whom the Natural Gas Projects have business or
operational relations, relative to the Y2K Issue is beyond the scope of this
Report. We have not conducted any independent evaluation or on-site testing of
the aforesaid entities in any way to independently ascertain the actual hardware
and software status. We caution that it is entirely possible that presently
unknown conditions could arise, which lead to significant operational and/or
administrative problems, and that these problems could have an adverse impact on
the Natural Gas Projects.
Additionally, the Y2K Issue has the potential to affect
organizations other than those of the Natural Gas Projects, the continued
performance of which is also critical to continued operation of the Natural Gas
Projects. These other organizations may be located either up or downstream of
the Natural Gas Projects in the production or transmission of electrical power.
The PRI Operator stated that that it believes that the Y2K
deficiencies with the plant DCS system will be resolved with the installation of
the new Foxboro IA control system. The PRI Operator has prepared a "Year 2000
Contingency Planning and Preparations Guide" Draft Version 2.0 dated January 7,
1998, and plans to use this document to make and implement their preparations
for all other Y2K issues at the PRI Project.
This plan calls for complete implementation by July 31, 1999.
OFF-SITE REQUIREMENTS
Makeup water for the PRI Project is supplied from two local
lakes under a contract with the Colorado River Municipal Water District which
expires on September 30, 2003. Water from the lakes is clarified on site and
filtered before being utilized by the plant demineralized water equipment and
cooling tower makeup. Potable water for plant general use is supplied by Fina as
part of the site lease agreement, however the plant utilizes bottled water for
drinking water. A septic tank located near the warehouse handles the PRI Project
sanitary waste.
The 345 kV electric transmission lines extend approximately 7
miles from the PRI Project Site to the TUEC transmission system.
Natural gas is obtained from FSGC, a wholly owned subsidiary
of CE Generation, via pipeline into the PRI Project Site. Refinery gas is
obtained from the Fina refinery adjacent to the PRI Project Site. Jet "A" fuel
is obtained from Fina.
Based on C.C. Pace's review of the PRI Gas Supply Agreement,
the FSGC Gas Transportation Contracts, the Louis Dreyfus Gas Contract, the PRI
Refinery Gas Contract, C.C. Pace's fuel cost projections, and our estimate of
the fuel requirements of the PRI Project, we are of the opinion that the PRI
Project possesses sufficient contract or spot natural gas commodity supplies to
meet the requirements of the PRI PPA and that its contracted natural gas
transportation capacity is adequate to deliver the natural gas supply
requirements over the term of the PRI PPA.
B-7
<PAGE>
REVIEW OF TECHNOLOGY
The GE Frame 7EA is proven technology and in general has
exhibited the qualities of a reliable mature gas turbine technology.
GE has issued Technical Information Letters ("TILs") with
recommendations for the 17-stage compressor for the CTG. The PRI Project
implemented the GE-recommended 17th stage compressor revisions prior to any
failure at the PRI Project and, according to the PRI Operator, has kept up to
date with TILs issued by GE.
In June 1998 CTG No. 1 experienced a field failure. The
failure was caused by thermal expansion and contraction of the generator rotor
bars which obstructed the cooling holes resulting in inadequate cooling. The
generator rotor failure was repaired, however, according to the PRI Operator, GE
has not issued a TIL to address the cause of this failure.
During the June 1998 generator repair, the PRI Project decided
to proceed with the latest turbine up-rate for unit No. 1, which increased the
turbine firing temperature from 2,020(degree)F to 2,035(degree)F. The plant made
the decision to up-rate the turbine to decrease the use of the HRSG duct burner
during peak periods, thus achieving fuel savings due to improved over all plant
heat rate. CTG No. 2 is to be up-rated to the new firing temperature during the
outage scheduled in October 1999.
Based on our review, we are of the opinion that the PRI
Project utilizes sound technology and proven methods of electric and thermal
generation and has generally been designed and constructed in accordance with
generally accepted industry practices. If operated and maintained consistent
with generally accepted industry practices, the PRI Project should be capable of
meeting the requirements of the PRI PPA, the PRI Steam Sales Agreement and
current environmental permits throughout the term of the PRI PPA. Further, the
PRI Project has adequately provided for all off-site requirements, including
fuel, water supply, wastewater disposal and electrical interconnections.
RELIABILITY AND AVAILABILITY
Based on historical performance, review of O&M procedures and
general observation of the PRI Project, we are of the opinion that the PRI
Project is capable of maintaining an annual average availability, inclusive of
curtailed hours, of 92 percent throughout the term of the PRI PPA. This
availability includes the average annual "backdown", or curtailment, hours since
the PRI Project must be available to run during all curtailment periods. The
average capacity factor, which reflects the actual amount of generation, has
been assumed to be 80 percent for the purposes of the Projected Operating
Results, based on the allowed amount of curtailment. The stipulated annual
average capacity factor is the projected average over the term of the PRI PPA.
There may be years when the capacity factor is either above or below the
projected annual average.
STATUS OF PERMITS AND APPROVALS
All of the major permits and approvals required to operate the
PRI Project have been obtained. With respect to its Operating Permit, a new
requirement under Title V of the Clean Air Act, has been applied for with the
Texas Natural Resources Conservation Commission ("TNRCC"). While most of the
permits required for operation must be renewed periodically, we know of no
technical reason that such renewals would not be obtainable. Table 1 summarizes
the status of the major permits and approvals issued for the PRI Project.
B-8
<PAGE>
TABLE 1
PRI PROJECT
STATUS OF KEY PERMITS AND APPROVALS
<TABLE>
<CAPTION>
PERMIT OR APPROVAL RESPONSIBLE AGENCY STATUS COMMENTS
------------------ ------------------ ------ --------
<S> <C> <C> <C>
FEDERAL
QF Status FERC In compliance Noticed 12/29/88
Prevention of Significant USEPA Approved October 14, The PRI Project submitted an
Deterioration ("PSD") Permit 1986 application for amendments to
the Air Quality Permit and the
PSD Permit to the TNRCC on
October 8, 1998
NPDES Storm Water Permit USEPA Approved 11/17/97
STATE
Air Quality Permit TNRCC Approved September 29, Permit No. 17411
1986
Federal Operating Permit TNRCC
Permit Application
Approval Pending
Underground Injection Permits TNRCC Approved 08/29/89 Permit No. WDW-280
Amended 06/23/95 Permit No. WDW-281
Expires: 08/29/99
Solid Waste Registration TNRCC Expires: 11/17/02
</TABLE>
OPERATING HISTORY
PERFORMANCE HISTORY
The PRI Project's historical operating results have been
compiled from data reports provided by the PRI Operator. The PRI Project has
been in full commercial operation since June 1988 and has been operating at an
average availability of 92.3 percent since full commercial operation. The PRI
Project originally operated for a few months in simple-cycle mode until the
HRSGs, steam turbine and other ancillary components were installed for full
combined-cycle operation. The operating history since commercial operation is
summarized in Table 2. Availability shown in Table 2 is defined as the sum of
the total energy delivered to TUEC plus curtailment energy credited by TUEC
divided by the product of the demonstrated capacity of 200 MW times the number
of hours in a year.
TABLE 2
PRI PROJECT OPERATING HISTORY
<TABLE>
<CAPTION>
PRI PPA FUEL STEAM SALES AVAILABILITY(1) CAPACITY
YEAR CAPACITY (MW) NET MWh (MMBtu) (Mlb) (%) FACTOR (%)
---- ------------- ------- ------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
1998 200 1,341,719 12,469,848 716,224 93.7 82.3
1997 200 1,305,333 12,396,779 944,902 91.2 79.7
1996 200 1,286,959 12,208,578 753,783 88.7 77.0
1995 200 1,406,121 13,396,194 847,122 97.4 85.9
1994 200 1,292,641 12,312,121 780,237 91.0 79.5
</TABLE>
(1) The source of the data and calculations in the above table was the TUEC and
PRI monthly reports and the Fina invoices for refinery fuel and steam
sales.
B-9
<PAGE>
Based upon the operating history of the PRI Project and with
an allowance for future degradation, we are of the opinion that, for the purpose
of developing the Projected Operating Results, the PRI Project is capable of
delivering net electrical capability of 200 MW at an annual average heat rate of
approximately 9,500 Btu per kWh on a higher heating value ("HHV") basis and an
availability, inclusive of curtailed hours, of 92 percent for the term of the
PRI PPA.
OPERATING PROGRAMS AND PROCEDURES
We have reviewed with the PRI Operator the various operations
and maintenance programs and procedures, training programs and performance
monitoring systems. We did not review all aspects of these plans and procedures.
However, we verified that the PRI Operator had in place all of the usual and
necessary plans, procedures and documentation normally required to operate
facilities of this type.
The PRI Operator has implemented computer-based maintenance
management systems at the PRI Project which schedule and track regularly
scheduled preventive maintenance activities. The PRI Operator reported that
equipment vendor maintenance recommendations were followed when setting up the
maintenance management systems. These systems are also used to track corrective
and emergency work orders and to keep equipment-specific records of maintenance
activities, parts use, and labor requirements. All but minor maintenance on the
CTGs is subcontracted to GE. The PRI Operator utilizes the computer software
program Mainsaver(R) to assist it in its preventive and corrective maintenance
programs.
We did not review in detail the operations and maintenance
procedures for major equipment and systems. However, the plant does have in
place operating and procedural manuals.
Spare parts are stored in both the in-plant warehouse area and
a separate yard warehouse. Items stored on the PRI Project Site are those items
requiring climatized storage. Items stored in the warehouse adjacent to the PRI
Project Site are items not requiring climatized storage and large bulky items.
Items are referenced by computer storage number in accordance with the software
program Mainsaver(R).
The PRI Operator's training programs provide an initial
two-year employee training, however, refresher training is not currently
provided.
We have reviewed the organizational structure for the
operation and maintenance for the PRI Project. There is a total of 24 operation
and maintenance personnel.
REGULATORY COMPLIANCE
The PRI Project is subject to various permits and approvals
issued by the TNRCC, USEPA, FERC. These permits and approvals establish design
criteria, performance standards, monitoring, recordkeeping and reporting
requirements for the CTGs, HRSGs, and ancillary equipment at the PRI Project.
Although we did not conduct a detailed environmental audit,
the following describes our understanding of the status of the PRI Project with
respect to requirements set forth in its permits and approvals, pending
regulations, and applicable environmental management laws and regulations based
on review of documents provided for our on-site review and discussions with the
PRI Operator. Based on our review, we are of the opinion, the PRI Project
appears to be operating in general compliance with applicable environmental
permits, approvals, laws, rules and regulations.
AIR QUALITY PERMITS
Before initiating construction on the PRI Project, PRI
obtained an Air Quality Permit from the TNRCC and a PSD Permit from the USEPA.
These permits specify design criteria, emission limitations and compliance
monitoring requirements for the CTGs, HRSGs, and emergency diesel generators.
On October 8, 1998, the PRI Project submitted an application
for amendments to the Air Quality and PSD permits previously approved by the
TNRCC. The amendments were necessitated as a result of the CTG
B-10
<PAGE>
up-rate which increased the output and firing temperature on CTG No. 1. As a
result, the PRI Project must amend the previously approved permits to reflect
the attendant increase in potential emissions. The increase in potential
emissions, however, will not constitute a major modification under the PSD
Rules.
Based on the initial stack tests, the CTGs and HRSGs comply
with the emission limitations specified in the Air Quality and PSD Permits. The
last four quarterly reports submitted for the CTGs also demonstrated general
compliance with the operating criteria specified in the permits.
FEDERAL OPERATING PERMIT
The PRI Project submitted an administratively complete
application for a Federal Operating Permit to the TNRCC by the deadline
specified in 30 TAC ss.122.130. The permit application cites the emission
limitations and monitoring, recordkeeping and reporting requirements stipulated
in the previously approved Air Quality and PSD Permits. If the application is
approved as submitted to the TNRCC, no new requirements will be imposed on the
CTGs, HRSGs, or emergency diesel generators in the Federal Operating Permit.
NEW SOURCE PERFORMANCE STANDARDS
Because the CTGs and HRSG duct burners have maximum heat input
greater than 100 MMBtu per hour ("MMBtu/hr"), they are subject to the New Source
Performance Standards ("NSPS") for Stationary Gas Turbines (40 CFR, Subpart GG)
and Industrial Steam Generating Units (40 CFR, Subpart Db). Immediately after
startup, the PRI Project was required to conduct stack test to demonstrate
compliance with the NSPS. The PRI Project is also required to continuously
record the electrical generation, fuel consumption, and steam-to-fuel ratio in
each CTG and to report excess emissions from the CTGs quarterly to the USEPA.
Based on the initial stack tests, the CTGs and HRSGs were
shown to readily comply with the emission limitations specified in the
applicable NSPS. The last four quarterly reports submitted for the gas turbines
also demonstrated general compliance with the applicable standards.
UNDERGROUND INJECTION PERMITS
The PRI Project disposes of industrial wastewater, including
regenerative wastes and cooling tower blowdown, in two injection wells located
near the PRI Project Site. The TNRCC issued the original permits to conduct
Class I underground injection for the two disposal wells on August 29, 1989. The
PRI Project applied for amended permits before expiration of the original
permits on August 29, 1994. The amended permits were issued on January 3, 1995
and will expire on August 29, 1999.
HAZARDOUS AND SOLID WASTE REGISTRATION
In accordance with 30 TAC 331, the PRI Project reports and, as
necessary, updates solid waste generation at the PRI Project on Notice of
Registration ("NOR") Forms submitted to the TNRCC. An annual report documenting
the generation, transportation, disposal and recycling of both hazardous and
Class I non-hazardous waste is also filed with the TNRCC. Based on the annual
waste summary, a waste generation fee is assessed on the waste stored on site or
disposed of off site at the end of each reporting year by the TNRCC. Waste that
is recycled is exempt from the waste generation fee.
STORMWATER PERMIT
The PRI Project previously operated under an NPDES baseline
general permit for stormwater discharges associated with industrial activities
issued by the USEPA on September 25, 1992. Before expiration of the NPDES
baseline general permit on September 25, 1997, the PRI Project submitted a
Notice of Intent ("NOI") for coverage under the NPDES multi-sector general
permit associated with industrial activities to the USEPA. The USEPA
subsequently issued a notice of coverage under the NPDES multi-sector general
permit to the PRI Project on November 17, 1997.
B-11
<PAGE>
QF STATUS
The PRI Project is required by the PRI PPA to be a QF. On
December 29, 1988, the PRI Project filed a notice with FERC of the qualifying
status as a cogeneration facility for the PRI Project. Actual average Operating
Standards and Efficiency Standards required for a QF, as provided by the PRI
Operator, are listed in Table 3.
TABLE 3
PRI PROJECT QF STATISTICS
<TABLE>
<CAPTION>
OPERATING EFFICIENCY
YEAR STANDARD (%) STANDARD (%)
---- ------------ ------------
<S> <C> <C>
1998 18.91 49.22
1997 20.24 43.95
1996 20.27 48.74
1995 19.04 49.05
</TABLE>
PROJECTED OPERATING RESULTS
We have reviewed the historical operating information,
estimates and projections of electrical generating capacity, steam generation
capacity, fuel consumption, and operating costs of the PRI Project made
available to us by CE Generation. On the basis of such data, we have prepared
the Projected Operating Results. The Projected Operating Results are presented
for each calendar year beginning January 1, 1999, representing the beginning of
the quarterly distributions which will be available to CE Generation, through
September 30, 2003, the expiration date of the PRI PPA. Revenues for the PRI
Project are derived primarily from the sale of electricity to TUEC and steam to
Fina. Expenses consist of the cost of fuel, including transportation, as
estimated by C.C. Pace, and operating and maintenance expenses, based on the
information provided by CE Generation, and existing senior debt service, as
provided by CE Generation. Projected sources of revenues and expenses have been
set for the PRI Project in the Projected Operating Results presented in Exhibit
B-1. The Projected Operating Results are based on current contractual
commitments as described herein and have been prepared using assumptions and
considerations set forth in this Report and in the footnotes to Exhibit B-1.
ANNUAL OPERATING REVENUES
REVENUES FROM THE SALE OF ELECTRICITY
The PRI PPA with TUEC expires September 30, 2003. TUEC is
required to purchase all of the output from the PRI Project up to 200 MW per
hour except when they elect to curtail the PRI Project down to a minimum of 79
MW. In any 12 consecutive months, the aggregate amount of all curtailments
cannot be of such magnitude as to jeopardize the PRI Project's QF status. TUEC
history of curtailments has not exceeded 300,000 MWh for any 12-month period.
The PRI PPA specifies pricing for capacity and energy
delivered to TUEC. The capacity payment is based on a firm capacity of 200 MW
with an annual capacity factor greater than 65 percent. If the annual capacity
factor falls below 65 percent, the capacity payment is zero. In addition,
capacity billing adjustments can occur if the peak month capacity factor is less
than 75 percent or if the peak period capacity factor is less than 82 percent.
For the purposes of the Projected Operating Results, we have assumed that the
PRI Project will achieve a peak period capacity factor such that no adjustments
to the capacity payments will be made. Based on the maximum level of curtailment
allowed under the PRI PPA, for the purposes of the Projected Operating Results,
we have assumed an annual average capacity factor of 80 percent over the term of
the PRI PPA.
The PRI PPA specifies energy rates for energy produced under a
72.5 percent capacity factor. When the PRI Project has a monthly capacity factor
at or above 72.5 percent, the energy rate is equal to 99 percent of TUEC's
Weighted Average Cost of Gas ("WACOG"). The WACOG is determined using a heat
rate of
B-12
<PAGE>
10,300 Btu per kWh and TUEC's average cost of gas for the applicable month,
which has been estimated by C.C. Pace. The capacity and energy pricing for
energy produced under a 72.5 percent capacity factor pursuant to the PRI PPA are
presented in Table 4.
TABLE 4
PRI PPA CAPACITY AND ENERGY PRICES
<TABLE>
<CAPTION>
CAPACITY PRICE ENERGY PRICE
YEAR ($/KW-MO) ($/MWH)
---- -------------- ------------
<S> <C> <C>
1999 $16.24 $31.70
2000 16.81 32.80
2001 17.40 34.00
2002 18.00 35.20
2003 18.63 36.40
</TABLE>
REVENUE FROM THE SALE OF STEAM
The PRI Project has entered into the PRI Steam Sales Agreement
for the sale of steam to Fina expiring September 30, 2003. The volume of steam
Fina is required to purchase must be sufficient to allow the PRI Project to
maintain its QF status under PURPA. The steam capacity available to Fina is
between 51,000 pph and 115,000 pph. The minimum capacity Fina is required to
purchase is 440,000 Mlb of steam annually. For the purposes of the Projected
Operating Results, we have assumed that Fina will purchase 830,000 Mlb of steam
per year, as estimated by CE Generation. Under the terms of the PRI Steam Sales
Agreement, the price of steam is equal to $2.45 in 1991 dollars, escalating at a
rate of 2.0 percent each June 1 beginning June 1, 1992.
INTEREST INCOME
We have included interest income on the senior debt service
reserve and major maintenance reserve funds required under the Restated Term
Loan Agreement dated December 30, 1988. CE Generation reports that the debt
service reserve fund requirement is currently funded at $5,917,000 and is
required to be maintained at a level equal to the next quarter's debt service
payment. The major maintenance reserve fund has a minimum requirement, which we
have assumed, of $1,000,000. CE Generation has estimated interest income on
these reserve funds at a rate of 5.5 percent per year. The debt service reserve
fund is assumed to be distributed to CE Generation upon the final payment of the
term loan.
ANNUAL OPERATING EXPENSES
FUEL COSTS
The PRI Refinery Gas Contract obligates the purchase of an
average of 3,600 MMBtu/day of refinery gas. The PRI Refinery Gas Contract
terminates on September 30, 2003 with the provision that it can be extended for
a period of two years. For the purposes of the Projected Operating Results, we
have assumed that the PRI Project will use approximately 1,051,000 MMBtu year.
Under the terms of the PRI Refinery Gas Contract, the price of refinery gas is
equal to $2.20 per MMBtu in 1987 dollars and escalates each January 1 at a rate
of 2 percent annually.
Natural gas is delivered to the PRI Project pursuant to the
PRI Gas Supply Agreement with FSGC. FSGC provides gas through a separate
contract with Louis Dreyfus, which expires October 1, 2003. The contractual
rates under the Louis Dreyfus Gas Contract are fixed at $2.81 per MMBtu, which
escalates by 3 percent per year each June 1 beginning June 1, 1997. Portions of
the gas supplied under the Louis Dreyfus Gas Contract are priced on a spot
basis. For the purpose of the Projected Operating Results, we have assumed a
spot price of gas to the PRI Project as estimated by C.C. Pace. An annual
reservation fee of $547,500, which is escalated at 3 percent per year starting
in July 1, 1996, is also applied.
B-13
<PAGE>
Under the PRI Gas Supply Agreement, the PRI Project pays
$0.075 per MMBtu in transportation charges. For deliveries above 25,000
MMBtu/day, an additional $0.06 per MMBtu is charged.
OPERATION AND MAINTENANCE EXPENSES
The PRI Project is operated by FPOC, a wholly-owned subsidiary
of CE Generation, (the "PRI Operator") in accordance with the PRI O&M Agreement,
which expires January 2004. The PRI Operator is reimbursed for direct costs for
operations and maintenance and receives payment for an operator fee, management
fee, operator's incentive fee, and any applicable sales or use tax. Pursuant to
the PRI O&M Agreement, the annual PRI Operator's fee is $660,000 in 1989 dollars
and escalates each January 1 at a rate of 3.5 percent and the annual management
fee is fixed at $240,000. The PRI Operator's incentive fee is equal to 1.125
percent of gross revenue if the PRI Project operates at an annual capacity
factor in excess of 82 percent. Base on the assumed capacity factor of 80
percent in the Projected Operating Results, the PRI Operator would not receive
an incentive fee.
SENIOR DEBT SERVICE
Based on information provided by CE Generation, we have
included a senior debt service payment based on the term loan principal amount
of $90,529,000 as of January 1, 1999 and an interest rate of 10.385 percent per
year in 1999 and 2000 and 10.635 percent per year from 2001 through 2003. The
remaining balance of the term loan is payable in quarterly installments and
matures on December 31, 2003.
DISTRIBUTIONS TO CE GENERATION
CE Generation indirectly owns 100 percent of the PRI Project
and therefore it has been assumed that 100 percent of the cash available for
distributions will be available to CE Generation.
SARANAC PROJECT
The Saranac Project is a nominal 240 MW combined-cycle
cogeneration facility which commenced commercial operation in June 1994. The
Saranac Project sells electric energy and capacity to NYSEG pursuant to the
Saranac PPA while selling process steam to Georgia-Pacific and Tenneco.
The Saranac Project consists of two natural gas-fired GE Frame
7EA CTGs exhausting to separate HRSGs. The HRSGs produce HP steam which is
directed to a single STG for additional power generation, IP steam as process
steam and STG admission, and LP steam for use in the integral HRSG deaerators.
Duct firing of the HRSGs is provided to generate additional steam. Propane is
stored on site for use when natural gas is unavailable.
PROJECT OPERATOR
The Saranac Project is operated under the Saranac O&M
Agreement by FPOC (the "Saranac Operator"). The Saranac Operator commenced
operation and maintenance of its first combined-cycle cogeneration facility in
1987.
THE PROJECT
THE PROJECT SITE
The Saranac Project is located in the Town of Plattsburgh, New
York near the existing Georgia-Pacific tissue plant and adjacent to the D&H
railroad (the "Saranac Project Site") (see Figure B-2, Saranac Project Site
Plan). The general area is industrial in nature with Tenneco and Georgia-Pacific
being the closest neighbors to the Saranac Project Site. The Saranac Project
Site is easily accessible from highway I-87.
B-14
<PAGE>
ENVIRONMENTAL SITE CONDITIONS
We have not reviewed any reports of previous or recent
environmental investigations regarding the potential for site contamination
issues at the Saranac Project Site. Because we did not conduct or review such
environmental reports, we can offer no opinion with respect to potential site
contamination at the Saranac Project Site or potential future remediation costs
should contamination be found.
As of February 1999, the Saranac Project was not listed on
USEPA's National Priorities List of Superfund Sites or USEPA's CERCLIS List. The
Saranac Project is not listed on the Inactive Hazardous Waste Disposal Sites
list, dated April 1998, published by NYSDEC.
The Saranac Operator reported that there have been three
relatively minor reportable spills over the last three years of operation. As
required, NYSDEC was notified in all cases and the Saranac Operator took
appropriate remedial action. NYSDEC has not required any further action.
Visual inspections during our Saranac Project Site visit of
February 4, 1999 indicated that the Saranac Operator is following "good
housekeeping" procedures. We did not observe any unusual stained or soiled areas
and the Saranac Operator maintains spill cleanup kits at various locations on
the Saranac Project Site. The transformers, acid, caustic and ammonia storage
tanks all have adequate secondary containment.
We are not aware of any potential groundwater or soil
contamination. The Saranac Operator stated that there are no soil or groundwater
monitoring requirements for the Saranac Project Site.
DESCRIPTION OF THE PROJECT
MECHANICAL EQUIPMENT AND SYSTEMS
The Saranac Project utilizes two dry low NOx ("DLN") GE Frame
7EA CTGs firing natural gas with a hydrogen-cooled generator. The CTGs are
supplied by GE with auxiliary equipment required for an indoor installation.
Each CTG exhausts to a dedicated Deltak three pressure level
HRSG with an integral deaerator and feedwater heater. Each HRSG incorporates a
natural gas fired duct burner to supplement steam production. The Saranac
Project delivers up to 144,000 pph of steam at 250 psia and 450(degree)F to
Georgia-Pacific.
The GE-supplied STG is a single automatic extraction
condensing unit with a controlled automatic induction/extraction, capable of
generating 77,614 kW at an inlet steam flow rate of 549,400 pph of 1,265 psia
and 925(Degree)F steam and a back pressure of 2 inches of mercury ("in. HgA").
The STG exhaust steam is condensed in an air-cooled condenser
located to the north of the main facility building. A 3,000 psi water wash
system has been added for once-a-year high pressure spray type washing to clear
springtime poplar seed strings and other airborne fouling items.
The A frame, all galvanized fin and tube air-cooled condenser
is manufactured by GEA Power Cooling Systems, Inc. The air-cooled condenser
package includes required air removal equipment (two 100 percent redundant steam
jet air ejectors and one hogging ejector), fans with two speed motor drives, a
condenser support structure, a condensate collection tank, an exhaust duct,
certain piping and controls.
ENVIRONMENTAL CONTROL SYSTEMS
A DLN combustor system is utilized in the CTGs to limit NOx
emissions. A selective catalytic reduction ("SCR") and a CO catalyst are
installed in the HRSG to meet the air permit emission limits. SCR controls the
NOx emissions from the CTGs and the duct burners to below 9 parts per million
("ppm"). The production of CO is controlled by the use of a CO catalyst.
B-15
<PAGE>
The Saranac Project wastewater, including boiler and cooling
tower blowdown, discharges to the Town of Plattsburgh wastewater treatment
facility after on-site pretreatment as required, which consists of automatic pH
adjustment. Stormwater discharges to a swale running alongside the Saranac
Project Site and subsequently to Scomotion Creek.
Facility floor drains discharge to oil/water separators and
then to the Town of Plattsburgh sanitary system. Drains in the acid/caustic tank
area flow to a neutralization tank prior to discharge to the oil/water
separators and to the town of Plattsburgh sanitary system.
ELECTRICAL AND CONTROL SYSTEMS
The electrical interface with the electric transmission grid
is at the substation located approximately two miles from the Saranac Project
Site. The connecting 115 kV underground cable is run in a connected duct and the
SF-6 breakers are inspected every time the unit is down for a maintenance
outage.
The Saranac Project has two 1,500 kW gas-fired standby
generators, one in the main powerhouse and one in the auxiliary boiler building.
There is also a 1,500 kW No. 2 oil-fired emergency diesel generator. These
generators are capable of black-starting the Saranac Project. An additional 400
kW No. 2 oil-fired generator is available for emergency lighting and other
emergency/maintenance requirements.
The instrumentation and control system is a Foxboro DCS and
provides for custom graphics, system diagnostics, historical trending and report
generation. Redundant multi-loop and microprocessors are provided for process
protection, control and monitoring.
We have reviewed the Y2K Issue with the Saranac Operator. The
Saranac Operator reports that its Y2K compliance review is approximately 80
percent complete. The balance of the review is scheduled for completion by late
March 1999. For a description of the Y2K Issue and the scope of our review
relative to the Y2K Issue, please refer to the corresponding subsection of the
PRI Project section of this Report.
OFF-SITE REQUIREMENTS
The Saranac Project utilizes the Town of Plattsburgh water
supply and wastewater disposal systems. Both process and sanitary wastewater
discharge to the Town of Plattsburgh sewer system.
The 115 kV electric transmission lines extend from the Saranac
Project Site to the NYSEG Northend substation. One 115 kV transmission line
continues on to the NYPA Plattsburgh substation and the other continues on to
the proposed NYSEG Ashley Road substation.
The gas pipeline route is 22 miles long and extends from the
Canadian border near the town of Chazy, where the line pressure is approximately
1,000 psi, to the Saranac Project Site. The route generally parallels highway
I-87; however, only a small portion directly abuts the right-of-way of I-87.
Based on C.C. Pace's review of the Saranac Gas Supply
Agreement, the Saranac Gas Transportation Contracts, C.C. Pace's fuel cost
projections, and our estimate of the fuel requirements of the Saranac Project,
we are of the opinion that the Saranac Project possesses sufficient firm
contract natural gas commodity supplies to meet the requirements of the Saranac
PPA and that its contracted firm natural gas transportation capacity is adequate
to deliver the natural gas supply requirements over the term of the Saranac PPA.
B-16
<PAGE>
FIGURE B-2
SARANAC PROJECT
SITE PLAN
[Graphic Showing Site Plan of the Saranac Project Omitted]
B-17
<PAGE>
REVIEW OF TECHNOLOGY
While the operating experience of the GE Frame 7EA CTG is
extensive, it has experienced some problems recently at facilities similar to
the Saranac Project. These problems have been addressed at the Saranac Project
and solutions have been incorporated as follows:
o The GE Frame 7EA electric generators have been found to have out-of-phase
vibration which over time has caused fatigue failure at certain stress
points within the generator. The Saranac Project's electric generators Nos.
1 and 2 have been upgraded by GE and this problem has not occurred.
o An apparent manufacturing defect has been found in certain electric
generators regarding an inadequate number of side ripple springs. The
insufficient number of ripple springs could lead over time to the
degradation of the electric generator insulation and cause generator bar
stator default. The Saranac Project's electric generators have had the
generator wedges reglazed and this problem is not expected to occur.
o The combustion turbines 17th stage compressor vanes failed and caused
limited compressor and combustor damage in previous units of this
generation. GE corrected this situation with an upgrade and the problem is
not expected to occur at the Saranac Project.
o Risk of potential damage to first stage compressor blades due to icing.
Potential icing conditions are understood and watched for by the Saranac
Operator. An air inlet icing situation has not been reported to have
occurred at the Saranac Project.
Based on our review, we are of the opinion that the Saranac
Project utilizes sound technology and proven methods of electric and thermal
generation and has generally been designed and constructed in accordance with
generally accepted industry practices. If operated and maintained consistently
with generally accepted industry practices, the Saranac Project should be
capable of meeting the requirements of the Saranac PPA, the Georgia-Pacific
Steam Sales Agreement, the Tenneco Steam Sales Agreement, and current
environmental permits throughout the term of the Saranac PPA. Further, the
Saranac Project has adequately provided for all off-site requirements, including
fuel, water supply, wastewater disposal and electrical interconnections.
RELIABILITY AND AVAILABILITY
Based on historical performance, review of O&M practices and
procedures and general observation of the Saranac Project, we are of the opinion
that the Saranac Project is capable of maintaining an annual average
availability of 94 percent. The stipulated annual average capacity factor is the
projected average over the term of the Saranac PPA. There will be years when the
availability is either above or below the projected annual average.
STATUS OF PERMITS AND APPROVALS
All of the major permits and approvals required to operate the
Saranac Project have been obtained. While most of the permits required for
operation must be renewed periodically, we know of no technical reason that such
renewals would not be obtainable.
A draft Title V Operating Permit was issued by NYSDEC on
January 15, 1999. After the 30-day public comment period, the NYSDEC has another
45 days to comment and, assuming no problems arise, issue a final permit. The
draft permit does not contain any new or more restrictive conditions or
limitations, and essentially duplicates the conditions and limitations found in
the PSD Permit Modification dated October 6, 1998, as described later herein.
B-18
<PAGE>
A list of key permits and approvals required for operation,
and a summary of their status, is provided in Table 5. This represents our
understanding based on our Saranac Project Site visit, discussions with the
Saranac Operator, and a brief review of selected documents.
TABLE 5
SARANAC PROJECT
STATUS OF KEY PERMITS AND APPROVALS
<TABLE>
<CAPTION>
PERMIT OR APPROVAL RESPONSIBLE AGENCY STATUS COMMENTS
------------------ ------------------ ------ --------
<S> <C> <C> <C>
FEDERAL
QF Status FERC In compliance Refer to text
Wetlands Permit U.S. Corps of Obtained prior to Compensatory wetlands
Engineers (joint construction monitoring has been
with NYSDEC) completed
STATE
Air Quality Certificate to Operate NYSDEC Issued: December 20, 1994
Expires: December 20, 1999
Title V Operating Permit NYSDEC Received draft permit Currently in 30-day public
January 15, 1999 comment period
State Pollution Discharge NYSDEC Issued: November 1, 1998 A general permit for
Elimination System ("SPDES") stormwater discharge
LOCAL
Wastewater Discharge Permit for Town of Plattsburgh Issued: November 1, 1996 Revised July 1, 1997
discharge to Town of Plattsburgh Expires: October 31, 2001 Requires weekly, monthly,
sewer system quarterly monitoring and
reporting
</TABLE>
OPERATING HISTORY
PERFORMANCE HISTORY
The Saranac Project's historical operating results have been
compiled from monthly operating reports provided by CE Generation. The Saranac
Project has been in commercial operation since June 1994 and has been operating
at an average availability of 94.9 percent since commercial operation. The
operating history since commercial operation is summarized in Table 6.
TABLE 6
SARANAC PROJECT OPERATING HISTORY
<TABLE>
<CAPTION>
FUEL STEAM SALES AVAILABILITY CAPACITY
YEAR AVERAGE MW NET MWh (MMBtu) (Mlb) (%) FACTOR (%)
---- ---------- ------- ------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
1998 207 1,680,912 14,563,522 778,039 92.8 85.4
1997 223 1,855,184 15,890,597 742,698 97.7 95.0
1996 227 1,886,894 15,869,553 628,175 95.2 97.0
1995 237 1,971,795 16,419,574 499,237 98.4 95.1
1994 235 937,931 7,964,336 128,792 90.7 89.4
</TABLE>
Based upon the operating history of the Saranac Project and
with an allowance for future degradation, we are of the opinion that, for the
purpose of developing the Projected Operating Results, the Saranac
B-19
<PAGE>
Project is capable of delivering net electrical capability of 240 MW at an
annual average heat rate of approximately 8,550 Btu per kWh (HHV) and an
availability of 94 percent for the term of the Saranac PPA.
OPERATING PROGRAMS AND PROCEDURES
We have reviewed with the Saranac Operator the various
operations and maintenance programs and procedures, training programs and
performance monitoring systems. We did not review all aspects of these plans and
procedures. However, we verified that the Saranac Operator had in place all of
the usual and necessary plans, procedures and documentation normally required to
operate facilities of this type. Specific documents reviewed included: Standard
Operating Guidelines, Technician Qualification Program, Plant Start-up/Shut-down
Checklist, and Control Room Operator Qualification.
The Saranac Operator has implemented computer-based
maintenance management systems at the Saranac Project which schedule and track
regularly scheduled preventive maintenance activities. The Saranac Operator
reported that equipment vendor maintenance recommendations were followed when
setting up the maintenance management systems. These systems are also used to
track corrective and emergency work orders and to keep equipment-specific
records of maintenance activities, parts use, and labor requirements. All but
minor maintenance is subcontracted to GE. The Saranac Operator utilizes the
computer software program Mainsaver(R) to assist it in its preventive and
corrective maintenance programs.
We reviewed operations and maintenance procedures for major
equipment and systems. The procedures appeared complete and included drawings
and vendor manuals as well as step-by-step operating instructions and
maintenance schedules. Normal daily maintenance is performed by the Saranac
Operator's on-site personnel.
Spare parts are stored in both the in-plant warehouse area and
a separate yard warehouse. Items are stored by computer storage number in
accordance with the software program Mainsaver(R). Larger items requiring a fork
lift are stored in the yard warehouse, a five-level rack storage facility.
The Saranac Operator's training programs provide initial
employee training as well as periodic training to maintain competency of the
Saranac Operator's on-site personnel.
We have reviewed the organizational structure for the
operation and maintenance for the Saranac Project. There is a total of 24
operation and maintenance personnel.
REGULATORY COMPLIANCE
The Saranac Project must be operated in accordance with all
applicable environmental permits, approvals, laws, rules and regulations.
Although we did not conduct a detailed environmental audit, the following
describes our understanding of the status of the Saranac Project with respect to
requirements set forth in its permits and approvals, pending regulations, and
applicable environmental management laws and regulations based on review of
documents provided for our on-site review and discussions with NYSDEC. Based on
our review, we are of the opinion that the Saranac Project appears to be
operating in general compliance with applicable environmental permits,
approvals, laws, rules and regulations with the exceptions noted below.
AIR PERMIT
Review of the last four quarterly summary reports for the
Saranac Project indicates that it has demonstrated satisfactory compliance with
permitted emission limits and that monitoring systems are being properly
maintained.
Saranac performed emissions testing to demonstrate compliance
with all applicable emissions requirements at low load operation. A PSD Permit
Modification was issued by NYSDEC on October 6, 1998, which allows for gas
turbine operation as low as 43 MW at 50(Degree)F, down from the original
operating limit of 64.5 MW at 50(Degree)F. The draft Title V Operating Permit
contains the same restrictions with respect to gas turbine
B-20
<PAGE>
operation to 50 percent load, defined as 43 MW at 50(Degree)F. Further, both the
PSD Permit Modification and the draft Title V Operating Permit extend the
allowable startup/shutdown time from 3 to 6 hours.
QF STATUS
The Saranac Project is required by the Saranac PPA to be a QF.
Actual average Operating Standards and Efficiency Standards as provided by the
Saranac Operator are listed in Table 7.
TABLE 7
SARANAC PROJECT QF STATISTICS
<TABLE>
<CAPTION>
OPERATING EFFICIENCY
YEAR STANDARD (%) STANDARD (%)
---- ------------ ------------
<S> <C> <C>
1998 12.43 46.72
1997 11.98 46.92
1996 7.47 46.77
1995 6.35 47.63
</TABLE>
NOx BUDGET RULE
As a further measure to bring all areas of the State of New
York into compliance with the National Air Quality Standard for ozone, NYSDEC
developed a NOx Budget Rule 6NYCRR27-3 that set up a NOx cap, allowance and
trading system similar, on a state level, to the Federal SO2 allowance program
under Title IV of the Clean Air Act Amendments of 1990. Each facility in
operation by 1997 was allocated a certain number of allowances. If, in a given
year's ozone season beginning in 1999, a facility emits more than its available
allowances, it will have to purchase further allowances from other sources at
market prices. If a facility emits less than its allowances, it may sell the
excess allowances on the open market. The Saranac Project was allocated 177 tons
per year of NOx allowance for the ozone season. Saranac submitted a plan to
NYSDEC in December 1998 to modify their CEMS data acquisition system to support
NOx trading. The Saranac Project is awaiting approval before implementing the
modifications.
WASTEWATER AND STORMWATER DISCHARGE
Documents reviewed indicate that the Saranac Project has been
operating in compliance with requirements of the wastewater and stormwater
permits. As required under the wastewater discharge permit, the Saranac Operator
submits weekly, monthly and quarterly reports to the Town of Plattsburgh. Review
of these documents indicated they are comprehensive and demonstrate the Saranac
Project's compliance with applicable limits. The Saranac Operator reports there
have been no exceedances of wastewater limits during 1996, 1997, and 1998.
WETLANDS
The Saranac Project is required to monitor a wetlands
mitigation area the size of 1.5 times the area of wetlands disturbed by the
Saranac Project for 5 years after commercial operation. This monitoring was
completed in November 1999.
GENERAL COMPLIANCE
Although we did not conduct a detailed environmental audit,
the following observations are based on our review of related documentation and
a Saranac Project Site visit and walkover conducted in February 1999. In
general, the Saranac Project appeared to be using good housekeeping procedures
and appropriate handling practices.
B-21
<PAGE>
The Saranac Operator reported that a noise monitoring survey,
performed in 1994, did not reveal any significant problems. Two public
complaints during the summer of 1997 have been resolved. A nearby facility, and
not the Saranac Project, was determined to be the source of excessive noise.
According to the Saranac Operator, there have been no further noise complaints
since then.
As required by the SPDES permit, the Saranac Operator
maintains a Spill Prevention Countermeasure and Control ("SPCC") plan detailing
spill cleanup procedures and appropriate plant personnel responsible for
completing such procedures. CE Generation reported that the SPCC plan was
completed on March 30, 1998.
We understand that the Saranac Project is classified as a
"small quantity generator" of hazardous waste under the applicable regulations.
The Saranac Operator maintains a log of all manifests for hazardous materials
shipped from the Saranac Project Site. Review of these manifests indicates
shipments consist primarily of oily rags, used oil, and cleanup material from
the three spills: sulfuric acid, polyethylene and ethylene glycol.
A review of Saranac Project logs indicates the Saranac
Operator has submitted the appropriate Superfund Amendments and Reauthorization
Act of 1986 ("SARA") Title II notifications, as required under the Emergency
Planning and Community Right-to-Know Act ("EPCRA") regarding hazardous materials
on-site, to the Town of Plattsburgh and other appropriate parties.
The Saranac Operator reported that internal environmental
audits have been performed in recent years, but these were not made available
for our review.
PROJECTED OPERATING RESULTS
We have reviewed the historical operating information,
estimates and projections of electrical generating capacity, steam generation
capacity, fuel consumption, and operating costs of the Saranac Project made
available to us by CE Generation. On the basis of such data, we have prepared
the Projected Operating Results. The Projected Operating Results are presented
for each calendar year beginning January 1, 1999, representing the beginning of
the quarterly distributions which will be available to CE Generation, through
June 30, 2009, based on the term of the Saranac PPA. Revenues for the Saranac
Project are derived primarily from the sale of electricity to NYSEG and steam to
Georgia-Pacific and Tenneco. Expenses consist of the cost of fuel, including
transportation, as estimated by C.C. Pace, and operating and maintenance
expenses, based on information provided by CE Generation, and existing senior
debt service, as provided by CE Generation. Projected sources of revenues and
expenses have been set forth in the Projected Operating Results presented in
Exhibit B-1. The Projected Operating Results are based on current contractual
commitments as described herein and have been prepared using assumptions and
considerations set forth in this Report and in the footnotes to Exhibit B-1.
ANNUAL OPERATING REVENUES
REVENUES FROM THE SALE OF ELECTRICITY
The Saranac PPA with NYSEG expires in June 2009. NYSEG is
required to purchase all of the output from the Saranac Project up to 240 MW per
hour except for limited curtailment rights. The Saranac PPA specifies annual
on-peak and off-peak variable capacity and energy prices for actual energy
delivered. On-peak hours extend from 7:00 a.m. to 10:00 p.m. weekdays except for
holidays. There is also a price for generation that is available but not
delivered, which is equal to the variable energy rate plus the variable capacity
component less 95 percent of the lesser of (1) 105 percent of sum of the
variable energy rate plus the variable capacity component, or (2) the price of
natural gas times the estimated heat rate. The effective Saranac PPA on-peak and
off-peak prices, excluding the available generation rate, are presented in
Table 8.
B-22
<PAGE>
TABLE 8
SARANAC PPA ELECTRICITY PRICE
($/MWH)
<TABLE>
<CAPTION>
YEAR ON-PEAK PRICE(1) OFF-PEAK PRICE
---- ------------- --------------
<S> <C> <C>
1999 $103.4 $60.9
2000 107.9 63.6
2001 112.5 66.4
2002 117.4 69.3
2003 122.5 72.5
2004 127.9 75.6
2005 133.4 79.0
2006 139.1 82.5
2007 145.3 86.1
2008 151.6 89.9
2009 158.2 93.9
</TABLE>
(1) Includes variable capacity component of electricity price.
REVENUE FROM THE SALE OF STEAM
The Saranac Project has entered into the Georgia-Pacific Steam
Sales Agreement and the Tenneco Steam Sales Agreement for the sale of steam,
both expiring in June 2009. The volume of steam required to be purchased is
sufficient to allow the Saranac Project to maintain its QF status under PURPA.
The total amount of steam assumed to be purchased under these contracts is
713,000 Mlb of steam per year. The average steam price is equal to $3.04 per Mlb
in 1998 dollars and escalates at 4 percent per year thereafter.
INTEREST INCOME
We have included interest income on the debt service reserve
required under the term loan agreement. The debt service reserve fund
requirement is equal to $7,000,000. CE Generation has estimated interest income
on the debt service reserve fund at a rate of 5.5 percent per year. The debt
service reserve fund is assumed to be distributed to CE Generation upon the
final payment of the term loan.
ANNUAL OPERATING EXPENSES
FUEL COSTS
The Saranac Project has entered into the Saranac Gas
Transportation Agreement for the delivery of up to 51,000 MMBtu/day of natural
gas on a firm basis along TransCanada's system. The total contract price for the
gas is fixed in the Saranac Gas Supply Agreement, but is separated into
transportation and commodity components. The transportation component has been
assumed to be equal to approximately $0.88 per MMBtu and the remaining portion
of the contract price is used as the commodity component. The transportation
component is paid for the full 51,000 MMBtu/day at all times (excluding cost
mitigation provided for in the Saranac Gas Supply Agreement). The commodity
component is paid for the actual quantity of gas consumed. The total contract
price is set at $2.97 per MMBtu through October 31, 1994, escalating by 4
percent on each subsequent November 1. The Saranac Project is required to
purchase a minimum annual quantity equal to the annual aggregate of 80 percent
of the maximum daily quantity. To the extent that the Saranac Project uses less
than 51,000 MMBtu/day, certain rebates are made. These price of these rebates
vary monthly, but have been assumed to be equal to approximately $0.56 per MMBtu
and applied to the gas in excess of the average daily consumption.
Under the Gas Transportation Agreement dated December 18, 1992
between North Country Gas Pipeline Corporation ("North Country") and Saranac
(the "North Country Gas Transportation Agreement"), the
B-23
<PAGE>
Saranac Project has contracted with North Country to transport the gas from the
TransCanada system at the Canada- U.S. border to the Saranac Project. Saranac
pays demand charges to North Country; however, North Country is a wholly-owned
subsidiary of Saranac. North Country also receives revenue from other pipeline
customers. For the purposes of the Projected Operating Results, we have included
a credit to the cost of gas transportation for the Saranac Project equal to the
estimated net operating revenue of North Country, as estimated by C.C. Pace.
OPERATION AND MAINTENANCE EXPENSES
Pursuant to the Saranac O&M Agreement, the Saranac Operator
will be compensated for its operations and maintenance services on both a
monthly management fee basis plus reimbursement for its direct costs of
performance. The monthly management fee is adjusted by the Employment Cost Index
for Private Industry White Collar Wages and Salaries. Amendment No. 1 to the
Saranac O&M Agreement agrees to a plan for reduction or increase in the
management fee based on annual availability and heat rate of the Saranac
Project.
The operation and maintenance projections are derived from
operating history provided by the Saranac Operator. Operation and maintenance
expenses are assumed to escalate at inflation with the exception of property
taxes, which have been assumed to remain flat, and labor costs, which have been
assumed to escalate at a rate 2.0 percent above inflation, as estimated by CE
Generation.
SENIOR DEBT SERVICE
Based on information provided by CE Generation, we have
included a senior debt service payment based on the term loan principal amount
of $189,288,000 as of January 1, 1999 and an interest rate of 8.185 percent per
year, as reported by CE Generation. The term loan is payable in quarterly
installments and matures on March 31, 2008. The senior debt service is paid out
of the level 1 distributions and therefore has not been deducted in the
Projected Operating Results from the cash available for distributions.
DISTRIBUTIONS TO CE GENERATION
Saranac's distributable cash flow has two levels of
distribution. The level 1 distribution is paid on a pre-determined schedule. The
level 2 distribution is the remaining portion of distributable cash flow after
the level 1 distribution has been satisfied. Of the level 1 distribution, 99
percent is distributed to General Electric Capital Corporation ("GE Capital")
and 0.3585 percent is available for distribution to a Tomen Power Corporation
subsidiary ("TPC Saranac"). TPC Saranac receives 35.49 percent of the level 2
distributions prior to achieving an 8.35 percent after-tax return. After
achieving an 8.35 percent after-tax return, TPC Saranac's share of the level 2
distributions is reduced to 17.82 percent. GE Capital receives 1 percent of the
level 2 distributions. CE Generation receives all remaining level 1 and level 2
distributions. The TPC Saranac's historic internal rate of return and the
calculation of TPC Saranac's after-tax income have been based on tax and
depreciation assumptions provided by CE Generation.
YUMA PROJECT
The Yuma Project is a nominal 50 MW combined-cycle
cogeneration facility which commenced commercial operation under the Yuma PPA on
May 28, 1994, under which the Yuma Project sells electric energy and capacity to
SDG&E. The Yuma Project sells process steam and steam for chilled water to Queen
Carpet, formerly American-West Industries, Inc., under the Yuma Process ESA and
the Yuma Chiller ESA.
The Yuma Project consists of one dual fuel (natural gas and
fuel oil) Frame 6B CTG exhausting to a separate Nooter-Eriksen three-pressure
HRSG. The HRSG produce HP steam which is directed to a single STG for additional
power generation, IP steam as process steam, CTG for NOx control and auxiliary
boiler heating, and LP steam for use in the integral HRSG deaerators and chiller
steam. Natural gas duct firing of the HRSG is provided to generate additional
steam. Fuel oil is stored on site for use when natural gas is unavailable. The
fuel oil tank capacity is 535,000 gallons or approximately 14 days at full load.
B-24
<PAGE>
PROJECT OPERATOR
The Yuma Project is operated by the Yuma Operator utilizing
Yuma Cogeneration Associates ("YCA") employees without an O&M agreement. YCA is
a wholly-owned, indirect subsidiary of CE Generation. The Yuma Operator has been
operating and maintaining the Yuma Project since 1994.
THE PROJECT
THE PROJECT SITE
The 42.5-acre Yuma Project is located on the northwest
boundary of Yuma, Arizona near the existing Queen Carpet plant and adjacent to
the Santa Clara By-Pass Canal (the "Yuma Project Site") (see Figure C-3, Yuma
Project Site Plan). The Yuma Project Site is located at First Street just west
of B Avenue with the Colorado River to the north. The Yuma Project Site is owned
by YCA. The general area is industrial in nature with some agricultural areas.
The Yuma Project Site is easily accessible by highway.
ENVIRONMENTAL SITE CONDITIONS
We have not reviewed any reports of previous or recent
environmental investigations regarding the potential for site contamination
issues at the Yuma Project Site. Because we did not conduct or review such
environmental reports, we can offer no opinion with respect to potential site
contamination at the Yuma Project Site or potential future remediation costs
should contamination be found.
Visual inspections during our Yuma Project Site visit of
January 28, 1999 indicated that the Yuma Operator is following "good
housekeeping" procedures. We did not observe any unusual stained or soiled areas
and the Yuma Operator maintains spill cleanup kits at the Yuma Project Site. The
transformers, fuel oil, acid, caustic and ammonia storage tanks all have
adequate secondary containment.
As of February 1999, the Yuma Project was not listed on the
USEPA's National Priorities List of Superfund Sites or USEPA's CERCLIS List.
We are not aware of any potential groundwater or soil
contamination. The Yuma Operator stated that there are no soil or groundwater
monitoring requirements for the Yuma Project Site.
DESCRIPTION OF THE PROJECT
MECHANICAL EQUIPMENT AND SYSTEMS
The Yuma Project utilizes a GE Frame 6 PG8541B CTG firing
either natural gas or fuel oil capable of generating approximately 37 MW (gross)
at design conditions (110(degree)F and 23 percent relative humidity). The
combustion turbine is in the process of being "up-rated" to increase firing
temperature which in turn may increase efficiency. The CTG package was
manufactured by GE with the auxiliary equipment required for outdoor operation
but is located in a sound enclosure. An evaporative cooler is included to
increase CTG performance.
The CTG exhausts to a Nooter-Eriksen three-pressure HRSG
integral deaerator and feedwater heater. The HRSG includes a natural gas fired
duct burner to supplement steam-generating capabilities. The HP steam system
delivers HP steam to the STG at conditions discussed below. The HRSG IP steam
system is designed to supply 23,580 pph of CTG NOx control steam at a pressure
of 330 psig and 545(degree)F plus process steam to Queen Carpet (15,000 pph, 130
psig, 375(degree)F). The LP steam system delivers 35,000 pph of LP steam to the
chiller at a pressure of 28 psig and 259(degree)F.
The STG was manufactured by GE and is a dual extraction,
bottom exhaust, condensing unit capable of generating approximately 18 MW
(gross) at a HP steam flow of 158,990 pph at 1,250 psig and 950(degree)F and
back pressure of 2.9 in. HgA. The STG is also located in a sound enclosure and
mounted above the Type 304 stainless steel, single shell, two-pass condenser.
B-25
<PAGE>
The cooling tower supplies the condenser with cooling water at
a design temperature of 91(degree)F. The cooling tower utilizes make-up water
directly from the Colorado River or from the City of Yuma sewage treatment plant
effluent. The cooling tower is a two-cell wooden structure (with PVC fill),
induced mechanical draft, counter flow, evaporative tower.
The chiller system is made up of two steam absorption type
liquid chillers with a respective cooling capacity of 800 tons and 1,100 tons of
refrigeration in the form of chilled water. The chiller system utilizes LP steam
from the Yuma Project and returns the steam in the form of condensate. The
chiller system is owned by Queen Carpet but is operated and maintained by the
Yuma Operator.
The auxiliary boiler provides process steam to Queen Carpet
during SDG&E curtailments and CTG outages. The auxiliary boiler is maintained in
a hot standby condition with steam from the process steam supply header. The
auxiliary boiler system is a stand alone system with its own dedicated
deaerator, feedwater pumps, blowdown separator, and hot water heat exchanger.
The auxiliary boiler has a design steam flow rate of 17,000 pph at 125 psig and
353(degree)F. The auxiliary boiler is designed to operate on natural gas only.
ENVIRONMENTAL CONTROL SYSTEMS
A steam injected CTG system is utilized to limit NOx
emissions. No SCR nor CO catalyst is installed in the HRSG to meet the air
permit emission limits. Steam injection controls the NOx emissions from the CTGs
and the duct burners to below 25 ppm on natural gas and 42 ppm while burning
fuel oil.
The Yuma Project utilizes raw water from the Colorado River
for boiler/steam cycle make-up and evaporative cooling. Potable water is
supplied by the City of Yuma.
In compliance with environmental permits, the Yuma Project
wastewater, including boiler blowdown, cooling tower blowdown, and neutralized
water treatment wastewater is discharged to the Main Outlet Drain Extension
("MODE") canal. Stormwater run-off is discharged to an unlined evaporation
retention pond. The Yuma Project floor and equipment drains also discharge into
the retention pond. The Yuma Project does not include an oily water separator.
Sanitary sewage is discharged to the City of Yuma sewer system.
ELECTRICAL AND CONTROL SYSTEMS
The electrical interface with the electrical transmission grid
occurs at the Arizona Public service ("APS") Riverside 69 kV substation. The
substation located approximately 500 yards from the Yuma Project property
boundary and is connected by an overhead 69 kV transmission line to the Yuma
Project switchyard. Electricity generated by the CTG and STG flows through a
13.8 switchgear to dedicated step-up transformers feeding the switchyard. The
switchyard consists of a dead-end structure with two 69 kV circuit switches and
two 69 kV air break disconnect switches. Yuma Project auxiliary power is taken
from the 13.8 switchgear to feed 4,160 volt and 480 volt station service
transformers which in turn feed 4,160 volt and 480 volt motor control centers.
During curtailment periods, the Yuma Project receives backfeed power from APS
through the step-up transformers. The Yuma Project has no "black-start"
capabilities.
Control for the Yuma Project is provided by a Bailey Controls
INFI 90 microprocessor DCS. The DCS performs/controls plant regulatory systems,
motor systems, monitoring, alarms, operations trending, and events data
recording. The DCS also provides interface with the combustion turbine, CTG,
steam turbine, STG, and HRSG.
We have reviewed the Y2K Issue with the Yuma Operator. The
Yuma Operator reports it has completed an assessment of Y2K problems and these
are predominantly corrected at the Yuma Project Site. The remaining items will
be corrected this spring during the annual outage. Their inventory included
hand-held instruments and they are actually testing the items after correction.
For a description of the Y2K Issue and the scope of our review relative to the
Y2K Issue, please refer to the corresponding subsection of the PRI Project
section of this Report.
B-26
<PAGE>
FIGURE B-3
YUMA PROJECT
SITE PLAN
[GRAPHIC SHOWING SITE PLAN OF THE YUMA PROJECT OMITTED]
B-27
<PAGE>
OFF SITE REQUIREMENTS
The Yuma Project's primary source water is from the Colorado
River as arranged with the City of Yuma. A secondary source is available to the
Yuma Project by taking the tertiary discharge from an adjacent wastewater clean
up facility. The primary source is 300 acre feet per year with an additional 500
acre feet per year available. The option on the additional volume is renewed
every five years.
Natural gas is obtained from SWG via a pipeline into the Yuma
Project Site. Fuel oil is purchased on a spot market basis.
Based on C.C. Pace's review of the SWG Gas Supply and
Agreement, C.C. Pace's fuel cost projections, and our estimate of the fuel
requirements of the Yuma Project, we are of the opinion that the Yuma Project
possesses sufficient contract natural gas commodity supplies to meet the
requirements of the Yuma PPA and that its contracted natural gas transportation
capacity is adequate to deliver the natural gas supply requirements over the
term of the Securities.
REVIEW OF TECHNOLOGY
GE originally developed the Frame 6B as a heavy-duty gas
turbine in 1978. Since its inception, 450 units have been placed in service
worldwide. Problems to date with Frame 6B include premature failure of a limited
number of first stage turbine blades. These failures were blamed on high
temperature deformation in combination with local corrosion. In 1993, GE
developed a new metallurgical process to reduce blade deformation. The Yuma
Project replaced the original first stage turbine blades with the
metallurgically improved blades in 1997.
Based on our review, we are of the opinion the Yuma Project
utilizes sound technology and proven methods of electric and thermal generation
and has been generally designed and constructed in accordance with generally
accepted industry practices. If operated and maintained consistently with
generally accepted industry practices, the Yuma Project should be capable of
meeting the requirements of the Yuma PPA, the Yuma Chiller ESA, the Yuma Process
ESA, and current environmental permits throughout the term of the Securities.
Further, the Yuma Project has adequately provided for all off-site requirements,
including fuel, water supply, wastewater disposal and electrical
interconnections.
RELIABILITY AND AVAILABILITY
Based on historical performance, review of O&M practices and
procedures and general observation of the Yuma Project, we are of the opinion
that the Yuma Project is capable of maintaining an annual average contract
availability of 96 percent. The contract availability is based on the Yuma PPA
which allows major outage type maintenance to occur during the "block" periods
of curtailment. The Yuma PPA specifically prohibits maintenance from occurring
during the "flexible" curtailment periods. Block periods of curtailment are
allocated in either 200 or 400 hour increments. The flexible curtailment periods
are 8 to 10 continuous hour increments. The stipulated annual average capacity
factor is the projected average over the term of the Securities. There will be
years when the availability is either above or below the projected annual
average.
STATUS OF PERMITS AND APPROVALS
All of the major permits and approvals required to operate the
Yuma Project have been obtained. While most of the permits required for
operation must be renewed periodically, we know of no technical reason that such
renewals would not be obtainable.
A list of key permits and approvals required for operation,
and a summary of their status, is provided in Table 9. This represents our
understanding based on our Yuma Project Site visit, discussions with the Yuma
Operator, and a brief review of selected documents.
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<PAGE>
TABLE 9
YUMA PROJECT
STATUS OF KEY PERMITS AND APPROVALS
<TABLE>
<CAPTION>
PERMIT OR APPROVAL RESPONSIBLE AGENCY STATUS COMMENTS
------------------ ------------------ ------ --------
<S> <C> <C> <C>
FEDERAL
QF Status FERC In compliance Refer to text
Waste Water Discharge Permit U.S. Department of Issued March 6, 1993 Does not require renewal
the Interior, Bureau
of Land Reclamation
STATE
Air Permit Arizona Department Issued October 13, 1993 Superseded by Title V
of Environmental Revised September 15, 1995 Operating Permit
Quality ("ADEQ")
Title V Operating Permit ADEQ Draft Permit Issued in Public Notice February
February 1999 1999, expect issuance of
Final April 1999
Aquifer Protection Permit ADEQ Issued September 18, 1996; Backup permit for
valid for the life of the wastewater discharge when
project MODE is out of service
LOCAL
Conditional Use Permit City of Yuma Issued December 12, 1990 Valid for life of
Amended October 14, 1992 project. Covers sanitary
and August 11, 1993 wastewater discharges
Discharge Permit No. 0010 City of Yuma Issued June 13, 1990 Backup for wastewater
Modified June 3, 1994 discharge when MODE is out
of service. Has been
allowed to expire.
</TABLE>
OPERATING HISTORY
PERFORMANCE HISTORY
The Yuma Project's historical operating results have been
compiled from monthly or annual operating reports provided by CE Generation. The
Yuma Project has been in commercial operation since June 1994 and has been
operating at an average contract availability of 96.7 percent since commercial
operation. The operating history since commercial operation is summarized in
Table 10.
TABLE 10
YUMA PROJECT OPERATING HISTORY
<TABLE>
<CAPTION>
FUEL STEAM SALES AVAILABILITY(1) CAPACITY(2)
YEAR AVERAGE MW NET MWh (MMBtu) (Mlb) (%) FACTOR (%)
---- ---------- ------- ------- ------- ------- ----------
<S> <C> <C> <C> <C> <C> <C>
1998 54.5 406,765 3,578,741 214,339 96.0 93.0
1997 50.1 373,626 3,357,027 195,098 96.2 85.3
1996 50.8 378,715 3,316,320 159,963 97.0 86.5
1995 53.4 398,442 3,437,576 206,076 97.8 91.0
</TABLE>
(1) Based on total hours out of service and not during a curtailments.
(2) Based on 7,460 non-curtailed hours in a year and 50 MW.
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<PAGE>
Based upon the operating history of the Yuma Project and with
an allowance for future degradation, we are of the opinion that, for the purpose
of developing the Projected Operating Results the Yuma Project is capable of
delivering net electrical capability of 56.5 MW at an annual average heat rate
of approximately 8,830 Btu per kWh (HHV) and a contract availability of 96
percent (assuming current curtailment practices continue) for the term of the
Securities.
OPERATING PROGRAMS AND PROCEDURES
We have reviewed with the Yuma Operator the various operations
and maintenance programs and procedures, training programs and performance
monitoring systems. We did not review all aspects of these plans and procedures.
However, we verified that the Yuma Operator had in place all of the usual and
necessary plans, procedures and documentation normally required to operate
facilities of this type. Specific documents reviewed included: Standard
Operating Guidelines, Technician Qualification Program, Operator Training
Programs, and Control Room Operator Qualification.
The Yuma Operator has implemented computer-based maintenance
management systems at the Yuma Project which schedule and track regularly
scheduled preventive maintenance activities. CE Generation reported that
equipment vendor maintenance recommendations were followed when setting up the
maintenance management systems, plus utilizing their own experiences. These
systems are also used to track corrective and emergency work orders and to keep
equipment-specific records of maintenance activities, parts use, and labor
requirements. The Yuma Operator utilizes the computer software program
Mainsaver(R) to assist it in its preventive and corrective maintenance programs.
We reviewed operations and maintenance procedures for major
equipment and systems. The procedures appeared complete and included drawings
and vendor manuals as well as step-by-step operating instructions and
maintenance schedules. Normal daily maintenance is performed by the Yuma
Operator's on-site personnel.
Spare parts are stored in both the in-plant warehouse area
and a separate yard shipping containers. Items are stored by computer storage
number in accordance with the software program Mainsaver(R). The warehouse and
maintenance shop are fork lift accessible.
The Yuma Operator's training programs provide initial employee
training as well as periodic training to maintain competency of the Yuma
Operator's on-site personnel. The core training program was designed and is
maintained by the Yuma Operator and consists of ten modules. Specific special
training is addressed based on needs.
We have reviewed the organizational structure for the
operation and maintenance for the Yuma Project. There is a total of 15 operation
and maintenance personnel.
REGULATORY COMPLIANCE
The Yuma Project must be operated in accordance with all
applicable environmental permits, approvals, laws, rules and regulations.
Although we did not conduct a detailed environmental audit, the following
describes our understanding of the status of the Yuma Project with respect to
requirements set forth in its permits and approvals, pending regulations, and
applicable environmental management laws and regulations based on review of
documents provided for our review and discussions with the Yuma Operator. Based
on our review, we are of the opinion that the Yuma Project appears to be
operating in general compliance with applicable environmental permits,
approvals, laws, rules and regulations.
AIR PERMIT
The Yuma Project is currently operating under ADEQ Permit,
dated October 13, 1993, as revised via Minor Permit Revision, dated September
15, 1995. The Yuma Project has recently received a Draft Title V Operating
Permit which is scheduled for Public Comment notice on February 18, 1999. The
Public Comment
B-30
<PAGE>
period will expire by the end of March 1999, and a final permit is anticipated
to be issued by the end of April 1999. The Draft Title V Permit essentially
duplicates the original air permit, with all operating, emissions, monitoring
and recordkeeping requirements remaining the same as in the existing permit.
QF STATUS
The Yuma Project is required by the Yuma PPA to be a QF.
Actual operating results provided by the Yuma Operator indicate that the Yuma
Project is achieving average Operating Standards and Efficiency Standards
required for QF status as listed in Table 11.
TABLE 11
YUMA PROJECT QF STATISTICS
<TABLE>
<CAPTION>
OPERATING EFFICIENCY
YEAR STANDARD (%) STANDARD (%)
---- ------------ ------------
<S> <C> <C>
1998 13.4 46.5
1997 13.0 46.9
1996 10.9 46.5
1995 13.3 47.4
</TABLE>
WASTEWATER AND STORMWATER DISCHARGE PERMITS
Plant wastewater is discharged to the Bureau of Land
Reclamation's MODE under a permit with the Bureau of Land Reclamation, which
requires wastewater sampling and analysis to be performed every 6 months.
Documents reviewed containing the results of this ongoing sampling and analysis
indicate that the Yuma Project has been operating in compliance with its
wastewater discharge permit. The Yuma Project also has an evaporation pond which
serves as a backup in the event the MODE is unavailable for discharge due to
scheduled service requirements. The evaporation pond, which has never been used,
has an Aquifer Protection Permit from the ADEQ.
Sanitary wastes from the Yuma Project are discharged to the
City of Yuma publicly-owned treatment works in accordance with the City of Yuma
Conditional Approval, dated June 13, 1990.
The Yuma Project's stormwater is collected in a
retention/evaporation pond. Since the stormwater is not discharged to waters of
the United States, the stormwater system does not require a discharge permit.
GENERAL COMPLIANCE
Although we did not conduct a detailed environmental audit,
the following observations are based on our review of related documentation and
a site visit on January 28, 1999. In general, the Yuma Project appeared to be
using good housekeeping procedures and appropriate materials handling practices.
The SPCC Plan was up to date and covered the appropriate areas
expected to be addressed in this type of document for these types of plants.
There have been no reportable spills documented for the entire operating history
of the project.
The Yuma Project is classified as a Small Quantity Generator
of Hazardous Wastes under applicable regulations. The Yuma Project maintains a
log of all manifests for hazardous wastes shipped from the site. There were two
manifests in 1997; one for lab packs of expired chemicals; and one for 4,000
pounds of soil contaminated with sulfuric acid. There were no manifests for
1998.
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<PAGE>
A review of the Yuma Project documentation indicates that the
appropriate SARA Tier II Reports and notifications under EPCRA regarding
hazardous materials stored on-site have been submitted to the City of Yuma and
the other appropriate parties.
PROJECTED OPERATING RESULTS
We have reviewed the historical operating information,
estimates and projections of electrical generating capacity, steam generation
capacity, fuel consumption, and operating costs of the Yuma Project made
available to us. On the basis of such data, we have prepared the Projected
Operating Results. The Projected Operating Results are presented for each
calendar year beginning January 1, 1999, representing the beginning of the
quarterly distributions which will be available to CE Generation, through
December 31, 2018. Although the Securities have a final maturity of December 15,
2018, CE Generation has stated that a full year of revenues will be available to
pay the debt service on the Securities in 2018. Revenues for the Yuma Project
are derived primarily from the sale of electricity and steam. Expenses consist
of the cost of fuel, including transportation, as estimated by C.C. Pace, and
operating and maintenance expenses, based on information provided by CE
Generation. Projected sources of revenues and expenses have been set forth in
the Projected Operating Results presented in Exhibit B-1. The Projected
Operating Results are based on current contractual commitments as described
herein and have been prepared using assumptions and considerations set forth in
this Report and in the footnotes to Exhibit B-1.
ANNUAL OPERATING REVENUES
REVENUES FROM THE SALE OF ELECTRICITY
The Yuma Project sells capacity and energy to SDG&E under the
terms of the Yuma PPA. The term of the Yuma PPA is for 30 years from the firm
capacity operation date, and thus expires May 1, 2024. Under the Yuma PPA, the
Yuma Project sells 50 MW of firm capacity to SDG&E at the fixed (unescalated)
rate of $140.00 per kW-year. In addition, the Yuma Project is entitled to a
capacity bonus if it delivers firm capacity during the on-peak hours (11 a.m. to
6 p.m., weekdays) of the peak months (May to September) at a capacity factor of
85 percent or greater. Based on historical operating data and projections by CE
Generation, for the purposes of the Projected Operating Results, we have assumed
the on-peak availability factor to be 92 percent.
Under the terms of the Yuma PPA, SDG&E purchases energy at
their schedule of time-differentiated payments and conditions for purchase of
energy from QFs. These energy prices are derived from SDG&E's full avoided
operating costs. For the purpose of the Projected Operating Results, we have
assumed the energy prices projected by Henwood. Henwood has projected that
energy prices will be equal to SDG&E's short-run avoided costs in 1999 and 2000
and thereafter will be equal to the California Power Exchange ("PX") prices. It
should be noted that the prices projected by Henwood range from 1.3 percent to
17.4 percent higher than those projected by the California Energy Commission
("CEC"). On average, Henwood's projected PX prices are approximately 10 percent
higher than those projected by CEC.
Under Amendment Two to the Yuma PPA, SDG&E will accept up to
56.5 MW of energy from the Yuma Project. However, SDG&E has the option to
schedule a block curtailment of one 400 hour block or two 200 hour blocks with
not less then three weeks notice. In addition, in years one through nine of the
Yuma PPA, SDG&E may schedule up to 900 hours of flexible curtailment with at
least two hours notice. Each flexible curtailment period has a duration of no
less than eight consecutive hours, and the maximum number of these curtailments
in a calendar year is 125. In years 10 through 15 of the contract (i.e., May 1,
2004 to April 30, 2010), the number of flexible curtailment hours is increased
to 1,400 per year. After May 1, 2010, the flexible curtailment hours is
increased to 2,200 per year with the maximum number of curtailments increased to
150. For the purposes of the Projected Operating Results, we have assumed that
SDG&E schedules the maximum number of curtailment hours it is entitled to in any
year. Based on historical operating results and the amount of curtailment
allowed in the Yuma PPA, we have assumed energy delivered to SDG&E to be 387,400
MWh in years one to nine, 361,400 MWh in years 10 to 16, and 319,900 MWh
thereafter.
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<PAGE>
REVENUE FROM THE SALE OF STEAM
ABSORPTION CHILLER STEAM. The Yuma Project sells absorption
chiller steam to Queen Carpet under the terms of the Yuma Chiller ESA. The term
of the Yuma Chiller ESA is for 30 years from the firm capacity availability
date, and thus expires May 1, 2024. Under the Yuma Chiller ESA, the Yuma Project
delivers to Queen Carpet sufficient steam to operate their equipment, up to a
maximum of 35,000 pph. Chiller steam deliveries are not required when the Yuma
Project is curtailed or otherwise on outage. Based on CE Generation's 1998
budget, we have assumed the chiller steam deliveries to be 116,540,000 pounds
per year.
The Yuma Chiller ESA sets the purchase price of the chiller
steam at 60 percent of the equivalent cost to Queen Carpet of producing chilled
water at the electrical energy price per Arizona Public Service's ("APS") tariff
E-34. The chiller steam price is based on 60 percent of Queen Carpet's avoided
cost of operating its own chillers. Its avoided cost is calculated in the Yuma
Chiller ESA as the product of the assumed steam absorption chiller efficiency of
47.62 and the sum of the avoided electricity and operating and maintenance cost.
The electricity cost is calculated based on Queen Carpet's chiller efficiency
constant of 0.78 kW/ton-hour and APS's rate E-34, which was reported by CE
Generation to be $40.00 per MWh in 1998 and which we have assumed to escalate
with the PX price. Queen Carpet's avoided cost of operation and maintenance for
its chillers is defined as $0.0130 per ton in 1993 and adjusted each January 1
by the U.S City Average Consumers Price Index for All Urban Consumers ("CPI").
At the end of each year, Queen Carpet pays CE Generation a
true up amount in addition to the above purchase price. The true up steam is all
steam above the minimum thermal usage, defined in the Yuma Chiller ESA to be an
annual average during actual operation of 10,731 pph of steam delivered. The
true up steam price is 25 percent of the chiller steam price.
PROCESS STEAM. The Yuma Project sells process steam to Queen
Carpet under the terms of the Yuma Process ESA. The term of the Yuma Process ESA
is for 30 years from the firm capacity availability date, and thus expires May
1, 2024. Under the Yuma Process ESA, the Yuma Project delivers to Queen Carpet
sufficient steam to operate their equipment, up to a maximum of 15,000 pph.
Process steam deliveries are required when the Yuma Project is curtailed or
otherwise on outage. Such steam is produced in the standby boilers and is
referred to as supplemental steam. Based on projections prepared by CE
Generation, we have assumed the process steam deliveries to be 49,500 Mlb per
year (an average of 6,911 pph while operating), and the supplemental steam
deliveries to be 9,200 Mlb per year (an average of 5,735 pph while curtailed or
on outage).
The Yuma Process ESA sets the purchase price of the process
steam at 75 percent of net avoided cost to Queen Carpet of producing process
steam at the price of natural gas purchased from the nearest available gas
utility by an industrial customer. The process steam price is calculated as 75
percent of Queen Carpet's avoided cost of process steam. The avoided cost of
process steam is calculated as the sum of the nearest available gas utility
price of natural gas in dollars per MMBtu for large industrial users divided by
the efficiency of Queen Carpet's existing standby boilers of 63 percent and the
operation and maintenance costs of existing standby boilers, multiplied by the
difference in the enthalpy of the steam delivered and the condensate returned.
The cost of gas was reported by CE Generation to be $4.02 per MMBtu in 1998 and
has been assumed to escalate with the Yuma Project price of natural gas. The
operation and maintenance costs of existing standby boilers is set contractually
at $1.41 per Mlb of steam in 1992, adjusted each January 1 by the CPI. The
enthalpy of the steam delivered is estimated by CE Generation to be 1,197 Btu
per pound ("Btu/lb") and the condensate return is estimated to be zero.
The price paid for supplemental steam is the lesser of (i) CE
Generation's actual cost of producing the supplemental steam, or (ii) 100
percent of Queen Carpet's avoided cost of process steam, as described above.
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<PAGE>
ANNUAL OPERATING EXPENSES
FUEL COSTS
YCA has entered into a Gas Supply and Transportation Services
Master Agreement with SWG. The master agreement combines several earlier
agreements (including a supply agreement and a transportation agreement) into
one agreement with common terms and conditions. The primary term of the
agreement is to December 31, 2008, and continues year to year thereafter. The
maximum daily quantity under the agreement is 20,000 MMBtu per day.
Under the agreement, YCA pays a monthly service charge which
is currently $15,000 per month, and which we have assumed to escalate at half
the rate of inflation. The rate per MMBtu of the delivered gas is based on SWG's
average cost of gas plus $0.25 per MMBtu. For the purposes of our Projected
Operating Results, we have used the natural gas commodity prices as projected by
Henwood and reviewed by C.C. Pace and transportation cost as projected by C.C
Pace. We have also included use and sales taxes, which include county, state,
city, and Arizona energy assessment taxes, of 7.86 percent, as estimated by CE
Generation.
OPERATION AND MAINTENANCE EXPENSES
The operation and maintenance projections are derived from
historical data and 1999 projections provided by CE Generation. Operation and
maintenance expenses are assumed to escalate at the rate of general inflation.
The schedule of major maintenance expenses has been projected by CE Generation.
YCA has entered into a Firm Transmission Service Agreement
with APS and SDG&E dated February 4, 1993 (the "Yuma Firm Transmission Service
Agreement") for the transmission of 50.85 MW of electricity from the Yuma
Project to SDG&E. The wheeling cost is $1.52 per kW-month, unescalated. Under
the terms of the Yuma Firm Transmission Service Agreement, the Yuma Project
delivers one percent of the scheduled capacity and associated energy to APS as
reimbursement for electrical losses on APS' electric system. The term of the
Yuma Firm Transmission Service Agreement is from the initial operation date of
the Yuma Project through December 31, 2024.
YCA has also entered into an Interruptible Transmission
Service Agreement with APS dated June 15, 1994 (the "YCA Interruptible
Transmission Service Agreement") for the transmission of energy above the firm
transmission capacity. The wheeling cost is $2.082 per MWh, which does not
escalate. Under the terms of the YCA Interruptible Transmission Service
Agreement, the Yuma Project delivers one percent of the scheduled energy
delivered to APS as reimbursement for electrical losses on APS' electric system.
The term of the YCA Interruptible Transmission Service Agreement is concurrent
with the term of the YCA Firm Transmission Service Agreement.
OTHER EXPENSES
Other expenses, including operating fees, water, audit, legal,
finance, insurance, and property and other taxes, are as estimated by CE
Generation for 1999 and are assumed to escalate at the rate of general
inflation.
DISTRIBUTIONS TO CE GENERATION
CE Generation owns 100 percent of the Yuma Project and
therefore it has been assumed that 100 percent of the cash available for
distributions will be available to CE Generation.
NORCON PROJECT
The NorCon Project is a nominal 80 MW combined-cycle
cogeneration facility which began commercial operation in December, 1992. The
NorCon Project sells electric energy to Niagara Mohawk pursuant
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<PAGE>
to the NorCon PPA while selling process steam and chilled ammonia to Welch under
the NorCon Steam Agreement.
The NorCon Project consists of two natural gas-fired GE LM5000
CTGs exhausting to separate HRSGs. The HRSGs produce HP steam, which is sent to
either the CTG's combustors to control NOx emissions or to a single STG for
additional power generation; IP steam, which is used as process steam and STG
admission; and LP steam for use in the integral HRSG deaerators. Duct firing of
the HRSGs is provided to generate additional steam when needed.
PROJECT OPERATOR
The NorCon Project is operated under the NorCon O&M Agreement
by the NorCon Operator. The NorCon Operator commenced operation and maintenance
of its first combined-cycle cogeneration facility in 1987.
THE PROJECT
THE PROJECT SITE
The NorCon Project is located in the Township of North East
approximately 13 miles northeast of Erie, Pennsylvania (the "NorCon Project
Site") (see Figure B-4, NorCon Project Site Plan). The NorCon Project facilities
are located on 12.1 acres in an industrial zone adjacent to Welch property and
about 2.5 miles south of downtown North East.
ENVIRONMENTAL SITE CONDITIONS
We have reviewed two reports prepared by others for CE
Generation regarding the NorCon Project Site investigations at the subject
property including: (1) the Phase I Environmental Site Assessment (June 1991)
prepared by Hill Engineering for Northern Consolidated Power, Inc.; and (2) the
Phase I Environmental Site Assessment for NorCon Cogeneration Plant and Related
Properties (August 1996) prepared by Black & Veatch, Inc. ("Black & Veatch") for
CE Generation. These assessments identified prior NorCon Project Site uses
including agricultural/orchard production, a dairy farm, and a small portion of
the property previously used to store junked automobiles. The Hill Phase I ESA
identified "no obvious signs of conditions that would suggest the presence of
hazardous wastes at the site." Limited soil sampling by Hill did not identify
any concerns. Black & Veatch's Phase I ESA addressed the NorCon Project Site,
the ARP plant, a 3.84-acre parcel (currently in grape production) adjacent to
the plant site, and the 9.5-acre Ripley substation site located approximately
four miles to the east. Black & Veatch concluded that their investigation
"revealed no evidence of recognized environmental conditions in connection with
these properties."
In addition, we conducted a site reconnaissance of the NorCon
Project Site, the ARP site and the substation site on February 2, 1999. The
NorCon Project maintains a 4,200-gallon aboveground diesel fuel storage tank and
four 30,000-gallon propane tanks at the NorCon Project Site. We observed no
on-site spills, stains or other evidence of potential site contamination issues.
Further, we did not observe any off-site areas that would appear to present a
significant contamination potential to the NorCon Project. The NorCon Project is
not listed on any current state or federal database that typically list
contaminated sites or hazardous waste sites, including the National Priorities
List of Superfund Sites or the CERCLIS List dated January 26, 1999, prepared by
the USEPA and the Hazardous Sites Cleanup Act Site List dated November 3, 1998,
prepared by the Pennsylvania Department of Environmental Protection ("PDEP").
Further, there are no off-site areas documented on the above lists that would
have any impact upon the NorCon Project Site. The NorCon Operator stated that no
significant spills had ever occurred at the property, and that there are no soil
or groundwater monitoring requirements for the NorCon Project. This is
consistent with our review of files at the PDEP Regional Office on February 3,
1999 that did not identify any significant spills or potential site
contamination issues at the NorCon Project Site resulting from on-site
operations or off-site sources. In our opinion the likelihood of significant
contamination impacts to the subject property is extremely low.
B-35
<PAGE>
DESCRIPTION OF THE PROJECT
MECHANICAL EQUIPMENT AND SYSTEMS
The NorCon Project utilizes two GE LM5000 PC CTGs firing
natural gas. The CTGs were supplied by Stewart & Stevenson, Inc. and GE with all
auxiliary equipment required for an indoor installation. The electric generators
were manufactured by Brush and are air-cooled.
Each CTG exhausts to a dedicated Deltak three pressure level
HRSG with an integral deaerator and feedwater heater. Each HRSG incorporates a
natural gas-fired duct burner to supplement steam production when needed. The
NorCon Project delivers up to 151,000 pph of saturated steam at approximately
135 psig to Welch.
The Elliot STG is a single automatic extraction condensing
unit with a controlled automatic induction/extraction, capable of generating
9,850 kW at an HP inlet steam flow rate of 89,000 pph of 665 psia and
675(degree)F steam, an IP inlet steam flow rate of 61,000 pph of 100 psia,
385(degree)F steam, a process steam extraction of 32,500 pph of 190 psia steam,
and a back-pressure of 2.5 in. HgA.
The STG exhaust steam is condensed in an air-cooled condenser.
A high pressure (3,000 psi) water wash system has been added to reduce fouling
which improves heat transfer, reduces back-pressure on the STG and increases STG
output.
The NorCon Project also includes the 1,200-ton ARP supplied by
Babcock Borsig that uses process steam extracted from the STG to convert low
pressure ammonia vapor from the Welch plant into chilled pressurized ammonia
liquid which is returned to the plant. The ARP replaced a standard centrifugal
refrigeration system which is maintained by Welch in standby and used when the
ARP is out of service.
An auxiliary boiler and a natural gas compression station are
also included in the NorCon Project. The auxiliary boiler can be fired on either
natural gas or propane and is capable of meeting Welch's process steam load when
the CTGs are out of service. The gas compression station is composed of four
motor-driven gas compressors capable of increasing gas pressure from 300 psi to
the 650 psi required by the aeroderivative LM5000 CTGs.
ENVIRONMENTAL CONTROL SYSTEMS
The NorCon Project's air emission sources include two natural
gas-fired combustion turbines, two natural gas-fired duct burners, three
diesel-fired emergency generators, and one natural gas- or propane-fired
auxiliary boiler. A steam injection system in each gas turbine is used to
control emissions of NOx and an oxidation catalyst system is used to reduce
volatile organic compound ("VOC") and CO emissions. The NorCon Project is
required to maintain a continuous emissions monitoring system ("CEMS") for NOx
and CO emissions.
The NorCon Project generates wastewater from demineralization
backwash, boiler blowdown, cooling tower blowdown, plant floor washdowns, and
sanitary wastewaters. The ARP produces cooling tower blowdown. These wastewaters
are discharged to the publicly-owned treatment works owned by the North East
Borough Sewer Authority (the "POTW"). NorCon Project floor drains discharge to
an oil/water separator prior to discharge to the sewer system. The NorCon
Project's process wastewaters are pretreated for pH control prior to discharge.
Stormwater discharges from the cogeneration plant are directed to an on-site
settling basin prior to discharge to an unnamed tributary to Sixteen Mile Creek.
ELECTRICAL AND CONTROL SYSTEMS
The NorCon Project transports electricity to Niagara Mohawk
via a dedicated, 8 mile, 115 kV transmission line to a remote substation located
just over the state line in Ripley, New York, where voltage is increased to 230
kV and fed into Niagara Mohawk's system. The facility also includes a 13.8 kV
feed to the ARP
B-36
<PAGE>
FIGURE B-4
NORCON PROJECT
SITE PLAN
[Graphic Showing Site Plan of the NorCon Project Omitted]
B-37
<PAGE>
at Welch's plant.
The NorCon Project has two 900 kW diesel engine generators
that are capable of black-starting the facility. A 500 kW emergency diesel
generator is also included at the ARP. The NorCon Project also has a 125 volt dc
uninterruptible power supply ("UPS") system.
The two CTGs use a Woodward 501 control system. The plant has
a DCS supplied by Foxboro.
We have reviewed the Y2K Issue with the NorCon Operator. The
NorCon Operator reports that its Y2K compliance review is approximately 80
percent complete, including an extensive evaluation of all Y2K issues associated
with the NorCon Project. The NorCon Operator has contacted all relevant
equipment manufacturers and intends to update the DCS and controllers for the
ARP and STG. The NorCon operator is planning to perform the majority of Y2K
related modifications during the next scheduled major outage in August 1999. The
NorCon Project Y2K compliance program is scheduled to be completed by September
1999. For a description of the Y2K Issue and the scope of our review relative to
the Y2K Issue, please refer to the corresponding subsection of the PRI Project
section of this Report.
OFF-SITE FACILITIES
The NorCon Project includes the following off-site facilities:
an 8-mile, 115 kV power interconnection to Niagara Mohawk at a remote substation
in Ripley, New York; a 13.8 kV power feed to the APR, a process steam line and a
condensate return line between the NorCon Project Site and the Welch plant; a
natural gas distribution line that delivers 300 psi gas to the plant fence; and
North East Township raw water supply and wastewater discharge lines.
REVIEW OF TECHNOLOGY
The LM5000 CTGs used in the NorCon Project were first
introduced by GE in 1988. Several of GE's LM5000s installed since 1988 have
experienced problems that have resulted in extended unit forced outages.
According to the NorCon Operater, Unit No. 2 has experienced two separate blade
failures on the fourth stage of the HP compressor: one in January 1997 and
another in November 1998. However, since the NorCon Project has a lease engine
agreement with GE, the longest downtime due to these blade failures was nine
days. Due to these and other LM5000 CTG failures, GE has developed and highly
recommends an aggressive preventative maintenance program for all its LM5000 CTG
Users including taking each LM5000 off-line every six weeks for preventive
maintenance and adding an updated vibration monitoring system. The NorCon
Operator reported a reduction in spurious trips due to implementation of this
program.
Based on our discussions with the NorCon Operator, we are of
the opinion that the NorCon Project utilizes sound technology and proven methods
of electric and thermal generation and has generally been designed and
constructed in accordance with generally accepted industry practices. Further,
the NorCon Project has adequately provided for all off-site requirements,
including fuel, water supply, wastewater disposal and electrical
interconnections.
STATUS OF PERMITS AND APPROVALS
All of the major permits and approvals required to operate the
NorCon Project have been obtained. The NorCon Project's emissions are permitted
by a Title V Operating Permit issued by the PDEP on June 4, 1998. The Title V
Permit is the only operating air permit required and expires June 30, 2003.
Permitted air contaminants emitted from the NorCon Project include NOx, CO,
particulate matter 10 microns and larger ("PM-10"), SO2 and VOCs.
The NorCon Project's process wastewaters have been authorized
for discharge to the local sewer system by an Industrial Wastewater Discharge
Agreement ("IWDA") between NorCon and the POTW dated
B-38
<PAGE>
September 4, 1991. The NorCon Project has made application for renewal of the
IWDA with the Borough of North East. According to a representative of the
Borough, the new permit will reflect new permit limitations for zinc and copper
that are less restrictive than the current permit. According to the Borough
representative, the new permit is expected to be issued by April 9, 1999.
A list of key permits and approvals required for operation,
and a summary of their status, is provided in Table 12. This represents our
understanding based on a site visit on February 2, 1999, discussions with the
NorCon Operator, an on-site review of NorCon Project documents, and discussions
with the PDEP and North East Borough representatives.
TABLE 12
NORCON PROJECT
STATUS OF KEY PERMITS AND APPROVALS
<TABLE>
<CAPTION>
PERMIT OR APPROVAL RESPONSIBLE AGENCY STATUS COMMENTS
------------------ ------------------ ------ --------
<S> <C> <C> <C>
FEDERAL
QF Status FERC Refer to text
Stormwater Discharge Permit USEPA Issued January 12, 1998 In compliance. General
NPDES Permit for
stormwater discharges
STATE
Title V Operating Permit PDEP Issued June 4, 1998 In compliance
RACT Approval PDEP Issued: September 21, 1995 In compliance
LOCAL
Industrial Wastewater Discharge Borough of North Issued September 4, 1991 In compliance. Permit
Agreement Permit for discharge to East, Pennsylvania renewal anticipated to be
local sewer system issued by April 9, 1999.
</TABLE>
REGULATORY COMPLIANCE
The NorCon Project must be operated in accordance with all
applicable environmental permits, approvals, laws, rules and regulations. The
following describes our understanding of the status of the NorCon Project with
respect to regulatory compliance issues.
AIR PERMIT
Our review of NorCon Project and PDEP files and interviews
with the NorCon Operator and the PDEP indicate that the NorCon Project is in
compliance with its Title V Operating Permit. Our review of 1997-1998 emissions
data indicates that the NorCon Project has had occasional minor excursions of
permit limitations for excess NOx emissions during startup/shutdown and during
normal operations. Based on our discussions with the PDEP, the excursions are
insignificant and do not present a significant long-term environmental concern.
According to the NorCon Operator there have been no notices of violation
("NOVs") issued by the PDEP for these exceedances. The PDEP stated that the
NorCon Project has a good compliance record and expressed no concerns regarding
current NorCon Project management.
NOx RACT RULE
Title I of the Clean Air Act Amendments of 1990 requires state
regulatory agencies to implement Reasonably Available Control Technology
("RACT") to reduce ozone levels. The NorCon Project is located within an area
classified as a moderate nonattainment zone for ozone, since it is located
within the Ozone Transport
B-39
<PAGE>
Region. The NorCon Project is classified as a major stationary source for NOx
and CO emissions, thus RACT must be implemented to reduce NOx emissions. The
NorCon Project has received a RACT Approval, dated September 21, 1995.
NOx BUDGET RULE
In accordance with the September 27, 1994 Memorandum of
Understanding ("MOU") among Northeast Ozone Transport States, the PDEP
promulgated regulations to limit NOx emissions from fossil-fired units. These
regulations are designed to ensure that by May 1, 1999, affected facilities in
the "outer zone" (including the NorCon Project) must reduce their combined rate
of NOx emissions by 55 percent of the 1990 baseline or emit NOx at a rate no
greater than 0.20 pounds per MMBtu. Under the PDEP's current regulations,
beginning in 1999, each affected source must hold by December 31 of each year a
quantity of "NOx allowances" equal to or greater than the total NOx emitted from
the source during the "NOx allowance control period" (May 1 through September
30) for the year. The NorCon Project was allocated an initial allowance of 50
tons per unit. Our review of actual 1997 and 1998 NOx emissions data indicates
that the NorCon Project should meet its NOx emission limits during the
five-3month ozone transport period.
WASTEWATER AND STORMWATER DISCHARGES
Our review of NorCon Project files and interviews with NorCon
Project and North East Borough representatives indicates that the NorCon Project
is in compliance with its IWDA. Our review of 1997-1998 discharge monitoring
reports indicates that the NorCon Project has had occasional non-significant
exceedances of zinc, copper, and oil and grease, relative to permit limitations.
Most of these exceedances were for higher than permitted levels of zinc and
copper in the cooling tower blowdown at the ARP. A discussion with a Borough
representative indicates that the exceedances have not been a concern to the
POTW, and that new permit limitations are expected to become effective for zinc,
copper, and oil and grease when the IWDA renewal is issued in approximately
eight weeks. Our review of NorCon Project discharge monitoring reports indicates
that the NorCon Project would have met all discharge limitations if the
anticipated new permit limitations had been in effect during 1998. The NorCon
Operator stated they will be able to maintain compliance with the wastewater
discharge permit.
GENERAL COMPLIANCE
Although we did not conduct a detailed environmental audit,
the following observations are based on our review of related documentation, our
site visit conducted February 2, 1999, and interviews with the NorCon Operator.
In general, the NorCon Project appeared to be using good housekeeping practices
and appropriate handling procedures for fuels and hazardous chemicals. The
NorCon Operator indicated that no complaints had been received from the public
since construction and initial startup in the early 1990s. The NorCon Project is
registered as a small quantity generator of hazardous waste, and appears to be
in compliance with hazardous waste regulations.
The NorCon Project is aware of their obligations to prepare a
Risk Management Plan per Section 112-R of the Clean Air Act, summarizing the
NorCon Project's accidental release prevention program, and indicated that they
would meet the June 21, 1999 deadline for plan submittal.
PROJECTED OPERATING RESULTS
CE Generation has indicated that the estimated distributions
from the NorCon Project are immaterial in comparison to the total distributions
available to service the debt service associated with the Securities. Therefore,
for the purposes of this Report, we have assumed that no distributions from the
NorCon Project will be made to CE Generation during the term of the Securities.
B-40
<PAGE>
SUMMARY PROJECTED OPERATING RESULTS
DISTRIBUTIONS FROM THE NATURAL GAS PROJECTS
The distributions to CE Generation from the Natural Gas
Projects are presented for the terms of the respective power purchase agreements
in Exhibit B-1. It should be noted that the distributions to CE Generation from
the Natural Gas Projects are dependent primarily on the sale of electricity
under contracts with electric utilities. The Energy Policy Act fundamentally
changed the Federal regulation of the electric utility industry. At this time we
cannot predict what impact changes in legislation, regulation or market
conditions will have on the ability or willingness of the power purchasers to
pay the stipulated capacity costs contained in the Natural Gas Projects' power
purchase agreements. Accordingly, we have therefore assumed that the capacity
pricing provisions contained in the Natural Gas Projects' power purchase
agreements will remain effective throughout their respective terms. For further
discussion of the potential impact of the restructuring of the electric utility
industry on the projected electricity rates and CE Generation, please refer to
the section entitled "Regulatory Matters" contained in the Confidential Offering
Circular.
SENSITIVITY ANALYSES
Due to the uncertainties necessarily inherent in relying on
assumptions and projections, it should be anticipated that certain circumstances
and events may differ from those assumed and described herein and that such will
affect the results of our Base Case Projected Operating Results. In order to
demonstrate the impact of certain circumstances on the Base Case Projected
Operating Results, certain sensitivity analyses were developed. It should be
noted that other examples could have been considered and those presented are not
intended to reflect the full extent of possible impacts on the Natural Gas
Projects.
These sensitivity analyses, labeled as Sensitivity Case A
through I in Exhibits B-2 through B-10, present the Projected Operating Results
assuming, respectively, that (a) operating and maintenance expenses increase by
10 percent over that assumed in the Base Case Projected Operating Results; (b)
the fuel consumption of the Natural Gas Projects increases by 5 percent over
that assumed in the Base Case Projected Operating Results: (c) the
availabilities of the Natural Gas Projects are reduced by 5 percentage points
from that as assumed in the Base Case Projected Operating Results; (d) the
electricity prices and cost of fuel to the Yuma Project increase according to
the "Low Gas 1" case described in the Henwood Report; (e) the electricity prices
and cost of fuel to the Yuma Project increase according to the "Low Gas 2" case
described in the Henwood Report; (f) the electricity prices and cost of fuel to
the Yuma Project increase according to the "SCE Low SRAC" case described in the
Henwood Report; (g) the electricity prices and cost of fuel to the Yuma Project
increase according to the "SCE Median SRAC" case described in the Henwood
Report; (h) the electricity prices and cost of fuel to the Yuma Project increase
according to the "SCE High SRAC" case described in the Henwood Report; and (i)
the electricity prices to the Yuma Project are equal to the level sufficient to
maintain an annual debt service coverage of 1.00 in all years, as projected by
Fluor Daniel. Exhibits B-5 through B-10 contain only the Projected Operating
Results for the Yuma Project. Since the PRI and Saranac Projects are not
impacted by the change in assumptions for these sensitivity cases, the Projected
Operating Results for the PRI and Saranac Projects for these cases are the same
as the Base Case Projected Operating Results.
SUMMARY COMPARISON OF PROJECTED OPERATING RESULTS
The estimated distributions to CE Generation from the Natural
Gas Projects for selected fiscal years of operation for the Base Case and each
sensitivity case are presented in Table 13. The Base Case and each of the
sensitivity cases are presented in Exhibits B-1 through B-10.
B-41
<PAGE>
TABLE 13
PROJECTED NATURAL GAS PROJECT DISTRIBUTIONS
($000)
<TABLE>
<CAPTION>
YUMA
YUMA YUMA YUMA BREAKEVEN
INCREASED INCREASED REDUCED YUMA YUMA SCE LOW SCE MEDIAN SCE HIGH ELECTRICITY
YEAR BASE CASE O&M HEAT RATE AVAILABILITY LOW GAS 1 LOW GAS 2 SRAC SRAC SRAC PRICE
---- --------- --- --------- ------------ --------- --------- ------ ------ ------ -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1999 $40,079 $36,952 $36,430 $32,670 $40,079 $40,079 $39,268 $39,578 $40,702 $33,172
2000 44,620 41,010 40,488 32,778 44,908 44,862 44,274 44,700 46,172 39,961
2001 52,255 48,784 47,852 42,077 52,728 52,102 54,019 54,639 56,382 46,276
2002 55,693 52,147 51,144 45,199 55,232 54,433 55,639 56,298 58,390 47,867
2003 54,703 51,154 50,365 45,668 54,631 53,909 54,551 55,326 57,806 48,889
2004 46,080 43,575 42,811 32,612 46,250 45,670 45,720 46,659 49,298 38,304
2005 49,088 46,510 45,679 37,231 49,491 48,808 47,895 49,305 52,015 40,549
2010 6,948 6,454 6,410 6,326 6,869 6,775 6,684 8,539 13,977 233
2015 1,682 672 1,069 5,952 1,591 1,142 2,270 4,733 16,410 0
</TABLE>
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
USED IN THE PROJECTION OF OPERATING RESULTS
In the preparation of our Report and the opinions that follow,
we have made certain assumptions with respect to conditions that may exist or
events that may occur in the future. While we believe these assumptions to be
reasonable for the purpose 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. While we believe the use of such information and
assumptions to be reasonable for the purposes of our Report, we offer no other
assurances with respect thereto and some assumptions may vary significantly due
to unanticipated events and circumstances. To the extent that 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 based upon the extent of such changes.
The principal considerations and assumptions made by us in
developing the input to the Projected Operating Results 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 Natural Gas Projects and their operations.
However, for purposes of this Report, we have assumed that all such
contracts, agreements, rules, and regulations will be fully enforceable
in accordance with their terms and that all parties will comply with
the provisions of their respective agreements.
2. Our review of the design of the Natural Gas Projects was
based on information provided by CE Generation and our visual
observations during our site visits.
3. The operators will maintain the Natural Gas Projects in
accordance with good engineering practice, will perform all required
major maintenance in a timely manner, and will not operate the
equipment to cause it to exceed the equipment manufacturers'
recommended maximum ratings.
4. The operators will employ qualified and competent personnel
and will generally operate the Natural Gas Projects in a sound and
businesslike manner.
B-42
<PAGE>
5. The Natural Gas Projects will identify and implement
solutions to the Y2K Problem in a manner which will not impact the
projected net revenues of the Natural Gas Projects.
6. Inspections, overhauls, repairs and modifications are
planned for and conducted in accordance with manufacturers'
recommendations, and with special regard for the need to monitor
certain operating parameters to identify early signs of potential
problems.
7. Proposed restructuring of the electric utility industry
will not significantly impact the projected electricity revenues of the
PRI, Saranac, and Yuma Projects.
8. All licenses, permits and approvals, and permit
modifications necessary to operate the Natural Gas Projects have been,
or will be, obtained on a timely basis and any changes in required
licenses, or permits and approvals will not require reduced operation
of, or increased costs to, the Natural Gas Projects.
9. The CPI and general inflation, used variously to escalate
various revenues and expenses, will increase at an average annual rate
of 2.7 percent.
10. The performance of the PRI, Saranac, and Yuma Projects
will be as assumed in the Projected Operating Results.
11. The price of electricity and natural gas for the Yuma
Project will be as estimated by Henwood.
12. The cost of natural gas to the PRI and Saranac Projects
and the cost of natural gas transportation of the Yuma Project will be
as estimated by C.C. Pace. The Yuma natural gas contracts will be
extended at pricing provision equal to the current agreements through
the term of the Securities.
13. The steam sales to the various steam hosts will be as
assumed in the Projected Operating Results.
14. The non-fuel operating and maintenance expenses, including
the cost of major maintenance, will be consistent with the information
provided by CE Generation, and will increase thereafter at the assumed
change in the general inflation rate, except as noted otherwise in this
Report.
15. The senior debt service requirements and interest income
of the PRI and Saranac Projects will be as reported by CE Generation.
16. There will be no additional capital improvements to the
PRI, Saranac, and Yuma Projects other than those assumed in the
Projected Operating Results.
17. The will be no distributions made to CE Generation from
the Natural Gas Projects after the expiration of the respective power
purchase agreements.
18. There will be no distributions made to CE Generation from
the NorCon Project.
19. A full year of revenues from the Yuma Project will be
available to pay the debt service on the Securities in 2018, as
estimated by CE Generation.
CONCLUSIONS
Set forth below are the principal opinions we have reached
after our review of the Natural Gas Projects. For a complete understanding of
the estimates, assumptions, and calculations upon which these opinions
B-43
<PAGE>
are based, the Report should be read in its entirety. On the basis of our review
and analyses of the Natural Gas Projects and the assumptions set forth in this
Report, we are of the opinion that:
1. The operators of the Natural Gas Projects have demonstrated
the ability to discharge their responsibilities under the respective
O&M agreements.
2. The Natural Gas Project sites are suitable for the
operation of the Natural Gas Projects.
3. The Natural Gas Projects utilize sound technology and
proven methods of electric and thermal generation and have generally
been designed and constructed in accordance with generally accepted
industry practices.
4. The Natural Gas Projects adequately provide for all
off-site requirements, including fuel, water supply, wastewater
disposal and electrical interconnections.
5. The PRI, Saranac, and Yuma Projects possess sufficient
contract or access to spot natural gas commodity supply to meet the
requirements of the respective power purchase agreements and the
contracted natural gas transportation capacity for these projects is
adequate to deliver the natural gas supply requirements.
6. If the PRI, Saranac, and Yuma Projects are operated and
maintained consistent with generally accepted industry practices, these
projects should be capable of meeting the requirements of their
respective power purchase agreements, current environmental permits
and, where applicable, steam sales agreements, throughout the term of
the respective power purchase agreements.
7. If the operators operate the PRI, Saranac, and Yuma
Projects in accordance with generally accepted industry practices,
these projects should have useful lives extending through the final
maturity of the Securities.
8. All of the major permits and approvals required to operate
the Natural Gas Projects have been or are currently in the process of
being obtained. While most operating permits must be renewed
periodically, we know of no technical reason that such renewals would
not be obtainable.
9. Based on the historical performance, operation and
maintenance practices and observed conditions of the PRI, Saranac, and
Yuma Projects, these projects should be capable of achieving the
average annual availabilities, net electrical capabilities, capacity
factors, steam supply requirements and heat rates assumed in the
Projected Operating Results.
10. The operation and maintenance procedures and practices at
the PRI, Saranac, and Yuma Projects are consistent with good
engineering practices and generally accepted industry practices and
take into consideration existing environmental and permit requirements
applicable to these projects. The operators' organizational structures
for these projects are comparable to other facilities using similar
technologies with which we are familiar.
11. The Natural Gas Projects appear to be operating in general
compliance with applicable environmental permits, approvals, laws,
rules and regulations.
12. The basis for the estimates provided by CE Generation of
the costs of operating and maintaining the PRI, Saranac, and Yuma
Projects, including the cost of major maintenance, is reasonable.
Respectfully submitted,
/S/ R. W. BECK, INC.
B-44
<PAGE>
[THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY]
B-45
<PAGE>
Exhibit B-1
CE Generation Gas Projects
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003(1)
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
PRI PROJECT
PERFORMANCE
Contract Capacity (kW)(2) 200,000 200,000 200,000 200,000 200,000
Capacity Factor (%)(3) 80.0% 80.0% 80.0% 80.0% 80.0%
Energy Sales (MWh) 1,401,600 1,401,600 1,401,600 1,401,600 1,051,200
Steam Sales (Mlb)(4) 830,000 830,000 830,000 830,000 830,000
Heat Rate (Btu/Wh)(5) 9,500 9,500 9,500 9,500 9,500
Fuel Consumption (BBtu)(6) 13,315 13,315 13,315 13,315 9,986
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(8) $194.88 201.72 208.80 216.00 223.56
Energy Component
Tier 1 Energy Price ($/MWh)(9) $31.70 32.80 34.00 35.20 36.40
Tier 2 Energy Price ($/MWh)(9) $24.82 25.06 25.52 25.98 26.79
Steam Price ($/Mlb)(10) $2.85 2.90 2.96 3.02 3.08
Natural Gas Price ($/MMBtu)(11) $2.892 2.968 3.050 3.135 3.227
Gas Transportation Cost ($/MMBtu)(12) $0.102 0.102 0.102 0.102 0.102
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $38,976 40,344 41,760 43,200 33,534
Energy $41,779 42,989 44,386 45,783 35,485
Steam Revenue $2,363 2,410 2,459 2,508 2,558
Interest Income (13) $380 385 392 396 289
---------- ---------- ---------- ---------- ----------
Total Operating Revenues $83,498 86,128 88,997 91,887 71,866
OPERATING EXPENSES ($000)(14)
Fuel Expense $38,510 39,525 40,618 41,741 32,230
Fuel Transportation Expense $1,360 1,360 1,360 1,360 1,020
Auxiliary Fuel $48 30 30 30 23
Operator's Fee $1,171 1,204 1,237 1,272 981
Plant Operations $3,131 3,216 3,302 3,392 2,612
Major Maintenance $3,337 3,427 3,520 3,615 2,784
Other O&M $904 1,014 1,087 1,142 882
Insurance $347 380 405 412 326
Administrative Fees $886 144 148 152 117
Property Taxes $1,387 1,387 1,387 1,387 1,040
Capital Expenditures $1,409 1,002 715 516 351
---------- ---------- ---------- ---------- ----------
Total Operating Expenses $52,490 52,689 53,809 55,019 42,366
NET OPERATING REVENUES ($000) $31,008 33,439 35,188 36,868 29,500
SENIOR DEBT SERVICE (15)
Balance Outstanding (Jan 1) $90,529 76,261 60,174 42,055 21,743
Principal $14,268 16,088 18,119 20,313 21,743
Interest $8,044 8,561 6,940 4,989 1,459
---------- ---------- ---------- ---------- ----------
Total Senior Debt Service $21,561 23,381 23,796 23,975 23,188
Payments into Debt Reserve Fund $85 128 67 (183) (6,014)
Debt Service Reserve Fund Balance (16) $6,002 6,130 6,196 6,014 0
Major Maintenance Reserve Fund Balance (17) $1,000 1,000 1,000 1,000 1,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $9,362 9,930 11,325 13,076 12,326
DISTRIBUTIONS TO
CE GENERATION ($000)(18) $9,362 9,930 11,325 13,076 12,326
</TABLE>
B-46
<PAGE>
Exhibit B-1
CE Generation Gas Projects
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 177,900 177,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 713,000 713,000
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550 8,550
Fuel Consumption (BBtu)(26) 15,466 15,466 15,466 15,466 15,466 15,466
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) $76.91 80.50 83.76 87.02 90.28 94.51
Energy Price ($/MWh)(28) $68.03 70.96 74.04 77.30 80.81 84.27
Steam Price ($/Mlb)(29) $3.16 3.29 3.42 3.56 3.70 3.85
Natural Gas Price ($/MMBtu)(30) $2.760 2.906 3.057 3.215 3.378 3.548
Gas Transportation Cost ($/MMBtu)(31) $0.977 0.978 0.978 0.979 0.979 0.980
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $18,459 19,320 20,102 20,884 21,666 22,683
Energy $134,438 140,243 146,328 152,777 159,713 166,545
Steam Revenue $2,256 2,346 2,440 2,538 2,639 2,745
Interest Income (32) $385 385 385 385 385 385
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $155,538 162,294 169,255 176,584 184,403 192,358
OPERATING EXPENSES ($000)(33)
Fuel Expense $42,691 44,942 47,282 49,716 52,248 54,880
Fuel Transportation Expense $15,110 15,120 15,129 15,138 15,146 15,156
Operation & Maintenance $2,376 2,488 2,605 2,727 2,855 2,989
Operator's Fee $2,100 2,157 2,215 2,275 2,336 2,399
Repair & Maintenance $5,930 6,090 6,255 6,424 6,597 6,775
Water & Chemicals $386 396 407 418 429 441
Consumables $476 489 502 516 530 544
State Excise Tax on Steam Revenues (34) $79 82 85 89 92 96
Insurance $767 788 809 831 853 876
Administrative & General $975 1,001 1,028 1,056 1,084 1,114
Property Taxes $3,016 3,016 3,016 3,016 3,016 3,016
Wheeling Charges (35) $5,424 5,695 5,980 6,279 6,593 6,923
Letter-of-Credit Fees $275 282 289 297 304 312
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $79,605 82,546 85,602 88,782 92,083 95,521
NET OPERATING REVENUES ($000) $75,933 79,748 83,653 87,802 92,320 96,837
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) $189,282 181,097 170,047 156,951 141,399 122,573
Principal $8,185 11,050 13,096 15,552 18,826 22,100
Interest $15,242 14,484 13,516 12,369 10,996 9,354
--------- --------- --------- --------- --------- ---------
Total Senior Debt Service $23,427 25,534 26,612 27,921 29,822 31,454
Payments into Base Reserve Fund $0 0 0 0 0 0
Base Reserve Fund Balance (37) $7,000 7,000 7,000 7,000 7,000 7,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $75,933 79,748 83,653 87,802 92,320 96,837
DISTRIBUTIONS TO OTHER PARTNERS (38) $52,123 49,717 48,703 53,011 55,757 58,533
DISTRIBUTIONS TO
CE GENERATION ($000)(38) $23,810 30,031 34,951 34,791 36,563 38,304
<CAPTION>
Year Ending December 31, 2005 2006 2007 2008 2009(1)
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 899,200
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 88,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 356,600
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550
Fuel Consumption(BBtu)(26) 15,466 15,466 15,466 15,466 7,733
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) 97.77 101.68 106.57 110.48 115.38
Energy Price ($/MWh)(28) 88.06 91.91 95.91 100.17 104.59
Steam Price ($/Mlb)(29) 4.00 4.16 4.33 4.50 4.68
Natural Gas Price ($/MMBtu)(30) 3.725 3.910 4.101 4.300 4.472
Gas Transportation Cost ($/MMBtu)(31) 0.981 0.981 0.982 0.982 0.971
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity 23,465 24,404 25,577 26,516 13,845
Energy 174,035 181,647 189,550 197,973 103,343
Steam Revenue 2,855 2,969 3,088 3,211 1,670
Interest Income (32) 385 385 385 385 0
--------- --------- --------- --------- ---------
Total Operating Revenues 200,740 209,405 218,600 228,085 118,858
OPERATING EXPENSES ($000)(33)
Fuel Expense 57,618 60,465 63,427 66,506 34,579
Fuel Transportation Expense 15,165 15,175 15,184 15,193 7,511
Operation & Maintenance 3,130 3,277 3,431 3,592 1,881
Operator's Fee 2,464 2,531 2,599 2,669 1,371
Repair & Maintenance 6,958 7,146 7,339 7,537 3,870
Water & Chemicals 453 465 478 491 252
Consumables 559 574 589 605 311
State Excise Tax on Steam Revenues (34) 100 104 108 112 58
Insurance 900 924 949 975 501
Administrative & General 1,144 1,175 1,206 1,239 636
Property Taxes 3,016 3,016 3,016 3,016 1,508
Wheeling Charges (35) 7,269 7,632 8,014 8,415 4,418
Letter-of-Credit Fees 321 330 339 179 0
--------- --------- --------- --------- ---------
Total Operating Expenses 99,097 102,814 106,679 110,529 56,896
NET OPERATING REVENUES ($000) 101,643 106,591 111,921 117,556 61,962
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) 100,473 74,281 43,177 8,799 0
Principal 26,193 31,104 34,378 8,799 0
Interest 7,420 5,125 2,479 180 0
--------- --------- --------- --------- ---------
Total Senior Debt Service 33,613 36,229 36,857 8,979 0
Payments into Base Reserve Fund 0 0 0 (7,000) 0
Base Reserve Fund Balance (37) 7,000 7,000 7,000 0 0
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 101,643 106,591 111,921 124,556 61,962
DISTRIBUTIONS TO OTHER PARTNERS (38) 61,094 65,066 71,316 75,494 18,744
DISTRIBUTIONS TO
CE GENERATION ($000)(38) 40,549 41,525 40,605 49,062 43,219
</TABLE>
B-47
<PAGE>
Exhibit B-1
CE Generation Gas Projects
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003 2004
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92
Energy ($/MWh)(50) $30.90 31.70 28.16 33.99 35.23 36.82
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84
Chilling Steam Price ($/Mlb)(52) $1.32 1.33 1.34 1.54 1.59 1.65
True-up Steam Price ($/Mlb)(52) $0.33 0.33 0.34 0.38 0.40 0.41
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,971 12,281 10,909 13,168 13,648 13,307
Steam Revenue
Process Steam $387 397 407 418 428 410
Supplemental Steam $96 98 101 103 106 141
Chilling Steam $154 155 156 179 185 179
True-up Steam $13 13 13 15 16 15
-------- -------- -------- -------- -------- --------
Total Operating Revenues $20,817 21,140 19,782 22,079 22,579 22,248
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723
Natural Gas Service Fees (55) $182 185 187 190 192 195
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557
Major Maintenance (57) $183 3,278 193 198 2,262 209
Other Operating Fees/Water (56) $443 455 467 480 493 506
Audit, Legal & Finance (56) $762 12 13 13 13 14
Insurance (56) $157 161 166 170 175 179
Property & Other Taxes (56) $779 800 822 844 867 890
Capital Expenditures (56) $179 9 6 23 40 40
Wheeling (58) $963 963 963 963 963 961
-------- -------- -------- -------- -------- --------
Total Operating Expenses $13,910 16,481 13,803 14,253 16,765 14,472
NET OPERATING REVENUES ($000) $6,907 4,659 5,979 7,826 5,814 7,776
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,907 4,659 5,979 7,826 5,814 7,776
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,907 4,659 5,979 7,826 5,814 7,776
<CAPTION>
Year Ending December 31, 2005 2006 2007 2008 2009
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92 163.92
Energy ($/MWh)(50) 40.09 39.91 40.19 43.05 42.04
Process Steam Price ($/Mlb)(51) 9.11 9.35 9.63 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 12.15 12.47 12.84 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 1.77 1.78 1.80 1.90 1.89
True-up Steam Price ($/Mlb)(52) 0.44 0.44 0.45 0.48 0.47
Natural Gas Price ($/MMBtu)(53) 2.67 2.77 2.89 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196 1,196
Energy Payment 14,489 14,423 14,525 15,558 15,193
Steam Revenue
Process Steam 421 432 445 455 467
Supplemental Steam 145 148 153 156 160
Chilling Steam 192 193 195 207 205
True-up Steam 16 16 17 18 17
-------- -------- -------- -------- --------
Total Operating Revenues 23,459 23,408 23,531 24,590 24,238
OPERATING EXPENSES ($000)
Natural Gas 9,526 9,864 10,283 10,579 10,952
Natural Gas Use/Sales Taxes (54) 749 775 808 831 861
Natural Gas Service Fees (55) 198 200 203 206 209
Operating & Maintenance (56) 1,599 1,642 1,687 1,732 1,779
Major Maintenance (57) 215 0 3,950 233 239
Other Operating Fees/Water (56) 520 534 548 563 578
Audit, Legal & Finance (56) 14 14 15 I5 16
Insurance (56) 184 189 194 200 205
Property & Other Taxes (56) 914 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40 40
Wheeling (58) 961 961 961 961 961
-------- -------- -------- -------- --------
Total Operating Expenses 14,920 15,158 19,653 16,350 16.857
NET OPERATING REVENUES ($000) 8,539 8,250 3,878 8,240 7,381
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 8,539 8,250 3,878 8,240 7,381
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 8,539 8,250 3,878 8,240 7,381
</TABLE>
B-48
<PAGE>
Exhibit B-1
CE Generation Gas Projects
Projected Operating Results
Base Case
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014 2015
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $43.48 43.48 43.26 45.70 45.89 47.57
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45
Chilling Steam price ($/Mlb)(52) $1.95 1.96 1.97 2.06 2.09 2.16
True-up Steam Price ($/Mlb)(52) $0.49 0.49 0.49 0.52 0.52 0.54
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $13,909 13,909 13,839 14,619 14,680 15,218
Steam Revenue
Process Steam $425 436 448 460 473 474
Supplemental Steam $226 232 238 244 251 252
Chilling Stream $187 189 190 199 201 207
True-up Steam $16 16 16 17 17 18
-------- -------- -------- -------- -------- --------
Total Operating Revenues $22,959 22,978 22,927 23,735 23,818 24,365
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616 11,457
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913 900
Natural Gas Service Fees (55) $211 214 217 220 223 226
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033 2,087
Major Maintenance (57) $245 2,799 259 266 0 4,887
Other Operating Fees/Water (56) $594 610 626 643 661 678
Audit, Legal & Finance (56) $16 17 17 17 18 18
Insurance (56) $210 216 222 228 234 240
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162 1,193
Capital Expenditures (56) $40 40 40 40 40 40
Wheeling (58) $957 957 957 957 957 957
-------- -------- -------- -------- -------- --------
Total Operating Expenses $16,011 19,060 17,033 17,571 l7,857 22,683
NET OPERATING REVENUES ($000) $6,948 3,918 5,894 6,164 5,961 1,682
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,948 3,918 5,894 6,164 5,961 1,682
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,948 3,918 5,894 6,164 5,961 1,682
<CAPTION>
Year Ending December 31 2016 2017 2018
-------- -------- --------
<S> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 47.79 49.16 50.31
Process Steam Price ($/Mlb)(51) 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) 16.26 16.71 17.15
Chilling Steam price ($/Mlb)(52) 2.18 2.24 2.30
True-up Steam Price ($/Mlb)(52) 0.55 0.56 0.57
Natural Gas Price ($/MMBtu)(53) 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196
Energy Payment 15,288 15,726 16,094
Steam Revenue
Process Steam 499 512 526
Supplemental Steam 265 272 280
Chilling Stream 210 216 221
True-up Steam 18 18 19
-------- -------- --------
Total Operating Revenues 24,476 24,940 25,336
OPERATING EXPENSES ($000)
Natural Gas 12,468 12,915 13,351
Natural Gas Use/Sales Taxes(54) 980 1,015 1,049
Natural Gas Service Fees (55) 229 232 235
Operating & Maintenance (56) 2,144 2,202 2,261
Major Maintenance (57) 288 296 304
Other Operating Fees/Water (56) 697 716 735
Audit, Legal & Finance (56) 19 19 20
Insurance (56) 247 254 260
Property & Other Taxes (56) 1,225 1,258 1,292
Capital Expenditures (56) 40 40 40
Wheeling (58) 957 957 957
-------- -------- --------
Total Operating Expenses 19,294 19,904 20,504
NET OPERATING REVENUES ($000) 5,182 5,036 4,832
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 5,182 5,036 4,832
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 5,182 5,036 4,832
</TABLE>
B-49
<PAGE>
Footnotes to Exhibit B-1
1. Represents twelve months for 1999, representing the beginning of the
quarterly distributions which will be available to CE Generation, and 12
months for 2018, except for the PRI Project and the Saranac Project, for
which no distributions are assumed after the expiration of the PRI PPA and
Saranac PPA on September 30, 2003 and June 30, 2009, respectively.
Although the Securities have a final maturity of December 15, 2018, CE
Generation has stated that a full year of revenues will be available to
pay the debt service on the Securities in 2018.
2. Net plant capacity of 200,000 kW as set forth in the PPI PPA.
3. Capacity factor based on an assumed dispatch factor of 100 percent less
the contractually allowed curtailment during the term of the PRI PPA.
4. Based on the historic level of steam sales to Fina at 830,000 Mlb per
year.
5. As estimated by R.W. Beck based on the historic level of net plant heat
rate.
6. Includes fuel based on the average annual heat rate.
7. Based on projections prepared by Blue Chip Economic Indicators dated
October 10, 1998.
8. Capacity rate as set forth in the PRI PPA.
9. As set forth in the PRI PPA, the energy rate for energy produced monthly
above a 72.5 percent capacity factor is equal to the product of TUEC's
monthly weighted average cost of gas, as estimated by C.C. Pace, the
monthly energy produced above a 72.5 percent capacity factor and 0.99.
Below a 72.5 percent capacity factor, the energy pricing is as set forth
in the PRI PPA.
10. Fina steam price is $2.45 per Mlb of steam beginning in 1991 and escalated
each June 1 beginning June 1, 1992 at 2.0 percent per contract year
thereafter pursuant to the PRI Steam Sales Agreement.
11. As projected by C.C. Pace in accordance with the PRI Gas Supply Agreement.
The reservation fee is equal to $547,500 per year beginning July 1, 1989
and escalates at 3 percent beginning on July 1, 1996. The fuel prices
under the Louis Dreyfus Gas Contract change each June 1. Spot gas pricing
has been projected by C.C. Pace.
12. As set forth in the PRI Gas Supply Agreement.
13. Estimated based on the debt service reserve fund and major maintenance
reserve fund balances required under the Amended and Restated Term Loan
Agreement dated December 30, 1988 and a reinvestment rate of 5.5 percent,
as estimated by CE Generation.
14. Based on information provided by CE Generation. Non-fuel operating
expenses assumed to escalate at the rate of general inflation.
15. As set forth in the PRI Amended and Restated Term Loan Agreement provided
by CE Generation.
16. The debt service reserve fund balance is to be maintained at the next
quarter's debt service payment pursuant to the PRI Amended and Restated
Term Loan Agreement.
17. The maintenance reserve account maintains a $1,000,000 balance in
accordance with the PRI operating budget for periodic overhauls, repairs
and spare parts.
18. One hundred percent of cash available for distribution is distributed to
CE Generation.
19. Net plant capacity of 240,000 kW as set forth in the Saranac PPA.
20. As estimated by R.W. Beck.
21. Capacity factor based on an assumed dispatch factor of 100 percent less
certain contractually allowed curtailment during the term of the Saranac
PPA.
22. Calculated as set forth in the Saranac PPA.
23. Based on the historical energy curtailment by NYSEG under the Saranac PPA.
24. Based on historic level of steam sales. Assumes 520,300 Mlb per year of
steam sales to Georgia-Pacific and 192,700 Mlb per year of steam sales to
Tenneco.
25. As estimated by R.W. Beck.
26. Includes generation fuel based on an average annual beat rate and
auxiliary boiler fuel at a rate of 1,400 Btu/lb of steam.
27. As set forth in the Saranac PPA, capacity rate is equal to the weighted
average of the schedule of on-peak and off-peak variable capacity prices
based on on-peak hours of 3,810 and 4,950 hours per year, respectively.
28. As set forth in the Saranac PPA, energy rate is equal to the weighted
average of the schedule of on-peak and off-peak variable energy prices.
Scheduled pricing based on a commercial operation date of May 1994.
Includes available generation revenue calculated as variable energy rate
plus variable capacity component less 95 percent of the lesser of (1) 105
percent of sum of the variable energy rate plus the variable capacity
component, or (2) the price of natural gas times the estimated heat rate
times the available generation.
29. Represents average steam price under Georgia-Pacific and Tenneco Steam
Sales Agreements. Average steam price is equal to $3.04 per Mlb in 1998
escalated at 4.0 percent per year thereafter.
30. As set forth in the Saranac Gas Arrangements, natural gas price is equal
to a contract price of $2.97 per MMBtu through October 31, 1994 and
escalating by 4.0 percent each November 1 thereafter. Demand component is
based on TransCanada's firm transportation rate and the contract quantity
based on a 100 percent load factor. Commodity charge is the remaining
portion of the contract price and is assessed only for actual fuel burned.
31. As set forth in the Saranac Gas Transportation Agreements.
32. Estimated based on the debt service reserve fund and major maintenance
reserve fund balances and a reinvestment rate of 5 percent, as estimated
by CE Generation.
33. Based on information provided by CE Generation. Non-fuel operating
expenses assumed to escalate at the rate of general inflation, except
where noted.
34. Equal to 3.5 percent of annual steam revenue.
B-50
<PAGE>
Footnotes to Exhibit B-1
(Continued)
35. As set forth in the Saranac PPA, equal to $4,250,000 per year in 1994
dollars escalated at 5.0 percent per year.
36. Based on information provided by CE Generation. Not deducted from cash
available for distributions since senior debt service is paid out of level
1 distributions.
37. As required under senior credit agreement. Based on information provided
by CE Generation.
38. Based on distributions to GE Capital equal to 99 percent of scheduled
level 1 distributions and 1 percent of level 2 distributions and
distributions to TPC Saranac equal to 0.3585 percent of scheduled level 1
distributions plus of 35.49 percent of level 2 distributions until an
after-tax return of 8.35 percent is achieved. After achieving an 8.35
after-tax return, which is projected in the Base Case to occur in the
first quarter of 2000, TPC Saranac's share is reduced from 35.49 to 17.82
percent. CE Generation receives all remaining level 1 and level 2
distributions.
39. Maximum energy deliverable to SDG&E under the Yuma PPA.
40. Contracted firm capacity under the Yuma PPA.
41. Curtailment hours assumed at contract maximums and consist of a block
curtailment of 400 hours plus 900 hours of flexible curtailment through
May 1, 2004, 1,400 hours of flexible curtailment from May 1, 2004 through
May 1, 2009, and 2,200 hours of flexible curtailment each year thereafter.
42. Estimated by R.W. Beck based on historical operating data.
43. Estimated by R.W. Beck based on historical operating data. Peak hours
under the Yuma PPA are defined as 11 A.M. to 6 P.M. weekdays, May through
September.
44. Based on contracted firm capacity.
45. Pursuant to transmission agreements with APS, losses are equal to one
percent of scheduled capacity and associated energy.
46. As estimated by CE Generation.
47. Includes auxiliary boiler.
48. Pursuant to the Yuma PPA.
49. Pursuant to the Yuma PPA. Assumes 92 percent on-peak availability and one
percent losses from the point of delivery to the designated point of
interconnection with SDG&E.
50. As estimated by Henwood.
51. As estimated by C.C. Pace.
52. Calculated pursuant to the Yuma Process ESA. Supplemental steam is steam
produced in the auxiliary boiler.
53. Calculated pursuant to Yuma Chiller ESA. True-up steam is steam in excess
of an annual average of 10,721 pounds per hour.
54. Gas use and sales taxes assumed to be equal to 7.86 percent of gas
expenses, as estimated by CE Generation.
55. SWG special gas procurement tariff is $15,000 per month in 1998, as
provided by CE Generation. Assumed by R.W. Beck to escalate at one half
the general rate of inflation.
56. Estimated for 1999 by CE Generation and assumed to escalate at the assumed
rate of general inflation of 2.7 percent per year thereafter.
57. Major maintenance schedule as estimated by CE Generation.
58. Includes firm and interruptible transmission costs based on firm
transmission service charge of $1.52 per kW-month, and interruptible
transmission service charge of $2.082 per MWh, unescalated pursuant to
transmission agreements with APS.
59. One hundred percent of cash available for distribution is distributed to
CE Generation.
B-51
<PAGE>
Exhibit B-2
CE Generation Gas Projects
Projected Operating Results
Sensitivity A: Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003(1)
---------- --------- --------- ---------- ----------
<S> <C> <C> <C> <C> <C>
PRI PROJECT
PERFORMANCE
Contract Capacity (kW)(2) 200,000 200,000 200,000 200,000 200,000
Capacity Factor (%)(3) 80.0% 80.0% 80.0% 80.0% 80.0%
Energy Sales (MWh) 1,401,600 1,401,600 1,401,600 1,401,600 1,051,200
Steam Sales (Mlb)(4) 830,000 830,000 830,000 830,000 830,000
Heat Rate (Btu/kWh)(5) 9,500 9,500 9,500 9,500 9,500
Fuel Consumption (BBtu)(6) 13,315 13,315 13,315 13,315 9,986
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(8) $194.88 201.72 208.80 216.00 223.56
Energy Component
Tier 1 Energy Price ($/MWh)(9) $31.70 32.80 34.00 35.20 36.40
Tier 2 Energy Price ($/MWh)(9) $24.82 25.06 25.52 25.98 26.79
Steam Price ($/Mlb)(10) $2.85 2.90 2.96 3.02 3.08
Natural Gas Price ($/MMBtu)(11) $2.892 2.968 3.050 3.135 3.227
Gas Transportation Cost ($/MMBtu)(12) $0.102 0.102 0.102 0.102 0.102
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $38,976 40,344 41,760 43,200 33,534
Energy $41,779 42,989 44,386 45,783 35,485
Steam Revenue $2,363 2,410 2,459 2,508 2,558
Interest Income (13) $380 385 392 396 289
---------- --------- --------- ---------- ----------
Total Operating Revenues $83,498 86,128 88,997 91,887 71,866
OPERATING EXPENSES ($000)(14)
Fuel Expense $38,510 39,525 40,618 41,741 32,230
Fuel Transportation Expense $1,360 1,360 1,360 1,360 1,020
Auxiliary Fuel $48 30 30 30 23
Operator's Fee $1,288 1,324 1,361 1,399 1,079
Plant Operations $3,444 3,537 3,633 3,731 2,874
Major Maintenance $3,671 3,770 3,872 3,976 3,063
Other O&M $994 1,115 1,196 1,256 970
Insurance $382 418 446 453 358
Administrative Fees $975 158 163 167 129
Property Taxes $1,526 1,526 1,526 1,526 1,144
Capital Expenditures $1,550 1,102 787 568 386
---------- --------- --------- ---------- ----------
Total Operating Expenses $53,748 53,865 54,992 56,207 43,276
NET OPERATING REVENUES ($000) $29,750 32,263 34,005 35,680 28,590
SENIOR DEBT SERVICE (15)
Balance Outstanding (Jan 1) $90,529 76,261 60,174 42,055 21,743
Principal $14,268 16,088 18,119 20,313 21,743
Interest $8,044 8,561 6,940 4,989 1,459
---------- --------- --------- ---------- ----------
Total Senior Debt Service $21,561 23,381 23,796 23,975 23,188
Payments into Debt Reserve Fund $85 128 67 (183) (6,014)
Debt Service Reserve Fund Balance (16) $6,002 6,130 6,196 6,014 0
Major Maintenance Reserve Fund Balance (17) $1,000 1,000 1,000 1,000 1,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $8,104 8,754 10,142 11,888 11,416
DISTRIBUTIONS TO
CE GENERATION ($000)(18) $8,104 8,754 10,142 11,888 11,416
</TABLE>
B-52
<PAGE>
Exhibit B-2
CE Generation Gas Projects
Projected Operating Results
Sensitivity A: Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 177,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 713,000
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550
Fuel Consumption (BBtu)(26) 15,466 15,466 15,466 15,466 15,466
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) $76.91 80.50 83.76 87.02 90.28
Energy Price ($/MWh)(28) $68.03 70.96 74.04 77.30 80.81
Steam Price ($/Mlb)(29) $3.16 3.29 3.42 3.56 3.70
Natural Gas Price ($/MMBtu)(30) $2.760 2.906 3.057 3.215 3.378
Gas Transportation Cost ($/MMBtu)(31) $0.977 0.978 0.978 0.979 0.979
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $18,459 19,320 20,102 20,884 21,666
Energy $134,438 140,243 146,328 152,777 159,713
Steam Revenue $2,256 2,346 2,440 2,538 2,639
Interest Income (32) $385 385 385 385 385
---------- ---------- ---------- ---------- ----------
Total Operating Revenues $155,538 162,294 169,255 176,584 184,403
OPERATING EXPENSES ($000)(33)
Fuel Expense $42,691 44,942 47,282 49,716 52,248
Fuel Transportation Expense $15,110 15,120 15,129 15,138 15,146
Operation & Maintenance $2,614 2,737 2,865 3,000 3,141
Operator's Fee $2,310 2,372 2,436 2,502 2,570
Repair & Maintenance $6,523 6,699 6,880 7,066 7,257
Water & Chemicals $425 436 448 460 472
Consumables $524 538 552 567 582
State Excise Tax on Steam Revenues (34) $87 90 94 98 102
Insurance $844 867 890 914 939
Administrative & General $1,072 1,101 1,131 1,162 1,193
Property Taxes $3,318 3,318 3,318 3,318 3,318
Wheeling Charges (35) $5,967 6,265 6,578 6,907 7,252
Letter-of-Credit Fees $303 310 318 326 335
---------- ---------- ---------- ---------- ----------
Total Operating Expenses $81,788 84,795 87,92l 91,174 94,555
NET OPERATING REVENUES ($000) $73,750 77,499 81,334 85,410 89,848
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) $189,282 181,097 170,047 156,951 141,399
Principal $8,185 11,050 13,096 15,552 18,826
Interest $15,242 14,484 13,516 12,369 10,996
---------- ---------- ---------- ---------- ----------
Total Senior Debt Service $23,427 25,534 26,612 27,921 29,822
Payments into Base Reserve Fund $0 0 0 0 0
Base Reserve Fund Balance (37) $7,000 7,000 7,000 7,000 7,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $73,750 77,499 81,334 85,410 89,848
DISTRIBUTIONS TO OTHER PARTNERS (38) $51,327 49,195 48,266 52,561 55,292
DISTRIBUTIONS TO
CE GENERATION ($000)(38) $22,424 28,305 33,068 32,849 34,556
<CAPTION>
Year Ending December 31, 2004 2005 2006 2007 2008 2009(1)
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400 899,200
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 177,900 88,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 713,000 356,600
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550 8,550
Fuel Consumption (BBtu)(26) 15,466 15,466 15,466 15,466 15,466 7,733
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) 94.51 97.77 101.68 106.57 110.48 115.38
Energy Price ($/MWh)(28) 84.27 88.06 91.91 95.91 100.17 104.59
Steam Price ($/Mlb)(29) 3.85 4.00 4.16 4.33 4.50 4.68
Natural Gas Price ($/MMBtu)(30) 3.548 3.725 3.910 4.101 4.300 4.472
Gas Transportation Cost ($/MMBtu)(31) 0.980 0.981 0.981 0.982 0.982 0.971
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity 22,683 23,465 24,404 25,577 26,516 13,845
Energy 166,545 174,035 181,647 189,550 197,973 103,343
Steam Revenue 2,745 2,855 2,969 3,088 3,211 1,670
Interest Income (32) 385 385 385 385 385 0
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues 192,358 200,740 209,405 218,600 228,085 118,858
OPERATING EXPENSES ($000)(33)
Fuel Expense 54,880 57,618 60,465 63,427 66,506 34,579
Fuel Transportation Expense 15,156 15,165 15,175 15,184 15,193 7,511
Operation & Maintenance 3,288 3,443 3,605 3,774 3,952 2,069
Operator's Fee 2,639 2,710 2,784 2,859 2,936 1,508
Repair & Maintenance 7,453 7,654 7,861 8,073 8,291 4,257
Water & Chemicals 485 498 512 525 540 277
Consumables 598 614 631 648 665 342
State Excise Tax on Steam Revenues (34) 106 110 114 119 124 64
Insurance 964 990 1,017 1,044 1,073 551
Administrative & General 1,225 1,258 1,292 1,327 1,363 700
Property Taxes 3,318 3,318 3,318 3,318 3,318 1,659
Wheeling Charges (35) 7,615 7,996 8,396 8,815 9,256 4,859
Letter-of-Credit Fees 344 353 363 373 197 0
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses 98,071 101,727 105,533 109,486 113,414 58,376
NET OPERATING REVENUES ($000) 94,287 99,013 103,872 109,114 114,671 60,482
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) 122,573 100,473 74,281 43,177 8,799 0
Principal 22,100 26,193 31,104 34,378 8,799 0
Interest 9,354 7,420 5,125 2,479 180 0
---------- ---------- ---------- ---------- ---------- ----------
Total Senior Debt Service 31,454 33,613 36,229 36,857 8,979 0
Payments into Base Reserve Fund 0 0 0 0 (7,000) 0
Base Reserve Fund Balance (37) 7,000 7,000 7,000 7,000 0 0
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 94,287 99,013 103,872 109,114 121,671 60,482
DISTRIBUTIONS TO OTHER PARTNERS (38) 58,053 60,599 64,554 70,788 74,951 18,465
DISTRIBUTIONS TO
CE GENERATION ($000)(38) 36,234 38,414 39,318 38,326 46,720 42,017
</TABLE>
B-53
<PAGE>
Exhibit B-2
CE Generation Gas Projects
Projected Operating Results
Sensitivity A: Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003 2004 2005
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Capacity Price ($/kW-yr)(48)
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $30.90 31.70 28.16 33.99 35.23 36.82 40.09
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15
Chilling Steam Price ($/Mlb)(52) $1.32 1.33 1.34 1.54 1.59 1.65 1.77
True-up Steam Price ($/Mlb)(52) $0.33 0.33 0.34 0.38 0.40 0.41 0.44
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,971 12,281 10,909 13,168 13,648 13,307 14,489
Steam Revenue
Process Steam $387 397 407 418 428 410 421
Supplement Steam $96 98 101 103 106 141 145
Chilling Steam $154 155 156 179 185 179 192
True-up Steam $13 13 13 15 16 15 16
-------- -------- -------- -------- -------- -------- --------
Total Operating Revenues $20,817 21,140 19,782 22,079 22,579 22,248 23,459
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198 9,526
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723 749
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,499 1,540 1,581 1,624 1,668 1,713 1,759
Major Maintenance (57) $201 3,606 212 218 2,488 230 237
Other Operating Fees/Water (56) $487 500 514 528 542 557 572
Audit, Legal & Finance (56) $838 l4 14 14 15 15 15
Insurance (56) $173 177 182 187 192 197 203
Property & Other Taxes (56) $857 880 904 928 953 979 1,005
Capital Expenditures (56) $197 10 7 25 44 44 44
Wheeling (58) $1,059 1,059 1,059 1,059 1,059 1,056 1,056
-------- -------- -------- -------- -------- -------- --------
Total Operating Expenses $14,392 17,189 14,208 14,669 17,397 14,907 15,364
NET OPERATING REVENUES ($000) $6,425 3,951 5,574 7,410 5,182 7,341 8,096
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,425 3,951 5,574 7,410 5,182 7,341 8,096
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,425 3,951 5,574 7,410 5,182 7,341 8,096
<CAPTION>
Year Ending December 31, 2006 2007 2008 2009
-------- -------- -------- --------
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price 140.00 140.00 140.00 140.00
Capacity Price ($/kW-yr)(48)
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 39.91 40.19 43.05 42.04
Process Steam Price ($/Mlb)(51) 9.35 9.63 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 12.47 12.84 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 1.78 1.80 1.90 1.89
True-up Steam Price ($/Mlb)(52) 0.44 0.45 0.48 0.47
Natural Gas Price ($/MMBtu)(53) 2.77 2.89 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 14,423 14,525 15,558 15,193
Steam Revenue
Process Steam 432 445 455 467
Supplement Steam 148 153 156 160
Chilling Steam 193 195 207 205
True-up Steam 16 17 18 17
-------- -------- -------- --------
Total Operating Revenues 23,408 23,531 24,590 24,238
OPERATING EXPENSES ($000)
Natural Gas 9,864 10,283 10,579 10,952
Natural Gas Use/Sales Taxes (54) 775 808 831 861
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,807 1,855 1,906 1,957
Major Maintenance (57) 0 4,345 256 263
Other Operating Fees/Water (56) 587 603 619 636
Audit, Legal & Finance (56) 16 16 17 17
Insurance (56) 208 214 219 225
Property & Other Taxes (56) 1,033 1,060 1,089 1,118
Capital Expenditures (56) 44 44 44 44
Wheeling (58) 1,056 1,056 1,056 1,056
-------- -------- -------- --------
Total Operating Expenses 15,590 20,487 16,822 17,338
NET OPERATING REVENUES ($000) 7,818 3,044 7,768 6,900
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 7,818 3,044 7,768 6,900
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 7,818 3,044 7,768 6,900
</TABLE>
B-54
<PAGE>
Exhibit B-2
CE Generation Gas Projects
Projected Operating Results
Sensitivity A: Increased Operating Expenses
<TABLE>
<CAPTION>
Year Ending December 31, 2010 2011 2012 2013 2014 2015 2016
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $43.48 43.48 43.26 45.70 45.89 47.57 47.79
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59 12.20
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45 16.26
Chilling Steam Price($/Mlb)(52) $1.95 1.96 1.97 2.06 2.09 2.16 2.18
True-up Steam Price ($/Mlb)(52) $0.49 0.49 0.49 0.52 0.52 0.54 0.55
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62 3.97
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35 0.36
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $13,909 13,909 13,839 14,619 14,680 15,218 15,288
Steam Revenue
Process Steam $425 436 448 460 473 474 499
Supplemental Steam $226 232 238 244 251 252 265
Chilling Stream $187 189 190 199 201 207 210
True-up Steam $16 16 16 17 17 18 18
-------- -------- -------- -------- -------- -------- --------
Total Operating Revenues $22,959 22,978 22,927 23,735 23,818 24,365 24,476
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616 11,457 12,468
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913 900 980
Natural Gas Service Fees (55) $211 214 217 220 223 226 229
Operating & Maintenance (56) $2,010 2,064 2,120 2,177 2,236 2,296 2,358
Major Maintenance (57) $270 3,079 285 293 0 5,376 317
Other Operating Fees/Water (56) $653 671 689 708 727 746 766
Audit, Legal & Finance (56) $18 18 19 19 20 20 21
Insurance (56) $232 238 244 251 258 264 272
Property & Other Taxes (56) $1,149 1,180 1,212 1,244 1,278 1,312 1,348
Capital Expenditures (56) $44 44 44 44 44 44 44
Wheeling (58) $1,052 1,052 1,052 1,052 1,052 1,052 1,052
-------- -------- -------- -------- -------- -------- --------
Total Operating Expenses $16,506 19,819 17,549 18,098 18,367 23,693 19,855
NET OPERATING REVENUES ($000) $6,454 3,159 5,378 5,637 5,451 672 4,621
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,454 3,159 5,378 5,637 5,451 672 4,621
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,454 3,159 5,378 5,637 5,451 672 4,621
<CAPTION>
Year Ending December 31, 2017 2018
-------- --------
<S> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000
Curtailment Hours (41) 2,600 2,600
Availability Factor (42) 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200
Energy Delivered (MWh) 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92
Energy Rate ($/MWh)(50) 49.16 50.31
Process Steam Price ($/Mlb)(51) 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) 16.71 17.15
Chilling Steam Price($/Mlb)(52) 2.24 2.30
True-up Steam Price ($/Mlb)(52) 0.56 0.57
Natural Gas Price ($/MMBtu)(53) 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000
Bonus Capacity Payment 1,196 1,196
Energy Payment 15,726 16,094
Steam Revenue
Process Steam 512 526
Supplemental Steam 272 280
Chilling Stream 216 221
True-up Steam 18 19
-------- --------
Total Operating Revenues 24,940 25,336
OPERATING EXPENSES ($000)
Natural Gas 12,915 13,351
Natural Gas Use/Sales Taxes (54) 1,015 1,049
Natural Gas Service Fees (55) 232 235
Operating & Maintenance (56) 2,422 2,487
Major Maintenance (57) 326 334
Other Operating Fees/Water (56) 787 808
Audit, Legal & Finance (56) 21 22
Insurance (56) 279 287
Property & Other Taxes (56) 1,384 1,422
Capital Expenditures (56) 44 44
Wheeling (58) 1,052 1,052
-------- --------
Total Operating Expenses 20,477 21,091
NET OPERATING REVENUES ($000) 4,463 4,245
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 4,463 4,245
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 4,463 4,245
</TABLE>
B-55
<PAGE>
Footnotes to Exhibit B-2
The footnotes to Exhibit B-2 are the same as the footnotes for Exhibit
B-1, except:
14. All non-fuel related operating costs are assumed to be 10 percent higher
than that assumed in the Base Case.
33. All non-fuel related operating costs are assumed to be 10 percent higher
than that assumed in the Base Case.
56. All non-fuel related operating costs are assumed to be 10 percent higher
than that assumed in the Base Case.
B-56
<PAGE>
Exhibit B-3
CE Generation Gas Projects
Projected Operating Results
Sensitivity B: Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003(1)
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
PRI PROJECT
PERFORMANCE
Contract Capacity (kW)(2) 200,000 200,000 200,000 200,000 200,000
Capacity Factor (%)(3) 80.0% 80.0% 80.0% 80.0% 80.0%
Energy Sales (MWh) 1,401,600 1,401,600 1,401,600 1,401,600 1,051,200
Steam Sales (Mlb)(4) 830,000 830,000 830,000 830,000 830,000
Heat Rate (Btu/kWh)(5) 9,975 9,975 9,975 9,975 9,975
Fuel Consumption (BBtu)(6) 13,981 13,981 13,981 13,981 10,486
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(8) $194.88 201.72 208.80 216.00 223.56
Energy Component
Tier 1 Energy Price ($/MWh)(9) $31.70 32.80 34.00 35.20 36.40
Tier 2 Energy Price ($/MWh)(9) $24.82 25.06 25.52 25.98 26.79
Steam Price ($/Mlb)(10) $2.85 2.90 2.96 3.02 3.08
Natural Gas Price ($/MMBtu)(11) $2.852 2.926 3.005 3.087 3.179
Gas Transportation Cost ($/MMBtu)(12) $0.104 0.104 0.104 0.104 0.104
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $38,976 40,344 41,760 43,200 33,534
Energy $41,779 42,989 44,386 45,783 35,485
Steam Revenue $2,363 2,410 2,459 2,508 2,558
Interest Income (13) $380 385 392 396 289
---------- ---------- ---------- ---------- ----------
Total Operating Revenues $83,498 86,128 88,997 91,887 71,866
OPERATING EXPENSES ($000)(14)
Fuel Expense $39,877 40,902 42,017 43,163 33,331
Fuel Transportation Expense $1,449 1,449 1,449 1,449 1,087
Auxiliary Fuel $48 30 30 30 23
Operator's Fee $1,171 1,204 1,237 1,272 981
Plant Operations $3,131 3,216 3,302 3,392 2,612
Major Maintenance $3,337 3,427 3,520 3,615 2,784
Other O&M $904 1,014 1,087 1,142 882
Insurance $347 380 405 412 326
Administrative Fees $886 144 148 152 117
Property Taxes $1,387 1,387 1,387 1,387 1,040
Capital Expenditures $1,409 1,002 715 516 351
---------- ---------- ---------- ---------- ----------
Total Operating Expenses $53,946 54,155 55,297 56,530 43,534
NET OPERATING REVENUES ($000) $29,552 31,973 33,700 35,357 28,332
SENIOR DEBT SERVICE (15)
Balance Outstanding (Jan 1) $90,529 76,261 60,174 42,055 21,743
Principal $14,268 16,088 18,119 20,313 21,743
Interest $8,044 8,561 6,940 4,989 1,459
---------- ---------- ---------- ---------- ----------
Total Senior Debt Service $21,561 23,381 23,796 23,975 23,188
Payments into Debt Reserve Fund $85 128 67 (183) (6,014)
Debt Service Reserve Fund Balance (16) $6,002 6,130 6,196 6,014 0
Major Maintenance Reserve
Fund Balance (17) $1,000 1,000 1,000 1,000 1,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $7,906 8,464 9,837 11,565 11,158
DISTRIBUTIONS TO
CE GENERATION ($000)(18) $7,906 8,464 9,837 11,565 11,158
</TABLE>
B-57
<PAGE>
Exhibit B-3
CE Generation Gas Projects
Projected Operating Results
Sensitivity B: Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004
---------- ---------- ---------- ---------- ---------- ----------
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400 1,798,400
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 177,900 177,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 713,000 713,000
Heart Rate (Btu/kWh)(25) 8,978 8,978 8,978 8,978 8,978 8,978
Fuel Consumption (BBtu)(26) 16,236 16,236 16,236 16,236 16,236 16,236
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) $76.91 80.50 83.76 87.02 90.28 94.51
Energy Price ($/MWh)(28) $67.92 70.86 73.93 77.19 80.69 84.14
Steam Price ($/Mlb)(29) $3.16 3.29 3.42 3.56 3.70 3.85
Natural Gas Price ($/MMBtu)(30) $2.760 2.906 3.057 3.215 3.378 3.548
Gas Transportation Cost ($/MMBtu)(31) $0.957 0.958 0.958 0.959 0.959 0.960
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $18,459 19,320 20,102 20,884 21,666 22,683
Energy $134,239 140,033 146,106 152,546 159,468 166,288
Steam Revenue $2,256 2,346 2,440 2,538 2,639 2,745
Interest Income (32) $385 385 385 385 385 385
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $155,339 162,084 169,033 176,353 184,158 192,101
OPERATING EXPENSES ($000)(33)
Fuel Expense $44,816 47,178 49,635 52,190 54,848 57,611
Fuel Transportation Expense $15,540 15,550 15,559 15,568 15,576 15,586
Operation & Maintenance $2,376 2,488 2,605 2,727 2,855 2,989
Operator's Fee $2,100 2,157 2,215 2,275 2,336 2,399
Repair & Maintenance $5,930 6,090 6,255 6,424 6,597 6,775
Water & Chemicals $386 396 407 418 429 441
Consumables $476 489 502 516 530 544
State Excise Tax on Steam Revenues (34) $79 82 85 89 92 96
Insurance $767 788 809 831 853 876
Administrative & General $975 1,001 1,028 1,056 1,084 1,114
Property Taxes $3,016 3,016 3,016 3,016 3,016 3,016
Wheeling Charges (35) $5,424 5,695 5,980 6,279 6,593 6,923
Letter-of-Credit Fees $275 282 289 297 304 312
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $82,160 85,212 88,385 91,686 95,113 98,682
NET OPERATING REVENUES ($000) $73,179 76,872 80,648 84,667 89,045 93,419
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) $189,282 181,097 170,047 156,951 141,399 122,573
Principal $8,185 11,050 13,096 15,552 18,826 22,100
Interest $15,242 14,484 13,516 12,369 10,996 9,354
---------- ---------- ---------- ---------- ---------- ----------
Total Senior Debt Service $23,427 25,534 26,612 27,921 29,822 31,454
Payments into Base Reserve Fund $0 0 0 0 0 0
Base Reserve Fund Balance (37) $7,000 7,000 7,000 7,000 7,000 7,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $73,179 76,872 80,648 84,667 89,045 93,419
DISTRIBUTIONS TO OTHER PARTNERS (38) $51,118 49,049 48,137 52,421 55,141 57,890
DISTRIBUTIONS TO
CE GENERATION ($000)(38) $22,061 27,824 32,511 32,246 33,904 35,530
<CAPTION>
Year Ending December 31 2005 2006 2007 2008 2009(1)
---------- ---------- ---------- ---------- --------
<S> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 94.00% 94.00% 94.00% 94.00% 94.00%
Capacity Factor (%)(21) 85.54% 85.54% 85.54% 85.54% 85.54%
Energy Sales (MWh)(22) 1,798,400 1,798,400 1,798,400 1,798,400 899,200
Available Generation (MWh)(23) 177,900 177,900 177,900 177,900 88,900
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 356,600
Heart Rate (Btu/kWh)(25) 8,978 8,978 8,978 8,978 8,978
Fuel Consumption (BBtu)(26) 16,236 16,236 16,236 16,236 8,118
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) 97.77 101.68 106.57 110.48 115.38
Energy Price ($/MWh)(28) 87.92 91.77 95.76 100.02 104.42
Steam Price ($/Mlb)(29) 4.00 4.16 4.33 4.50 4.68
Natural Gas Price ($/MMBtu)(30) 3.725 3.910 4.101 4.300 4.472
Gas Transportation Cost ($/MMBtu)(31) 0.961 0.961 0.962 0.962 0.952
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity 23,465 24,404 25,577 26,516 13,845
Energy 173,765 181,365 189,253 197,662 103,182
Steam Revenue 2,855 2,969 3,088 3,211 1,670
Interest Income (32) 385 385 385 385 0
---------- ---------- ---------- ---------- --------
Total Operating Revenues 200,470 209,123 218,303 227,774 118,697
OPERATING EXPENSES ($000)(33)
Fuel Expense 60,485 63,474 66,583 69,816 36,299
Fuel Transportation Expense 15,595 15,605 15,614 15,623 7,726
Operation & Maintenance 3,130 3,277 3,431 3,592 1,881
Operator's Fee 2,464 2,531 2,599 2,669 1,371
Repair & Maintenance 6,958 7,146 7,339 7,537 3,870
Water & Chemicals 453 465 478 491 252
Consumables 559 574 589 605 311
State Excise Tax on Steam Revenues (34) 100 104 108 112 58
Insurance 900 924 949 975 501
Administrative & General 1,144 1,175 1,206 1,239 636
Property Taxes 3,016 3,016 3,016 3,016 1,508
Wheeling Charges (35) 7,269 7,632 8,014 8,415 4,418
Letter-of-Credit Fees 321 330 339 179 0
---------- ---------- ---------- ---------- --------
Total Operating Expenses 102,394 106,253 110,265 114,269 58,831
NET OPERATING REVENUES ($000) 98,076 102,870 108,038 113,505 59,866
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) 100,473 74,281 43,177 8,799 0
Principal 26,193 31,104 34,378 8,799 0
Interest 7,420 5,125 2,479 180 0
---------- ---------- ---------- ---------- --------
Total Senior Debt Service 33,613 36,229 36,857 8,979 0
Payments into Base Reserve Fund 0 0 0 (7,000) 0
Base Reserve Fund Balance (37) 7,000 7,000 7,000 0 0
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 98,076 102,870 108,038 120,505 59,866
DISTRIBUTIONS TO OTHER PARTNERS (38) 60,422 64,366 70,586 74,731 18,349
DISTRIBUTIONS TO
CE GENERATION ($000)(38) 37,653 38,505 37,453 45,774 41,516
</TABLE>
B-58
<PAGE>
Exhibit B-3
CE Generation Gas Projects
Projected Operating Results
Sensitivity B: Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005
-------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 9,272 9,272 9,272 9,272 9,272 9,272 9,272
Fuel Consumption (BBtu)(47) 3,647 3,647 3,647 3,647 3,647 3,410 3,410
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $30.90 31.70 28.16 33.99 35.23 36.82 40.09
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15
Chilling Steam Price ($/Mlb)(52) $1.32 1.33 1.34 1.54 1.59 1.65 1.77
True-up Steam Price ($/Mlb)(52) $0.33 0.33 0.34 0.38 0.40 0.41 0.44
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,971 12,281 10,909 13,168 13,648 13,307 14,489
Steam Revenue
Process Steam $387 397 407 418 428 410 421
Supplemental Steam $96 98 101 103 106 141 145
Chilling Steam $154 155 156 179 185 179 192
True-up Steam $13 13 13 15 16 15 16
-------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $20,817 21,140 19,782 22,079 22,579 22,248 23,459
OPERATING EXPENSES ($000)
Natural Gas $8,662 8,972 9,293 9,632 9,971 9,657 10,002
Natural Gas Use/Sales Taxes (54) $681 705 730 757 784 759 786
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599
Major Maintenance (57) $183 3,278 193 198 2,262 209 215
Other Operating Fees/Water (56) $443 455 467 480 493 506 520
Audit, Legal & Finance (56) $762 12 13 13 13 14 14
Insurance (56) $157 161 166 170 175 179 184
Property & Other Taxes (56) $779 800 822 844 867 890 914
Capital Expenditures (56) $179 9 6 23 40 40 40
Wheeling (58) $963 963 963 963 963 961 961
-------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $14,354 16,940 14,278 14,746 17,276 14,967 15,433
NET OPERATING REVENUES ($000) $6,463 4,200 5,504 7,333 5,303 7,281 8,026
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,463 4,200 5,504 7,333 5,303 7,281 8,026
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,463 4,200 5,504 7,333 5,303 7,281 8,026
<CAPTION>
Year Ending December 31 2006 2007 2008 2009
-------- ------- ------- -------
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 9,272 9,272 9,272 9,272
Fuel Consumption (BBtu)(47) 3,410 3,410 3,410 3,410
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 39.91 40.19 43.05 42.04
Process Steam Price ($/Mlb)(51) 9.35 9.63 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 12.47 12.84 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 1.78 1.80 1.90 1.89
True-up Steam Price ($/Mlb)(52) 0.44 0.45 0.48 0.47
Natural Gas Price ($/MMBtu)(53) 2.77 2.89 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 14,423 14,525 15,558 15,193
Steam Revenue
Process Steam 432 445 455 467
Supplemental Steam 148 153 156 160
Chilling Steam 193 195 207 205
True-up Steam 16 17 18 17
-------- ------- ------- -------
Total Operating Revenues 23,408 23,531 24,590 24,238
OPERATING EXPENSES ($000)
Natural Gas 10,356 10,796 11,106 11,499
Natural Gas Use/Sales Taxes (54) 814 848 873 904
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,642 1,687 1,732 1,779
Major Maintenance (57) 0 3,950 233 239
Other Operating Fees/Water (56) 534 548 563 578
Audit, Legal & Finance (56) 14 15 15 16
Insurance (56) 189 194 200 205
Property & Other Taxes (56) 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 961 961 961 961
-------- ------- ------- -------
Total Operating Expenses 15,689 20,206 16,919 17,447
NET OPERATING REVENUES ($000) 7,719 3,325 7,671 6,791
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 7,719 3,325 7,671 6,791
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 7,719 3,325 7,671 6,791
</TABLE>
B-59
<PAGE>
Exhibit B-3
CE Generation Gas Projects
Projected Operating Results
Sensitivity B: Increased Heat Rate
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014 2015 2016
-------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 9,272 9,272 9,272 9,272 9,272 9,272 9,272
Fuel Consumption (BBtu)(47) 3,029 3,029 3,029 3,029 3,029 3,029 3,029
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $43.48 43.48 43.26 45.70 45.89 47.57 47.79
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59 12.20
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45 16.26
Chilling Steam Price ($/Mlb)(52) $1.95 1.96 1.97 2.06 2.09 2.16 2.18
True-up Steam Price ($/Mlb)(52) $0.49 0.49 0.49 0.52 0.52 0.54 0.55
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62 3.97
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35 0.36
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $13,909 13,909 13,839 14,619 14,680 15,218 15,288
Steam Revenue
Process Steam $425 436 448 460 473 474 499
Supplemental Steam $226 232 238 244 251 252 265
Chilling Steam $187 189 190 199 201 207 210
True-up Steam $16 16 16 17 17 18 18
-------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $22,959 22,978 22,927 23,735 23,818 24,365 24,476
OPERATING EXPENSES ($000)
Natural Gas $10,574 10,956 11,353 11,765 12,192 12,025 13,085
Natural Gas Use/Sales Taxes (54) $831 861 892 925 958 945 1,028
Natural Gas Service Fees (55) $211 214 217 220 223 226 229
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033 2,087 2,144
Major Maintenance (57) $245 2,799 259 266 0 4,887 288
Other Operating Fees/Water (56) $594 610 626 643 661 678 697
Audit, Legal & Finance (56) $16 17 17 17 18 18 19
Insurance (56) $210 216 222 228 234 240 247
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162 1,193 1,225
Capital Expenditures (56) $40 40 40 40 40 40 40
Wheeling (58) $957 957 957 957 957 957 957
-------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $16,549 19,618 17,611 18,171 18,478 23,296 19,959
NET OPERATING REVENUES ($000) $6,410 3,360 5,316 5,564 5,340 1,069 4,517
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,410 3,360 5,316 5,564 5,340 1,069 4,517
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,410 3,360 5,316 5,564 5,340 1,069 4,517
<CAPTION>
Year Ending December 31 2017 2018
-------- -------
<S> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000
Curtailment Hours (41) 2,600 2,600
Availability Factor (42) 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200
Energy Delivered (MWh) 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200
Heat Rate (Btu/kWh)(42) 9,272 9,272
Fuel Consumption (BBtu)(47) 3,029 3,029
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92
Energy Rate ($/MWh)(50) 49.16 50.31
Process Steam Price ($/Mlb)(51) 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) 16.71 17.15
Chilling Steam Price ($/Mlb)(52) 2.24 2.30
True-up Steam Price ($/Mlb)(52) 0.56 0.57
Natural Gas Price ($/MMBtu)(53) 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000
Bonus Capacity Payment 1,196 1,196
Energy Payment 15,726 16,094
Steam Revenue
Process Steam 512 526
Supplemental Steam 272 280
Chilling Steam 216 221
True-up Steam 18 19
-------- -------
Total Operating Revenues 24,940 25,336
OPERATING EXPENSES ($000)
Natural Gas 13,555 14,012
Natural Gas Use/Sales Taxes (54) 1,065 1,101
Natural Gas Service Fees (55) 232 235
Operating & Maintenance (56) 2,202 2,261
Major Maintenance (57) 296 304
Other Operating Fees/Water (56) 716 735
Audit, Legal & Finance (56) 19 20
Insurance (56) 254 260
Property & Other Taxes (56) 1,258 1,292
Capital Expenditures (56) 40 40
Wheeling (58) 957 957
-------- -------
Total Operating Expenses 20,594 21,217
NET OPERATING REVENUES ($000) 4,346 4,119
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 4,346 4,119
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 4,346 4,119
</TABLE>
B-60
<PAGE>
Footnotes to Exhibit B-3
The footnotes to Exhibit B-3 are the same as the footnotes for Exhibit
B-1, except:
5. Assumes fuel consumption is 5 percent higher than that assumed in the Base
Case.
25. Assumes fuel consumption is 5 percent higher than that assumed in the Base
Case.
42. Assumes fuel consumption is 5 percent higher than that assumed in the Base
Case.
B-61
<PAGE>
Exhibit B-4
CE Generation Gas Projects
Projected Operating Results
Sensitivity C: Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003(1)
--------- --------- --------- --------- -------
<S> <C> <C> <C> <C> <C>
PRI PROJECT
PERFORMANCE
Contract Capacity (kW)(2) 200,000 200,000 200,000 200,000 200,000
Capacity Factor (%)(3) 75.0% 75.0% 75.0% 75.0% 75.0%
Energy Sales (MWh) 1,314,000 1,314,000 1,314,000 1,314,000 985,500
Steam Sales (Mlb)(4) 830,000 830,000 830,000 830,000 830,000
Heat Rate (Btu/kWh)(5) 9,500 9,500 9,500 9,500 9,500
Fuel Consumption (BBtu)(6) 12,483 12,483 12,483 12,483 9,362
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(8) $194.88 201.72 208.80 216.00 223.56
Energy Component
Tier 1 Energy Price ($/MWh)(9) $31.70 32.80 34.00 35.20 36.40
Tier 2 Energy Price ($/MWh)(9) $24.82 25.06 25.52 25.98 26.79
Steam Price ($/Mlb)(10) $2.85 2.90 2.96 3.02 3.08
Natural Gas Price ($/MMBtu)(11) $2.895 2.972 3.054 3.138 3.231
Gas Transportation Cost ($/MMBtu)(12) $0.102 0.102 0.102 0.102 0.102
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $38,976 40,344 41,760 43,200 33,534
Energy $39,168 40,303 41,612 42,922 33,268
Steam Revenue $2,363 2,410 2,459 2,508 2,558
Interest Income (13) $380 385 392 396 289
--------- --------- --------- --------- -------
Total Operating Revenues $80,887 83,442 86,223 89,026 69,649
OPERATING EXPENSES ($000)(14)
Fuel Expense $36,141 37,095 38,120 39,174 30,248
Fuel Transportation Expense $1,275 1,275 1,275 1,275 956
Auxiliary Fuel $48 30 30 30 23
Operator's Fee $1,171 1,204 1,237 1,272 981
Plant Operations $3,131 3,216 3,302 3,392 2,612
Major Maintenance $3,337 3,427 3,520 3,615 2,784
Other O&M $904 1,014 1,087 1,142 882
Insurance $347 380 405 412 326
Administrative Fees $886 144 148 152 117
Property Taxes $1,387 1,387 1,387 1,387 1,040
Capital Expenditures $1,409 1,002 715 516 351
--------- --------- --------- --------- -------
Total Operating Expenses $50,036 50,174 51,226 52,367 40,320
NET OPERATING REVENUES ($000) $30,851 33,268 34,997 36,659 29,329
SENIOR DEBT SERVICE (15)
Balance Outstanding (Jan 1) $90,529 76,261 60,174 42,055 21,743
Principal $14,268 16,088 18,119 20,313 21,743
Interest $8,044 8,561 6,940 4,989 1,459
--------- --------- --------- --------- -------
Total Senior Debt Service $21,561 23,381 23,796 23,975 23,188
Payments into Debt Reserve Fund $85 128 67 (183) (6,014)
Debt Service Reserve Fund Balance (16) $6,002 6,130 6,196 6,014 0
Major Maintenance Reserve Fund Balance (17) $1,000 1,000 1,000 1,000 1,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $9,205 9,759 11,134 12,867 12,155
DISTRIBUTIONS TO
CE GENERATION ($000)(18) $9,205 9,759 11,134 12,867 12,155
</TABLE>
B-62
<PAGE>
Exhibit B-4
CE Generation Gas Projects
Projected Operating Results
Sensitivity C: Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31, 1999(1) 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 89.00% 89.00% 89.00% 89.00% 89.00% 89.00%
Capacity Factor (%)(21) 80.99% 80.99% 80.99% 80.99% 80.99% 80.99%
Energy Sales (MWh)(22) 1,702,700 1,702,700 1,702,700 1,702,700 1,702,700 1,702,700
Available Generation (MWh)(23) 74,800 74,800 74,800 74,800 74,800 74,800
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 713,000 713,000
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550 8,550
Fuel Consumption (BBtu)(26) 14,648 14,648 14,648 14,648 14,648 14,648
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) $72.82 76.22 79.30 82.39 85.47 89.48
Energy Price ($/MWh)(28) $68.61 71.58 74.70 78.00 81.55 85.05
Steam Price ($/Mlb)(29) $3.16 3.29 3.42 3.56 3.70 3.85
Natural Gas Price ($/MMBtu)(30) $2.760 2.906 3.057 3.215 3.378 3.548
Gas Transportation Cost ($/MMBtu)(31) $1.000 1.001 1.002 1.002 1.003 1.003
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity $17,477 18,292 19,032 19,773 20,513 21,476
Energy $121,952 127,232 132,771 138,644 144,959 151,172
Steam Revenue $2,256 2,346 2,440 2,538 2,639 2,745
Interest Income (32) $385 385 385 385 385 385
--------- --------- --------- --------- --------- ---------
Total Operating Revenues $142,070 148,255 154,628 161,340 168,496 175,778
OPERATING EXPENSES ($000)(33)
Fuel Expense $40,433 42,564 44,780 47,086 49,484 51,977
Fuel Transportation Expense $14,652 14,662 14,671 14,680 14,688 14,698
Operation & Maintenance $2,376 2,488 2,605 2,727 2,855 2,989
Operator's Fee $2,100 2,157 2,215 2,275 2,336 2,399
Repair & Maintenance $5,930 6,090 6,255 6,424 6,597 6,775
Water & Chemicals $386 396 407 418 429 441
Consumables $476 489 502 516 530 544
State Excise Tax on Steam Revenues (34) $79 82 85 89 92 96
Insurance $767 788 809 831 853 876
Administrative & General $975 1,001 1,028 1,056 1,084 1,114
Property Taxes $3,016 3,016 3,016 3,016 3,016 3,016
Wheeling Charges (35) $5,424 5,695 5,980 6,279 6,593 6,923
Letter-of-Credit Fees $275 282 289 297 304 312
--------- --------- --------- --------- --------- ---------
Total Operating Expenses $76,889 79,710 82,642 85,694 88,861 92,160
NET OPERATING REVENUES ($000) $65,181 68,545 71,986 75,646 79,635 83,618
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) $189,282 181,097 170,047 156,951 141,399 122,573
Principal $8,185 11,050 13,096 15,552 18,826 22,100
Interest $15,242 14,484 13,516 12,369 10,996 9,354
--------- --------- --------- --------- --------- ---------
Total Senior Debt Service $23,427 25,534 26,612 27,921 29,822 31,454
Payments into Base Reserve Fund $0 0 0 0 0 0
Base Reserve Fund Balance (37) $7,000 7,000 7,000 7,000 7,000 7,000
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $65,181 68,545 71,986 75,646 79,635 83,618
DISTRIBUTIONS TO OTHER PARTNERS (38) $48,199 49,581 46,507 50,724 53,370 56,045
DISTRIBUTIONS TO
CE GENERATION ($000)(38) $16,981 18,964 25,479 24,923 26,265 27,573
<CAPTION>
Year Ending December 31, 2005 2006 2007 2008 2009(1)
--------- --------- --------- --------- -------
<S> <C> <C> <C> <C> <C>
SARANAC PROJECT
PERFORMANCE
Net Plant Capacity (kW)(19) 240,000 240,000 240,000 240,000 240,000
Availability Factor (%)(20) 89.00% 89.00% 89.00% 89.00% 89.00%
Capacity Factor (%)(21) 80.99% 80.99% 80.99% 80.99% 80.99%
Energy Sales (MWh)(22) 1,702,700 1,702,700 1,702,700 1,702,700 851,400
Available Generation (MWh)(23) 74,800 74,800 74,800 74,800 37,400
Steam Sales (Mlb)(24) 713,000 713,000 713,000 713,000 356,600
Heat Rate (Btu/kWh)(25) 8,550 8,550 8,550 8,550 8,550
Fuel Consumption (BBtu)(26) 14,648 14,648 14,648 14,648 7,324
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(27) 92.57 96.27 100.90 104.60 109.24
Energy Price ($/MWh)(28) 88.89 92.78 96.83 101.14 105.59
Steam Price ($/Mlb)(29) 4.00 4.16 4.33 4.50 4.68
Natural Gas Price ($/MMBtu)(30) 3.725 3.910 4.101 4.300 4.472
Gas Transportation Cost ($/MMBtu)(31) 1.004 1.005 1.005 1.006 0.994
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Capacity 22,217 23,105 24,216 25,105 13,109
Energy 157,995 164,925 172,110 179,777 93,849
Steam Revenue 2,855 2,969 3,088 3,211 1,670
Interest Income (32) 385 385 385 385 0
--------- --------- --------- --------- -------
Total Operating Revenues 183,452 191,384 199,799 208,478 108,628
OPERATING EXPENSES ($000)(33)
Fuel Expense 54,569 57,266 60,071 62,988 32,751
Fuel Transportation Expense 14,707 14,717 14,726 14,735 7,282
Operation & Maintenance 3,130 3,277 3,431 3,592 1,881
Operator's Fee 2,464 2,531 2,599 2,669 1,371
Repair & Maintenance 6,958 7,146 7,339 7,537 3,870
Water & Chemicals 453 465 478 491 252
Consumables 559 574 589 605 311
State Excise Tax on Steam Revenues (34) 100 104 108 112 58
Insurance 900 924 949 975 501
Administrative & General 1,144 1,175 1,206 1,239 636
Property Taxes 3,016 3,016 3,016 3,016 1,508
Wheeling Charges (35) 7,269 7,632 8,014 8,415 4,418
Letter-of-Credit Fees 321 330 339 179 0
--------- --------- --------- --------- -------
Total Operating Expenses 95,590 99,157 102,865 106,553 54,839
NET OPERATING REVENUES ($000) 87,862 92,227 96,934 101,925 53,789
SENIOR DEBT SERVICE (36)
Balance Outstanding (Jan 1) 100,473 74,281 43,177 8,799 0
Principal 26,193 31,104 34,378 8,799 0
Interest 7,420 5,125 2,479 180 0
--------- --------- --------- --------- -------
Total Senior Debt Service 33,613 36,229 36,857 8,979 0
Payments into Base Reserve Fund 0 0 0 (7,000) 0
Base Reserve Fund Balance (37) 7,000 7,000 7,000 0 0
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 87,862 92,227 96,934 108,925 53,789
DISTRIBUTIONS TO OTHER PARTNERS (38) 58,500 62,362 68,496 72,552 17,205
DISTRIBUTIONS TO
CE GENERATION ($000)(38) 29,361 29,864 28,438 36,373 36,583
</TABLE>
B-63
<PAGE>
Exhibit B-4
CE Generation Gas Projects
Projected Operating Results
Sensitivity C: Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005
------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 91.0% 91.0% 91.0% 91.0% 91.0% 91.0% 91.0%
On-Peak Availability Factor (43) 87.0% 87.0% 87.0% 87.0% 87.0% 87.0% 87.0%
Capacity Factor (%)(44) 84.7% 84.7% 84.7% 84.7% 84.7% 79.0% 79.0%
Energy Generated (MWh)(42) 370,900 370,900 370,900 370,900 370,900 346,100 346,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700 3,700 3,500 3,500
Energy Delivered (MWh) 367,200 367,200 367,200 367,200 367,200 342,600 342,600
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,300 11,300
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,294 3,294 3,294 3,294 3,294 3,079 3,079
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $155.01 155.01 155.01 155.01 155.01 155.01 155.01
Energy Rate ($/MWh)(50) $30.90 31.70 28.16 33.99 35.23 36.82 40.09
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15
Chilling Steam Price ($/Mlb)(52) $1.32 1.33 1.34 1.54 1.59 1.65 1.77
True-up Steam Price ($/Mlb)(52) $0.33 0.33 0.34 0.38 0.40 0.41 0.44
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $751 751 751 751 751 751 751
Energy Payment $11,346 11,640 10,340 12,481 12,936 12,615 13,735
Steam Revenue
Process Steam $387 397 407 418 428 410 421
Supplemental Steam $96 98 101 103 106 134 137
Chilling Steam $154 155 156 179 185 179 192
True-up Steam $14 15 15 17 17 17 18
------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $19,748 20,056 18,770 20,949 21,423 21,106 22,254
OPERATING EXPENSES ($000)
Natural Gas $7,823 8,103 8,393 8,699 9,006 8,720 9,031
Natural Gas Use/Sales Taxes (54) $615 637 660 684 708 685 710
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599
Major Maintenance (57) $0 3,278 193 0 204 2,322 215
Other Operating Fees/Water (56) $443 455 467 480 493 506 520
Audit, Legal & Finance (56) $762 12 13 13 13 14 14
Insurance (56) $157 161 166 170 175 179 184
Property & Other Taxes (56) $779 800 822 844 867 890 914
Capital Expenditures (56) $179 9 6 23 40 40 40
Wheeling (58) $961 961 961 961 961 959 959
------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $13,264 16,001 13,306 13,540 14,175 16,067 14,384
NET OPERATING REVENUES ($000) $6,484 4,055 5,464 7,409 7,248 5,039 7,870
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,484 4,055 5,464 7,409 7,248 5,039 7,870
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,484 4,055 5,464 7,409 7,248 5,039 7,870
<CAPTION>
Year Ending December 31 2006 2007 2008 2009
------- ------- ------- -------
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 91.0% 91.0% 91.0% 91.0%
On-Peak Availability Factor (43) 87.0% 87.0% 87.0% 87.0%
Capacity Factor (%)(44) 79.0% 79.0% 79.0% 79.0%
Energy Generated (MWh)(42) 346,100 346,100 346,100 346,100
Transmission Losses (MWh)(45) 3,500 3,500 3,500 3,500
Energy Delivered (MWh) 342,600 342,600 342,600 342,600
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,300 11,300 11,300 11,300
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,079 3,079 3,079 3,079
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 155.01 155.01 155.01 155.01
Energy Rate ($/MWh)(50) 39.91 40.19 43.05 42.04
Process Steam Price ($/Mlb)(51) 9.35 9.63 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 12.47 12.84 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 1.78 1.80 1.90 1.89
True-up Steam Price ($/Mlb)(52) 0.44 0.45 0.48 0.47
Natural Gas Price ($/MMBtu)(53) 2.77 2.89 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 751 751 751 751
Energy Payment 13,673 13,769 14,749 14,403
Steam Revenue
Process Steam 432 445 455 467
Supplemental Steam 141 145 148 152
Chilling Steam 193 195 207 205
True-up Steam 18 18 19 19
------- ------- ------- -------
Total Operating Revenues 22,208 22,323 23,329 22,997
OPERATING EXPENSES ($000)
Natural Gas 9,351 9,748 10,028 10,382
Natural Gas Use/Sales Taxes (54) 735 766 788 816
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,642 1,687 1,732 1,779
Major Maintenance (57) 221 3,950 233 239
Other Operating Fees/Water (56) 534 548 563 578
Audit, Legal & Finance (56) 14 15 15 16
Insurance (56) 189 194 200 205
Property & Other Taxes (56) 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 959 959 959 959
------- ------- ------- -------
Total Operating Expenses 14,824 19,074 15,754 16,240
NET OPERATING REVENUES ($000) 7,384 3,249 7,575 6,757
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 7,384 3,249 7,575 6,757
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 7,384 3,249 7,575 6,757
</TABLE>
B-64
<PAGE>
Exhibit B-4
CE Generation Gas Projects
Projected Operating Results
Sensitivity C: Reduced Availability
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 91.0% 91.0% 91.0% 91.0% 91.0%
On-Peak Availability Factor (43) 87.0% 87.0% 87.0% 87.0% 87.0%
Capacity Factor (%)(44) 69.9% 69.9% 69.9% 69.9% 69.9%
Energy Generated (MWh)(42) 306,300 306,300 306,300 306,300 306,300
Transmission Losses (MWh)(45) 3,100 3,100 3,100 3,100 3,100
Energy Delivered (MWh) 303,200 303,200 303,200 303,200 303,200
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 14,700 14,700 14,700 14,700 14,700
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,735 2,735 2,735 2,735 2,735
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $155.01 155.01 155.01 155.01 155.01
Energy Rate ($/MWh)(50) $43.48 43.48 43.26 45.70 45.89
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41
Chilling Steam Price ($/Mlb)(52) $1.95 1.96 1.97 2.06 2.09
True-up Steam Price ($/Mlb)(52) $0.49 0.49 0.49 0.52 0.52
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $751 751 751 751 751
Energy Payment $13,183 13,183 13,116 13,856 13,914
Steam Revenue
Process Steam $425 436 448 460 473
Supplemental Steam $203 209 215 220 226
Chilling Steam $187 189 190 199 201
True-up Steam $18 18 18 19 19
------- ------- ------- ------- -------
Total Operating Revenues $21,767 21,786 21,738 22,505 22,584
OPERATING EXPENSES ($000)
Natural Gas $9,548 9,892 10,251 10,623 11,008
Natural Gas Use/Sales Taxes (54) $750 777 806 835 865
Natural Gas Service Fees (55) $211 214 217 220 223
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033
Major Maintenance (57) $245 2,547 259 266 273
Other Operating Fees/Water (56) $594 610 626 643 661
Audit, Legal & Finance (56) $16 17 17 17 18
Insurance (56) $210 216 222 228 234
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162
Capital Expenditures (56) $40 40 40 40 40
Wheeling (58) $956 956 956 956 956
------- ------- ------- ------- -------
Total Operating Expenses $15,441 18,217 16,422 16,938 17,473
NET OPERATING REVENUES ($000) $6,326 3,569 5,316 5,567 5,111
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,326 3,569 5,316 5,567 5,111
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,326 3,569 5,316 5,567 5,111
<CAPTION>
Year Ending December 31 2015 2016 2017 2018
------- ------- ------- -------
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600
Availability Factor (42) 91.0% 91.0% 91.0% 91.0%
On-Peak Availability Factor (43) 87.0% 87.0% 87.0% 87.0%
Capacity Factor (%)(44) 69.9% 69.9% 69.9% 69.9%
Energy Generated (MWh)(42) 306,300 306,300 306,300 306,300
Transmission Losses (MWh)(45) 3,100 3,100 3,100 3,100
Energy Delivered (MWh) 303,200 303,200 303,200 303,200
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 14,700 14,700 14,700 14,700
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,735 2,735 2,735 2,735
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 155.01 155.01 155.01 155.01
Energy Rate ($/MWh)(50) 47.57 47.79 49.16 50.31
Process Steam Price ($/Mlb)(51) 11.59 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) 15.45 16.26 16.71 17.15
Chilling Steam Price ($/Mlb)(52) 2.16 2.18 2.24 2.30
True-up Steam Price ($/Mlb)(52) 0.54 0.55 0.56 0.57
Natural Gas Price ($/MMBtu)(53) 3.62 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 751 751 751 751
Energy Payment 14,423 14,490 14,905 15,254
Steam Revenue
Process Steam 474 499 512 526
Supplemental Steam 227 239 246 252
Chilling Steam 207 210 216 221
True-up Steam 19 20 20 21
------- ------- ------- -------
Total Operating Revenues 23,101 23,209 23,650 24,025
OPERATING EXPENSES ($000)
Natural Gas 10,858 11,815 12,239 12,652
Natural Gas Use/Sales Taxes (54) 853 929 962 994
Natural Gas Service Fees (55) 226 229 232 235
Operating & Maintenance (56) 2,087 2,144 2,202 2,261
Major Maintenance (57) 0 5,020 296 304
Other Operating Fees/Water (56) 678 697 716 735
Audit, Legal & Finance (56) 18 19 19 20
Insurance (56) 240 247 254 260
Property & Other Taxes (56) 1,193 1,225 1,258 1,292
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 956 956 956 956
------- ------- ------- -------
Total Operating Expenses 17,149 23,321 19,174 19,749
NET OPERATING REVENUES ($000) 5,952 (112) 4,476 4,276
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 5,952 0 4,476 4,276
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 5,952 0 4,476 4,276
</TABLE>
B-65
<PAGE>
Footnotes to Exhibit B-4
The footnotes to Exhibit B-4 are the same as the footnotes for Exhibit
B-1, except:
3. Assumes availability of the Natural Gas Projects is 5 percent less than
that assumed in the Base Case.
20. Assumes availability of the Natural Gas Projects is 5 percent less than
that assumed in the Base Case.
42. Assumes availability of the Natural Gas Projects is 5 percent less than
that assumed in the Base Case.
B-66
<PAGE>
Exhibit B-5
CE Generation Gas Projects
Projected Operating Results
Sensitivity D: Yuma Low Gas 1
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005
------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4%
Energy Generated (Mwh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 l40.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 l63.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $30.90 31.70 27.86 30.57 32.73 34.88 38.70
Process Steam Price ($/Mlb)(51) $7.81 7.90 7.99 8.09 8.30 8.51 8.73
Supplemental Steam Price ($/Mlb)(51) $10.42 10.53 10.65 10.79 11.07 11.35 11.64
Chilling Steam Price ($/Mlb)(52) $1.32 1.32 1.33 1.43 1.51 1.59 1.72
True-up Steam Price ($/Mlb)(52) $0.33 0.33 0.33 0.36 0.38 0.40 0.43
Natural Gas Price ($/MMBtu)(53) $2.15 2.15 2.15 2.16 2.24 2.32 2.40
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,971 12,281 10,793 11,843 12,678 12,606 13.986
Steam Revenue
Process Steam $387 391 396 401 411 393 403
Supplemental Steam $96 97 98 99 102 135 139
Chilling Steam $154 154 155 166 176 173 187
True-up Steam $13 13 13 14 15 15 16
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $20,817 21,132 19,651 20,719 21,578 21,518 22,927
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,272 8,292 8,341 8,636 8,364 8,659
Natural Gas Use/Sales Taxes (54) $648 650 652 656 679 657 681
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599
Major Maintenance (57) $183 3,278 193 198 2,262 209 215
Other Operating Fees/Water (56) $443 455 467 480 493 506 520
Audit, Legal & Finance (56) $762 12 13 13 13 14 14
Insurance (56) $157 161 166 170 175 179 184
Property & Other Taxes (56) $779 800 822 844 867 890 914
Capital Expenditures (56) $179 9 6 23 40 40 40
Wheeling (58) $963 963 963 963 963 961 961
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,185 13,199 13,354 15,836 13,572 13,985
NET OPERATING REVENUES ($000) $6,907 4,947 6,452 7,365 5,742 7,946 8,942
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,907 4,947 6,452 7,365 5,742 7,946 8,942
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,907 4,947 6,452 7,365 5,742 7,946 8,942
<CAPTION>
Year Ending December 31 2006 2007 2008 2009
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4%
Energy Generated (Mwh)(42) 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400
Process Swam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 39.01 39.32 39.63 39.94
Process Steam Price ($/Mlb)(51) 8.96 9.22 9.43 9.67
Supplemental Steam Price ($/Mlb)(51) 11.95 12.29 12.57 12.90
Chilling Steam Price ($/Mlb)(52) 1.75 1.77 1.79 1.82
True-up Steam Price ($/Mlb)(52) 0.44 0.44 0.45 0.45
Natural Gas Price ($/MMBtu)(53) 2.49 2.60 2.67 2.77
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 14,098 14,210 14,322 14,434
Steam Revenue
Process Steam 414 426 436 447
Supplemental Steam 142 146 150 153
Chilling Steam 190 192 195 198
True-up Steam 16 16 17 17
------ ------ ------ ------
Total Operating Revenues 23,056 23,186 23,316 23,445
OPERATING EXPENSES ($000)
Natural Gas 8,968 9,344 9,614 9,952
Natural Gas Use/Sales Taxes (54) 705 734 756 782
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,642 1,687 1,732 1,779
Major Maintenance (57) 0 3,950 233 239
Other Operating Fees/Water (56) 534 548 563 578
Audit, Legal & Finance (56) 14 15 15 16
Insurance (56) 189 194 200 205
Property & Other Taxes (56) 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 961 961 961 961
------ ------ ------ ------
Total Operating Expenses 14,192 18,640 15,310 15,778
NET OPERATING REVENUES ($000) 8,864 4,546 8,006 7,667
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 8,864 4,546 8,006 7,667
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 8,864 4,546 8,006 7,667
</TABLE>
B-67
<PAGE>
Exhibit B-5
CE Generation Gas Projects
Projected Operating Results
Sensitivity D: Yuma Low Gas 1
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 l6,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92
Energy Rate ($MWh)(50) $40.25 40.91 41.57 42.13 42.89
Process Steam Price ($/Mlb)(51) $9.93 10.19 10.46 10.74 11.03
Supplemental Steam Price ($/Mlb)(51) $13.23 13.58 13.95 14.32 14.71
Chilling Steam Price ($/Mlb)(52) $1.84 1.88 1.92 1.95 1.99
True-up Steam Price ($/Mlb)(52) $0.46 0.47 0.48 0.49 0.50
Natural Gas Price ($/MMBtu)(53) $2.87 2.98 3.09 3.20 3.32
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196
Energy Payment $12,876 13,087 13,298 13,509 13,721
Steam Revenue
Process Steam $406 417 428 439 451
Supp1ement Steam $216 22l 227 233 240
Chilling Steam $177 181 184 188 192
True-up Steam $15 15 16 16 16
------- ------ ------ ------ ------
Total Operating Revenues $21,886 22,117 22,349 22,581 22,816
OPERATING EXPENSES ($000)
Natural Gas $9,154 9,483 9,827 10,182 10,55l
Natural Gas Use/Sales Taxes (54) $719 745 772 800 829
Natural Gas Service Fees (55) $211 214 217 220 223
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033
Major Maintenance (57) $245 2,799 259 266 0
Other Operating Fees/Water (56) $594 610 626 643 661
Audit, Legal & Finance (56) $16 17 17 17 18
Insurance (56) $210 216 222 228 234
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162
Capital Expenditures (56) $40 40 40 40 40
Wheeling (58) $957 957 957 957 957
------- ------ ------ ------ ------
Total Operating Expenses $15,017 18,029 15,965 16,463 16,708
NET OPERATING REVENUES ($000) $6,869 4,088 6,384 6,118 6,108
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,869 4,088 6,384 6,118 6,108
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,869 4,088 6,384 6,118 6,108
<CAPTION>
Year Ending December 31 2015 2016 2017 2018
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100
Transmission Losses (MWhx45) 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($MWh)(50) 43.91 44.92 45.94 46.95
Process Steam Price ($/Mlb)(51) 11.07 11.63 11.94 12.26
Supplemental Steam Price ($/Mlb)(51) 14.76 15.51 15.93 16.34
Chilling Steam Price ($/Mlb)(52) 2.04 2.09 2.14 2.19
True-up Steam Price ($/Mlb)(52) 0.51 0.52 0.54 0.55
Natural Gas Price ($/MMBtu)(53) 3.26 3.57 3.70 3.83
Gas Transportation Cost ($/MMBtu)(53) 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 14,045 14,370 14,695 15,019
Steam Revenue
Process Steam 453 476 489 501
Supp1ement Steam 241 253 260 266
Chilling Steam 196 201 206 211
True-up Steam 17 17 18 18
------ ------ ------ ------
Total Operating Revenues 23,148 23,513 23,864 24,211
OPERATING EXPENSES ($000)
Natural Gas 10,413 11325 11,729 12,124
Natural Gas Use/Sales Taxes (54) 818 890 922 953
Natural Gas Service Fees (55) 226 229 232 235
Operating & Maintenance (56) 2,087 2,144 2,202 2,261
Major Maintenance (57) 4,887 288 296 304
Other Operating Fees/Water (56) 678 697 716 735
Audit, Legal & Finance (56) 18 19 19 20
Insurance (56) 240 247 254 260
Property & Other Taxes (56) 1,193 1,225 1,258 1,292
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 957 957 957 957
------ ------ ------ ------
Total Operating Expenses 21,557 18,061 18,625 19,181
NET OPERATING REVENUES ($000) 1,591 5,452 5,239 5,030
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 1,591 5,452 5,239 5,030
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 1,591 5,452 5,239 5,030
</TABLE>
B-68
<PAGE>
Footnotes to Exhibit B-5
The footnotes to Exhibit B-5 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices consistent with the Low Gas 1 case as described in the
Henwood Report.
53. Assumes prices consistent with the Low Gas 1 case as described in the
Henwood Report.
B-69
<PAGE>
Exhibit B-6
CE Generation Gas Projects
Projected Operating Results
Sensitivity E: Yuma Low Gas 2
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005
------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4%
Energy Generated (Mwh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $30.90 31.70 26.47 28.75 30.42 32.09 35.58
Process Steam Price ($/Mlb)(51) $7.81 7.92 8.02 8.13 8.23 8.33 8.54
Supplemental Steam Price ($/Mlb)(51) $10.42 10.56 10.70 10.84 10.97 11.11 11.39
Chilling Steam Price ($/Mlb)(52) $1.32 1.30 1.29 1.37 1.44 1.50 1.63
True-up Steam Price ($/Mlb)(52) $0.33 0.32 0.32 0.34 0.36 0.38 0.41
Natural Gas Price ($/MMBtu)(53) $2.15 2.16 2.17 2.18 2.19 2.19 2.27
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,971 12,281 10,254 11,137 11,784 11,596 12,859
Steam Revenue
Process Steam $387 392 397 402 407 385 395
Supplemental Steam $96 97 98 100 101 132 136
Chilling Steam $154 151 150 160 167 163 177
True-up Steam $13 13 13 14 14 14 15
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $20,817 21,130 19,108 20,009 20,669 20,486 21,778
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,313 8,369 8,424 8,463 7,945 8,227
Natural Gas Use/Sales Taxes (54) $648 653 658 662 665 624 647
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599
Major Maintenance (57) $183 3,278 193 198 2,262 209 215
Other Operating Fees/Water (56) $443 455 467 480 493 506 520
Audit, Legal & Finance (56) $762 12 13 13 13 14 14
Insurance (56) $157 161 166 170 175 179 184
Property & Other Taxes (56) $779 800 822 844 867 890 914
Capital Expenditures (56) $179 9 6 23 40 40 40
Wheeling (58) $963 963 963 963 963 961 961
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,229 13,282 13,443 15,649 13,120 13,519
NET OPERATING REVENUES ($000) $6,907 4,901 5,826 6,566 5,020 7,366 8,259
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,907 4,901 5,826 6,566 5,020 7,366 8,259
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,907 4,901 5,826 6,566 5,020 7,366 8,259
<CAPTION>
Year Ending December 31 2006 2007 2008 2009
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4%
Energy Generated(Mwh)(42) 365,100 365,100 365,100 365,100
Transmission Losses (MWh(45) 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 36.16 36.74 37.31 37.89
Process Steam Price ($/Mlb)(51) 8.76 9.01 9.22 9.45
Supplemental Steam Price ($/Mlb)(51) 11.68 12.02 12.29 12.61
Chilling Steam Price ($/Mlb)(52) 1.66 1.69 1.72 1.75
True-up Steam Price ($/Mlb)(52) 0.41 0.42 0.43 0.44
Natural Gas Price ($/MMBtu)(53) 2.35 2.45 2.53 2.62
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 13,068 13,276 13,485 13,694
Steam Revenue
Process Steam 405 416 426 437
Supplemental Steam 139 143 146 150
Chilling Steam 180 184 187 191
True-up Steam 15 16 16 16
------ ------ ------ ------
Total Operating Revenues 22,003 22,231 22,456 22,684
OPERATING EXPENSES ($000)
Natural Gas 8,516 8,877 9,133 9,452
Natural Gas Use/Sales Taxes (54) 669 698 718 743
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,642 1,687 1,732 1,779
Major Maintenance (57) 0 3,950 233 239
Other Operating Fees/Water (56) 534 548 563 578
Audit, Legal & Finance(56) 14 15 15 16
Insurance (56) 189 194 200 205
Property & Other Taxes(56) 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 961 961 961 961
------ ------ ------ ------
Total Operating Expenses 13,704 18,137 14,791 15,239
NET OPERATING REVENUES ($000) 8,299 4,094 7,665 7,445
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 8,299 4,094 7,665 7,445
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 8,299 4,094 7,665 7,445
</TABLE>
B-70
<PAGE>
Exhibit B-6
CE Generation Gas Projects
Projected Operating Results
Sensitivity E: Yuma Low Gas 2
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 19,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $38.47 38.85 39.23 39.60 39.98
Process Steam Price ($/Mlb)(51) $9.70 9.95 10.22 10.49 10.77
Supplemental Steam Price($/Mlb)(51) $12.93 13.27 13.62 13.98 14.36
Chilling Steam Price ($/Mlb)(52) $1.79 1.82 1.84 1.87 1.90
True-up Steam Price ($/Mlb)(52) $0.45 0.45 0.46 0.47 0.48
Natural Gas Price ($/MMBtu)(53) $2.71 2.81 2.92 3.02 3.14
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196
Energy Payment $12,307 12,427 12,548 12,669 12,790
Steam Revenue
Process Steam $397 407 418 429 440
Supplement Steam $211 216 222 228 234
Chilling Steam $172 175 177 180 183
True-up Steam $15 15 15 15 16
------- ------ ------ ------ -----
Total Operating Revenues $21,298 21,436 2l,576 21,717 21,859
OPERATING EXPENSES ($000)
Natural Gas $8,696 9,007 9,333 9,671 10,020
Natural Gas Use/Sales Taxes (54) $683 708 733 760 787
Natural Gas Service Fees (55) $211 214 217 220 223
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033
Major Maintenance (57) $245 2,799 259 266 0
Other Operating Fees/Water (56) $594 610 626 643 661
Audit, Legal & Finance (56) $16 17 17 17 18
Insurance (56) $210 216 222 228 234
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162
Capital Expenditures (56) $40 40 40 40 40
Wheeling (58) $957 957 957 957 957
------- ------ ------ ------ -----
Total Operating Expenses $14,523 17,516 15,432 15,912 l6,135
NET OPERATING REVENUES ($000) $6,775 3,920 6,144 5,805 5,724
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,775 3,920 6,l44 5,805 5,724
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,775 3920 6,144 5,805 5,724
<CAPTION>
Year Ending December 31 2015 2016 2017 2018
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 40.81 41.65 42.48 43.31
Process Steam Price ($/Mlb)(51) 10.81 11.35 11.65 11.95
Supplemental Steam Price($/Mlb)(51) 14.41 15.13 15.54 15.94
Chilling Steam Price ($/Mlb)(52) 1.94 1.99 2.03 2.08
True-up Steam Price ($/Mlb)(52) 0.49 0.50 0.51 0.52
Natural Gas Price ($/MMBtu)(53) 3.08 3.37 3.49 3.61
Gas Transportation Cost ($/MMBtu)(53) 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 13,056 13,322 13,589 13,855
Steam Revenue
Process Steam 442 464 477 489
Supplement Steam 235 247 253 260
Chilling Steam 187 191 196 200
True-up Steam 16 16 17 17
------ ------ ------ ------
Total Operating Revenues 22,132 22,436 22,728 23,017
OPERATING EXPENSES ($000)
Natural Gas 9,887 10,750 11,137 11,509
Natural Gas Use/Sales Taxes (54) 777 845 875 904
Natural Gas Service Fees(55) 226 229 232 235
Operating & Maintenance (56) 2,087 2,144 2,202 2,261
Major Maintenance (57) 4,887 288 296 304
Other Operating Fees/Water (56) 678 697 716 735
Audit, Legal & Finance(56) 18 19 19 20
Insurance (56) 240 247 254 260
Property & Other Taxes (56) 1,193 1,225 1,258 1,292
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 957 957 957 957
------ ------ ------ ------
Total Operating Expenses 20,990 17,441 17,986 18,517
NET OPERATING REVENUES ($000) 1,142 4,995 4,742 4,500
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) l,142 4,995 4,742 4,500
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 1,142 4,995 4,742 4,500
</TABLE>
B-71
<PAGE>
Footnotes to Exhibit B-6
The footnotes to Exhibit B-6 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices consistent with the Low Gas 2 case as described in the
Henwood Report.
53. Assumes prices consistent with the Low Gas 2 case as described in the
Henwood Report.
B-72
<PAGE>
Exhibit B-7
CE Generation Gas Projects
Projected Operating Results
Sensitivity F: Yuma SCE Low SRAC
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005
------- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900
Chilling Steam Demand (MIb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBTu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $29.10 31.10 33.00 34.20 35.20 36.20 37.20
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15
Chilling Steam Price ($/Mlb)(52) $0.43 0.44 0.45 0.47 0.48 0.49 0.50
True-up Steam Price ($/Mlb)(52) $0.11 0.11 0.11 0.12 0.12 0.12 0.13
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,273 12,048 12,784 13,249 13,636 13,083 13,444
Steam Revenue
Process Steam $387 397 407 418 428 410 421
Supplemental Steam $96 98 101 103 106 141 145
Chilling Steam $50 51 53 54 56 53 55
True-up Steam $4 4 5 5 5 5 5
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $20,006 20,794 21,546 22,025 22,427 21,888 22,266
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198 9,526
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723 749
Natural Gas Service Fees (55) $182 185 187 190 192 195 198
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599
Major Maintenance (57) $183 3,278 193 198 2,262 209 215
Other Operating Fees/Water (56) $443 455 467 480 493 506 520
Audit, Legal & Finance (56) $762 12 13 13 13 14 14
Insurance (56) $157 161 166 170 175 179 184
Property & Other Taxes (56) $779 800 822 844 867 890 914
Capital Expenditures (56) $179 9 6 23 40 40 40
Wheeling (58) $963 963 963 963 963 961 961
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,481 13,803 14,253 16,765 14,472 14,920
NET OPERATING REVENUES ($000) $6,096 4,313 7,743 7,772 5,662 7,416 7,346
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,096 4,313 7,743 7,772 5,662 7,416 7,346
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,096 4,313 7,743 7,772 5,662 7,416 7,346
<CAPTION>
Year Ending December 31 2006 2007 2008 2009
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBTu)(47) 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 38.30 39.50 40.60 41.80
Process Steam Price ($/Mlb)(51) 9.35 9.63 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 12.47 12.84 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 0.52 0.53 0.55 0.56
True-up Steam Price ($/Mlb)(52) 0.13 0.13 0.14 0.14
Natural Gas Price ($/MMBtu)(53) 2.77 2.89 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.27 0.28 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 13,842 14,275 14,673 15,107
Steam Revenue
Process Steam 432 445 455 467
Supplemental Steam 148 153 156 160
Chilling Steam 56 58 59 61
True-up Steam 5 5 5 5
------ ------ ------ ------
Total Operating Revenues 22,679 23,132 23,544 23,996
OPERATING EXPENSES ($000)
Natural Gas 9,864 10,283 10,579 10,952
Natural Gas Use/Sales Taxes (54) 775 808 831 861
Natural Gas Service Fees (55) 200 203 206 209
Operating & Maintenance (56) 1,642 1,687 1,732 1,779
Major Maintenance (57) 0 3,950 233 239
Other Operating Fees/Water (56) 534 548 563 578
Audit, Legal & Finance (56) 14 15 15 16
Insurance (56) 189 194 200 205
Property & Other Taxes (56) 939 964 990 1,017
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 961 961 961 961
------ ------ ------ ------
Total Operating Expenses 15,158 19,653 16,350 16,857
NET OPERATING REVENUES ($000) 7,521 3,479 7,194 7,139
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 7,521 3,479 7,194 7,139
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 7,521 3,479 7,194 7,139
</TABLE>
B-73
<PAGE>
Exhibit B-7
CE Generation Gas Projects
Projected Operating Results
Sensitivity F: Yuma SCE Low SRAC
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (Mwh)(42) 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $43.10 44.30 45.70 47.00 48.40
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41
Chilling Steam Price ($/Mlb)(52) $0.58 0.59 0.61 0.62 0.64
True-up Steam Price ($/Mlb)(52) $0.14 0.15 0.15 0.16 0.16
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196
Energy Payment $13,788 14,172 14,619 15,035 15,483
Steam Revenue
Process Steam $425 436 448 460 473
Supplement Steam $226 232 238 244 251
Chilling Steam $55 57 59 60 62
True-up Steam $5 5 5 5 5
------- ------ ------ ------ ------
Total Operating Revenues $22,695 23,098 23,565 24,000 24,470
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913
Natural Gas Service Fees (55) $211 214 217 220 223
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033
Major Maintenance (57) $245 2,799 259 266 0
Other Operating Fees/Water (56) $594 610 626 643 661
Audit, Legal & Finance (56) $16 17 17 17 18
Insurance (56) $210 216 222 228 234
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162
Capital Expenditures (56) $40 40 40 40 40
Wheeling (58) $957 957 957 957 957
------- ------ ------ ------ ------
Total Operating Expenses $16,011 19,060 17,033 17,571 17,857
NET OPERATING REVENUES ($000) $6,684 4,038 6,532 6,429 6,613
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,684 4,038 6.532 6,429 6,613
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,684 4,038 6,532 6,429 6,613
<CAPTION>
Year Ending December 31 2015 2016 2017 2018
---- ---- ---- ----
<S> <C> <C> <C> <C>
YUMA PROJECT
PERFORMANCE
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8%
Energy Generated (Mwh)(42) 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) 49.90 51.25 52.63 54.05
Process Steam Price($/Mlb)(51) 11.59 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) 15.45 16.26 16.71 17.15
Chilling Steam Price ($/Mlb)(52) 0.66 0.68 0.70 0.71
True-up Steam Price($/Mlb)(52) 0.16 0.17 0.17 0.18
Natural Gas Price ($/MMBtu)(53) 3.62 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000 7,000 7,000
Bonus Capacity Payment 1,196 1,196 1,196 1,196
Energy Payment 15,963 16,394 16,837 17,291
Steam Revenue
Process Steam 474 499 512 526
Supplement Steam 252 265 272 280
Chilling Steam 63 65 67 69
True-up Steam 5 6 6 6
------ ------ ------ ------
Total Operating Revenues 24,953 25,425 25,890 26,368
OPERATING EXPENSES ($000)
Natural Gas 11,457 12,468 12,915 13,351
Natural Gas Use/Sales Taxes (54) 900 980 1,015 1,049
Natural Gas Service Fees (55) 226 229 232 235
Operating & Maintenance (56) 2,087 2,144 2,202 2,261
Major Maintenance (57) 4,887 288 296 304
Other Operating Fees/Water (56) 678 697 716 735
Audit, Legal & Finance (56) 18 19 19 20
Insurance (56) 240 247 254 260
Property & Other Taxes (56) 1,193 1,225 1,258 1,292
Capital Expenditures (56) 40 40 40 40
Wheeling (58) 957 957 957 957
------ ------ ------ ------
Total Operating Expenses 22,683 19,294 19,904 20,504
NET OPERATING REVENUES ($000) 2,270 6,131 5,986 5,864
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 2,270 6,131 5,986 5,864
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 2,270 6,131 5,986 5,864
</TABLE>
B-74
<PAGE>
Footnotes to Exhibit B-7
The footnotes to Exhibit B-7 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices consistent with the SCE Low SRAC case as described in the
Henwood Report.
53. Assumes prices consistent with the SCE Low SRAC case as described in the
Henwood Report.
B-75
<PAGE>
Exhibit B-8
CE Generation Gas Projects
Projected Operating Results
Sensitivity G: Yuma SCE Median SRAC
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005 2006 2007
------- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $29.90 32.20 34.60 35.90 37.20 38.80 41.10 43.10 44.40
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11 9.35 9.63
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15 12.47 12.84
Chilling Steam Price ($/Mlb)(52) $0.43 0.44 0.45 0.47 0.48 0.49 0.50 0.52 0.53
True-up Steam Price ($/Mlb)(52) $0.11 0.11 0.11 0.12 0.12 0.12 0.13 0.13 0.13
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67 2.77 2.89
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27 0.27 0.28
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $11,583 12,474 13,404 13,908 14,411 14,022 14,854 15,576 16,046
Steam Revenue
Process Steam $387 397 407 418 428 410 421 432 445
Supplemental Steam $96 98 101 103 106 141 145 148 153
Chilling Steam $50 51 53 54 56 53 55 56 58
True-up Steam $4 4 5 5 5 5 5 5 5
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $20,316 21,220 22,166 22,684 23,202 22,827 23,676 24,413 24,903
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198 9,526 9,864 10,283
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723 749 775 808
Natural Gas Service Fees (55) $182 185 187 190 192 195 198 200 203
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599 1,642 1,687
Major Maintenance (57) $183 3,278 193 198 2,262 209 215 0 3,950
Other Operating Fees/Water (56) $443 455 467 480 493 506 520 534 548
Audit, Legal & Finance (56) $762 12 13 13 13 14 14 14 15
Insurance (56) $157 161 166 170 175 179 184 189 194
Property & Other Taxes (56) $779 800 822 844 867 890 914 939 964
Capital Expenditures (56) $179 9 6 23 40 40 40 40 40
Wheeling (58) $963 963 963 963 963 961 961 961 961
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,481 13,803 14,253 16,765 14,472 14,920 15,158 19,653
NET OPERATING REVENUES ($000) $6,406 4,739 8,363 8,431 6,437 8,355 8,756 9,255 5,250
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $6,406 4.739 8,363 8,431 6,437 8,355 8,756 9,255 5,250
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $6,406 4,739 8,363 8,431 6,437 8,355 8,756 9,255 5,250
Year Ending December 31 2008 2009
---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000
Curtailment Hours (41) 1,800 1.800
Availability Factor (42) 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700
Energy Delivered (MWh) 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92
Energy Rate ($/MWh)(50) 45.90 47.40
Process Steam Price ($/Mlb)(51) 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 0.55 0.56
True-up Steam Price ($/Mlb)(52) 0.14 0.14
Natural Gas Price ($/MMBtu)(53) 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000
Bonus Capacity Payment 1,196 1,196
Energy Payment 16,588 17,130
Steam Revenue
Process Steam 455 467
Supplemental Steam 156 160
Chilling Steam 59 61
True-up Steam 5 5
------ ------
Total Operating Revenues 25,459 26,019
OPERATING EXPENSES ($000)
Natural Gas 10,579 10,952
Natural Gas Use/Sales Taxes (54) 831 861
Natural Gas Service Fees (55) 206 209
Operating & Maintenance (56) 1,732 1,779
Major Maintenance (57) 233 239
Other Operating Fees/Water (56) 563 578
Audit, Legal & Finance (56) 15 16
Insurance (56) 200 205
Property & Other Taxes (56) 990 1,017
Capital Expenditures (56) 40 40
Wheeling (58) 961 961
------ ------
Total Operating Expenses 16,350 16,857
NET OPERATING REVENUES ($000) 9,109 9,162
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 9,109 9,162
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 9,109 9,162
</TABLE>
B-76
<PAGE>
Exhibit B-8
CE Generation Gas Projects
Projected Operating Results
Sensitivity G: Yuma SCE Median SRAC
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014 2015 2016 2017 2018
---- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886 2,886 2,886 2.886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $48.90 50.60 42.20 54.00 55.80 57.60 59.16 60.75 62.39
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45 16.26 16.71 17.15
Chilling Steam Price ($/Mlb)(52) $0.58 0.59 0.61 0.62 0.64 0.66 0.68 0.70 0.71
True-up Steam Price ($/Mlb)(52) $0.14 0.15 0.15 0.16 0.16 0.16 0.17 0.17 0.18
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $15,643 16,187 13,500 17,275 17,850 18,426 18,924 19,435 19,959
Steam Revenue
Process Steam $425 436 448 460 473 474 499 512 526
Supplemental Steam $226 232 238 244 251 252 265 272 280
Chilling Steam $55 57 59 60 62 63 65 67 69
True-up Steam $5 5 5 5 5 5 6 6 6
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $24,550 25,113 22,446 26,240 26,837 27,416 27,955 28,488 29,036
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616 11,457 12,468 12,915 13,351
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913 900 980 1,015 1,049
Natural Gas Service Fees (55) $211 214 217 220 223 226 229 232 235
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033 2,087 2,144 2,202 2,261
Major Maintenance (57) $245 2,799 259 266 0 4,887 288 296 304
Other Operating Fees/Water (56) $594 610 626 643 661 678 697 716 735
Audit, Legal & Finance (56) $16 17 17 17 18 18 19 19 20
Insurance (56) $210 216 222 228 234 240 247 254 260
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162 1,193 1,225 1,258 1,292
Capital Expenditures (56) $40 40 40 40 40 40 40 40 40
Wheeling (58) $957 957 957 957 957 957 957 957 957
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $16,011 19,060 17,033 17,571 17,857 22,683 19,294 19,904 20,504
NET OPERATING REVENUES ($000) $8,539 6,053 5,413 8,669 8,980 4,733 8,661 8,584 8,532
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $8,539 6,053 5,413 8,669 8,980 4,733 8,661 8,584 8,532
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $8,539 6,053 5,413 8,669 8,980 4,733 8,661 8,584 8,532
</TABLE>
B-77
<PAGE>
Footnotes to Exhibit B-8
The footnotes to Exhibit B-8 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices consistent with the SCE Median SRAC case as described in
the Henwood Report.
53. Assumes prices consistent with the SCE Median SRAC case as described in
the Henwood Report.
B-78
<PAGE>
Exhibit B-9
CE Generation Gas Projects
Projected Operating Results
Sensitivity H: Yuma SCE High SRAC
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005 2006 2007
------- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8.830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $32.80 36.00 39.10 41.30 43.60 46.10 48.60 51.60 54.80
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11 9.35 9.63
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15 12.47 12.84
Chilling Steam Price ($/Mlb)(52) $0.43 0.44 0.45 0.47 0.48 0.49 0.50 0.52 0.53
True-up Steam Price ($/Mlb)(52) $0.11 0.11 0.11 0.12 0.12 0.12 0.13 0.13 0.13
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67 2.77 2.89
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27 0.27 0.28
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $12,707 13,946 15,147 16,000 16,891 16,661 17,564 18,648 19,805
Steam Revenue
Process Steam $387 397 407 418 428 410 421 432 445
Supplemental Steam $96 98 101 103 106 141 145 148 153
Chilling Steam $50 51 53 54 56 53 55 56 58
True-up Steam $4 4 5 5 5 5 5 5 5
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $21,440 22,692 23,909 24,776 25,682 25,466 26,386 27,485 28,662
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198 9,526 9,864 10,283
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723 749 775 808
Natural Gas Service Fees (55) $182 185 187 190 192 195 198 200 203
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599 1,642 1,687
Major Maintenance (57) $183 3,278 193 198 2,262 209 215 0 3,950
Other Operating Fees/Water (56) $443 455 467 480 493 506 520 534 548
Audit, Legal & Finance (56) $762 12 13 13 13 14 14 14 15
Insurance (56) $157 161 166 170 175 179 184 189 194
Property & Other Taxes (56) $779 800 822 844 867 890 914 939 964
Capital Expenditures (56) $179 9 6 23 40 40 40 40 40
Wheeling (58) $963 963 963 963 963 961 961 961 961
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,481 13,803 14,253 16,765 14,472 14,920 15,158 19,653
NET OPERATING REVENUES ($000) $7,530 6,211 10,106 10,523 8,917 10,994 11,466 12,327 9,009
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $7,530 6,211 10,106 10,523 8,917 10,994 11,466 12,327 9,009
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $7,530 6,211 10,106 10,523 8,917 10,994 11,466 12,327 9,009
Year Ending December 31 2008 2009
---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000
Curtailment Hours (41) 1,800 1,800
Availability Factor (42) 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700
Energy Delivered (MWh) 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92
Energy Rate ($/MWh)(50) 58.20 61.90
Process Steam Price ($/Mlb)(51) 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 0.55 0.56
True-up Steam Price ($/Mlb)(52) 0.14 0.14
Natural Gas Price ($/MMBtu)(53) 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000
Bonus Capacity Payment 1,196 1,196
Energy Payment 21,033 22,371
Steam Revenue
Process Steam 455 467
Supplemental Steam 156 160
Chilling Steam 59 61
True-up Steam 5 5
------ ------
Total Operating Revenues 29,904 31,260
OPERATING EXPENSES ($000)
Natural Gas 10,579 10,952
Natural Gas Use/Sales Taxes (54) 831 861
Natural Gas Service Fees (55) 206 209
Operating & Maintenance (56) 1,732 1,779
Major Maintenance (57) 233 239
Other Operating Fees/Water (56) 563 578
Audit, Legal & Finance (56) 15 16
Insurance (56) 200 205
Property & Other Taxes (56) 990 1,017
Capital Expenditures (56) 40 40
Wheeling (58) 961 961
------ ------
Total Operating Expenses 16,350 16,857
NET OPERATING REVENUES ($000) 13,554 14,403
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 13,554 14,403
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 13,554 14,403
</TABLE>
B-79
<PAGE>
Exhibit B-9
CE Generation Gas Projects
Projected Operating Results
Sensitivity H: Yuma SCE High SRAC
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014 2015 2016 2017 2018
---- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40,900 40,900 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $65.90 70.70 76.00 81.60 87.60 94.10 96.64 99.25 101.93
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45 16.26 16.71 17.15
Chilling Steam Price ($/Mlb)(52) $0.58 0.59 0.61 0.62 0.64 0.66 0.68 0.70 0.71
True-up Steam Price ($/Mlb)(52) $0.14 0.15 0.15 0.16 0.16 0.16 0.17 0.17 0.18
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1.196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $21,081 22,617 24,312 26,104 28,023 30,103 30,915 31,750 32,607
Steam Revenue
Process Steam $425 436 448 460 473 474 499 512 526
Supplemental Steam $226 232 238 244 251 252 265 272 280
Chilling Steam $55 57 59 60 62 63 65 67 69
True-up Steam $5 5 5 5 5 5 6 6 6
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $29,988 31,543 33,258 35,069 37,010 39,093 39,946 40,803 41,684
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616 11,457 12,468 12,915 13,351
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913 900 980 1,015 1,049
Natural Gas Service Fees (55) $211 214 217 220 223 226 229 232 235
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033 2,087 2,144 2,202 2,261
Major Maintenance (57) $245 2,799 259 266 0 4,887 288 296 304
Other Operating Fees/Water (56) $594 610 626 643 661 678 697 716 735
Audit, Legal & Finance (56) $16 17 17 17 18 18 19 19 20
Insurance (56) $210 216 222 228 234 240 247 254 260
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162 1,193 1,225 1,258 1,292
Capital Expenditures (56) $40 40 40 40 40 40 40 40 40
Wheeling (58) $957 957 957 957 957 957 957 957 957
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $16,011 19,060 17,033 17,571 17,857 22,683 19,294 19,904 20,504
NET OPERATING REVENUES ($000) $13,977 12,483 16,225 17,498 19,153 16,410 20,652 20,899 21,180
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $13,977 12,483 16,225 17,498 19,153 16,410 20,652 20,899 21,180
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $13,977 12,483 16,225 17,498 19,153 16,410 20,652 20,899 21,180
</TABLE>
B-80
<PAGE>
Footnotes to Exhibit B-9
The footnotes to Exhibit B-9 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices consistent with the SCE High SRAC case as described in the
Henwood Report.
53. Assumes prices consistent with the SCE High SRAC case as described in the
Henwood Report.
B-81
<PAGE>
Exhibit B-10
CE Generation Gas Projects
Projected Operating Results
Sensitivity I: Yuma Breakeven Electricity Price
<TABLE>
<CAPTION>
Year Ending December 31 1999(1) 2000 2001 2002 2003 2004 2005 2006 2007
------- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 1,300 1,300 1,300 1,300 1,300 1,800 1,800 1,800 1,800
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 89.3% 89.3% 89.3% 89.3% 89.3% 83.4% 83.4% 83.4% 83.4%
Energy Generated (MWh)(42) 391,300 391,300 391,300 391,300 391,300 365,100 365,100 365,100 365,100
Transmission Losses (MWh)(45) 3,900 3,900 3,900 3,900 3,900 3,700 3,700 3,700 3,700
Energy Delivered (MWh) 387,400 387,400 387,400 387,400 387,400 361,400 361,400 361,400 361,400
Process Steam Sales (Mlb)(46) 49,500 49,500 49,500 49,500 49,500 46,200 46,200 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 9,200 9,200 9,200 9,200 9,200 11,900 11,900 11,900 11,900
Chilling Steam Demand (Mlb)(46) 116,500 116,500 116,500 116,500 116,500 108,700 108,700 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 3,474 3,474 3,474 3,474 3,474 3,248 3,248 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $0.00 0.00 0.00 3.40 7.80 11.30 14.40 12.60 14.90
Process Steam Price ($/Mlb)(51) $7.81 8.01 8.22 8.44 8.65 8.88 9.11 9.35 9.63
Supplemental Steam Price ($/Mlb)(51) $10.42 10.68 10.96 11.25 11.54 11.84 12.15 12.47 12.84
Chilling Steam Price ($/Mlb)(52) $0.43 0.44 0.45 0.57 0.72 0.85 0.96 0.92 1.00
True-up Steam Price ($/Mlb)(52) $0.11 0.11 0.11 0.14 0.18 0.21 0.24 0.23 0.25
Natural Gas Price ($/MMBtu)(53) $2.15 2.23 2.31 2.40 2.48 2.57 2.67 2.77 2.89
Gas Transportation Cost ($/MMBtu)(53) $0.23 0.23 0.24 0.25 0.25 0.26 0.27 0.27 0.28
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $0 0 0 1,317 3,022 4,084 5,204 4,554 5,385
Steam Revenue
Process Steam $387 397 407 418 428 410 421 432 445
Supplemental Steam $96 98 101 103 106 141 145 148 153
Chilling Steam $50 51 53 67 84 92 104 99 109
True-up Steam $4 4 5 6 7 8 9 8 9
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $8,733 8,746 8,762 10,107 11,843 12,931 14,079 13,437 14,297
OPERATING EXPENSES ($000)
Natural Gas $8,251 8,546 8,852 9,175 9,498 9,198 9,526 9,864 10,283
Natural Gas Use/Sales Taxes (54) $648 672 696 721 746 723 749 775 808
Natural Gas Service Fees (55) $182 185 187 190 192 195 198 200 203
Operating & Maintenance (56) $1,363 1,400 1,438 1,476 1,516 1,557 1,599 1,642 1,687
Major Maintenance (57) $183 3,278 193 198 2,262 209 215 0 3,950
Other Operating Fees/Water (56) $443 455 467 480 493 506 520 534 548
Audit, Legal & Finance (56) $762 12 13 13 13 14 14 14 15
Insurance (56) $157 161 166 170 175 179 184 189 194
Property & Other Taxes (56) $779 800 822 844 867 890 914 939 964
Capital Expenditures (56) $179 9 6 23 40 40 40 40 40
Wheeling (58) $963 963 963 963 963 961 961 961 961
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,910 16,481 13,803 14,253 16,765 14,472 14,920 15,158 19,653
NET OPERATING REVENUES ($000) ($5,177) (7,735) (5,041) (4,146) (4,922) (1,541) (841) (1,721) (5,356)
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $0 0 0 0 0 0 0 0 0
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $0 0 0 0 0 0 0 0 0
Year Ending December 31 2008 2009
---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000
Curtailment Hours (41) 1,800 1,800
Availability Factor (42) 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0%
Capacity Factor (%)(44) 83.4% 83.4%
Energy Generated (MWh)(42) 365,100 365,100
Transmission Losses (MWh)(45) 3,700 3,700
Energy Delivered (MWh) 361,400 361,400
Process Steam Sales (Mlb)(46) 46,200 46,200
Supplemental Steam Sales (Mlb)(46) 11,900 11,900
Chilling Steam Demand (Mlb)(46) 108,700 108,700
Heat Rate (Btu/kWh)(42) 8,830 8,830
Fuel Consumption (BBtu)(47) 3,248 3,248
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) 163.92 163.92
Energy Rate ($/MWh)(50) 9.20 12.90
Process Steam Price ($/Mlb)(51) 9.85 10.11
Supplemental Steam Price ($/Mlb)(51) 13.14 13.48
Chilling Steam Price ($/Mlb)(52) 0.84 0.97
True-up Steam Price ($/Mlb)(52) 0.21 0.24
Natural Gas Price ($/MMBtu)(53) 2.97 3.08
Gas Transportation Cost ($/MMBtu)(53) 0.29 0.30
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment 7,000 7,000
Bonus Capacity Payment 1,196 1,196
Energy Payment 3,325 4,662
Steam Revenue
Process Steam 455 467
Supplemental Steam 156 160
Chilling Steam 91 105
True-up Steam 8 9
------ ------
Total Operating Revenues 12,231 13,599
OPERATING EXPENSES ($000)
Natural Gas 10,579 10,952
Natural Gas Use/Sales Taxes (54) 831 861
Natural Gas Service Fees (55) 206 209
Operating & Maintenance (56) 1,732 1,779
Major Maintenance (57) 233 239
Other Operating Fees/Water (56) 563 578
Audit, Legal & Finance (56) 15 16
Insurance (56) 200 205
Property & Other Taxes (56) 990 1,017
Capital Expenditures (56) 40 40
Wheeling (58) 961 961
------ ------
Total Operating Expenses 16,350 16,857
NET OPERATING REVENUES ($000) (4,119) (3,258)
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) 0 0
DISTRIBUTIONS TO
CE GENERATION ($000)(59) 0 0
</TABLE>
B-82
<PAGE>
Exhibit B-10
CE Generation Gas Projects
Projected Operating Results
Sensitivity I: Yuma Breakeven Electricity Price
<TABLE>
<CAPTION>
Year Ending December 31 2010 2011 2012 2013 2014 2015 2016 2017 2018
---- ---- ---- ---- ---- ---- ---- ---- ----
YUMA PROJECT
PERFORMANCE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Nameplate Capacity (kW)(39) 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500 56,500
Contract Firm Capacity (kW)(40) 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000
Curtailment Hours (41) 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600 2,600
Availability Factor (42) 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0% 96.0%
On-Peak Availability Factor (43) 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0% 92.0%
Capacity Factor (%)(44) 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8% 73.8%
Energy Generated (MWh)(42) 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100 323,100
Transmission Losses (MWh)(45) 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200 3,200
Energy Delivered (MWh) 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900 319,900
Process Steam Sales (Mlb)(46) 40,900 40.900 40,900 40,900 40,900 40,900 40,900 40,900 40,900
Supplemental Steam Sales (Mlb)(46) 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300 16,300
Chilling Steam Demand (Mlb)(46) 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200 96,200
Heat Rate (Btu/kWh)(42) 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830 8,830
Fuel Consumption (BBtu)(47) 2,886 2,886 2,886 2,886 2,886 2,886 2,886 2,886 2,886
COMMODITY PRICES
General Inflation (%)(7) 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70 2.70
Electricity Price
Capacity Price ($/kW-yr)(48) $140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00 140.00
Bonus Capacity Price ($/kW-yr)(49) $163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92 163.92
Energy Rate ($/MWh)(50) $22.70 20.80 17.00 21.00 17.20 19.70 19.50 21.80 19.20
Process Steam Price ($/Mlb)(51) $10.38 10.66 10.95 11.25 11.56 11.59 12.20 12.53 12.86
Supplemental Steam Price ($/Mlb)(51) $13.84 14.21 14.60 15.00 15.41 15.45 16.26 16.71 17.15
Chilling Steam Price ($/Mlb)(52) $1.29 1.25 1.14 1.29 1.18 1.28 1.29 1.38 1.32
True-up Steam Price ($/Mlb)(52) $0.32 0.31 0.29 0.32 0.30 0.32 0.32 0.35 0.33
Natural Gas Price ($/MMBtu)(53) $3.19 3.31 3.43 3.56 3.69 3.62 3.97 4.11 4.25
Gas Transportation Cost ($/MMBtu)(53) $0.30 0.31 0.32 0.33 0.34 0.35 0.36 0.37 0.38
OPERATING REVENUES ($000)
Revenue from Electricity Sales
Firm Capacity Payment $7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000 7,000
Bonus Capacity Payment $1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196 1,196
Energy Payment $7,262 6,654 5,438 6,718 5,502 6,302 6,238 6,974 6,142
Steam Revenue
Process Steam $425 436 448 460 473 474 499 512 526
Supplemental Steam $226 232 238 244 251 252 265 272 280
Chilling Steam $124 120 110 124 114 123 124 133 127
True-up Steam $11 10 9 11 10 10 11 11 11
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $16,244 15,648 14,439 15,753 14,546 15,357 15,333 16,098 15,282
OPERATING EXPENSES ($000)
Natural Gas $10,075 10,439 10,817 11,209 11,616 11,457 12,468 12,915 13,351
Natural Gas Use/Sales Taxes (54) $792 820 850 881 913 900 980 1,015 1,049
Natural Gas Service Fees (55) $211 214 217 220 223 226 229 232 235
Operating & Maintenance (56) $1,827 1,876 1,927 1,979 2,033 2,087 2,144 2,202 2,261
Major Maintenance (57) $245 2,799 259 266 0 4,887 288 296 304
Other Operating Fees/Water (56) $594 610 626 643 661 678 697 716 735
Audit, Legal & Finance (56) $16 17 17 17 18 18 19 19 20
Insurance (56) $210 216 222 228 234 240 247 254 260
Property & Other Taxes (56) $1,044 1,072 1,101 1,131 1,162 1,193 1,225 1,258 1,292
Capital Expenditures (56) $40 40 40 40 40 40 40 40 40
Wheeling (58) $957 957 957 957 957 957 957 957 957
------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $16,011 19,060 17,033 17,571 17,857 22,683 19,294 19,904 20,504
NET OPERATING REVENUES ($000) $233 (3,412) (2,594) (1,818) (3,311) (7,326) (3,961) (3,806) (5,222)
CASH AVAILABLE
FOR DISTRIBUTIONS ($000) $233 0 0 0 0 0 0 0 0
DISTRIBUTIONS TO
CE GENERATION ($000)(59) $233 0 0 0 0 0 0 0 0
</TABLE>
B-83
<PAGE>
Footnotes to Exhibit B-10
The footnotes to Exhibit B-10 are the same as the footnotes for Exhibit
B-1, except:
50. Assumes prices projected by Fluor Daniel which result in a debt
service coverage ratio on the Securities of 1.00 in all years.
B-84
<PAGE>
APPENDIX C
GEOTHERMAL PROJECTS
INDEPENDENT ENGINEER'S REPORT
CE GENERATION PROJECT ANALYSIS
PREPARED FOR
CE GENERATION, LLC
FEBRUARY 17, 1999
FLUOR DANIEL, INC.
IRVINE, CALIFORNIA
C-1
<PAGE>
TABLE OF CONTENTS
1.0 EXECUTIVE SUMMARY AND CONCLUSIONS .................................. 3
1.1 EXECUTIVE SUMMARY .................................................. 3
1.2 CONCLUSIONS ........................................................ 6
2.0 SCOPE OF SERVICES .................................................. 9
3.0 FACILITIES OVERVIEW ................................................ 10
3.1 GENERAL DESCRIPTION ................................................ 10
3.2 MANAGEMENT AND ORGANIZATION ........................................ 11
3.3 SALTON SEA PROJECTS ................................................ 12
3.4 PARTNERSHIP PROJECTS ............................................... 13
3.5 ROYALTY PROJECTS ................................................... 13
3.6 pH MODIFICATION PROCESS ............................................ 13
4.0 NEW PROJECTS ....................................................... 13
4.1 GENERAL DESCRIPTION -- SALTON SEA UNIT V PROJECT ................... 13
4.2 GENERAL DESCRIPTION -- REGION II BRINE FACILITIES CONSTRUCTION ..... 14
4.3 MATERIALS OF CONSTRUCTION .......................................... 15
4.4 NEW PROJECTS MANAGEMENT ORGANIZATION ............................... 15
4.5 PROJECT SITE GEOTECHNICAL DESCRIPTION .............................. 15
4.6 SCHEDULE ........................................................... 16
4.7 CAPITAL COST ANALYSIS .............................................. 17
5.0 PROJECT OPERATIONS ................................................. 17
6.0 PERMITTING AND ENVIRONMENTAL ....................................... 17
6.1 ENVIRONMENTAL COMPLIANCE ........................................... 17
6.2 APPLICABLE ENVIRONMENTAL PERMIT AND LICENSING REQUIREMENTS ......... 18
6.3 ENVIRONMENTAL REQUIREMENT COMPLIANCE, DEFICIENCIES AND
LIMITATIONS ........................................................ 18
7.0 ASSESSMENT OF FINANCIAL PROJECTIONS ................................ 18
7.1 BASE CASE PROJECTION ASSUMPTIONS ................................... 18
C-2
<PAGE>
SECTION 1.0
1.0 EXECUTIVE SUMMARY AND CONCLUSIONS
1.1 EXECUTIVE SUMMARY
Fluor Daniel, Inc. (Fluor Daniel) prepared an Independent Engineer's
report for the Salton Sea Funding Corporation, dated September 23, 1998, in
connection with Salton Sea Funding Corporation's Bond Offering Circular (the
Salton Sea Project Analysis). The analysis and conclusions contained in that
report are incorporated herein, except as hereinafter modified. Specifically,
CE Generation, LLC has requested Fluor Daniel to update the Salton Sea Project
Analysis to remove references to the Zinc Recovery Project and to report on the
construction status of Salton Sea Unit V and the CE Turbo Project (hereinafter
the Updated Events).
Presented herein is Fluor Daniel's, review and analyses (the Report) of
eight operating geothermal power plants (the Existing Projects), and two new
geothermal power plants (the New Projects), as listed below. The geothermal
resource production facilities (wellheads and related brine delivery system)
were not reviewed by Fluor Daniel.
o Salton Sea Units I, II, III and IV, including brine modification (pH
Modification) and a planned capacity increase via a new Salton Sea
Unit V (collectively the Salton Sea Projects).
o Vulcan, Del Ranch, Elmore and Leathers, including the Region II Brine
Facilities Construction, the CE Turbo Project (collectively the
Partnership Projects).
o Royalty and other payments received from the Del Ranch, Elmore, and
Leathers Projects (the Royalty Projects). The Salton Sea Projects,
Partnership Projects and the Royalty Projects are collectively
referred to herein as the Projects.
NEW PROJECTS -- OVERVIEW
Salton Sea Power LLC (Power LLC) is constructing a 49.0 MW net geothermal
power plant (Salton Sea Unit V Project) using proven technology designed to
produce electrical energy primarily from the Salton Sea Region I injection
brine. This brine is currently reinjected and contains over 40 MW of available
thermal energy to be used by Salton Sea Unit V. Additional power will be
produced utilizing minimal increased brine flows through the existing brine
handling facilities located at the Salton Sea Projects. Therefore, Salton Sea
Unit V will produce electrical energy by increasing the thermal efficiency of
Region I with only a limited increase in the quantity of brine production, as
well as providing a consistent supply of brine suitable for the ion exchange
zinc recovery process.
The Region II Brine Processing Construction will include the installation
of modern brine processing facilities to service the total brine flow to be
provided to Vulcan and Del Ranch. It is intended that these facilities will be
designed with the appropriate technology, developed and proven at the Salton
Sea, to provide for reliable steam production for power generation, and a
consistent supply of brine suitable for the ion exchange zinc recovery process.
CE Turbo LLC is constructing the CE Turbo Project which is designed to
provide electrical power output of 10.0 MW net. This power output will result
from increased efficiencies in the steam field and brine handling facilities
and no new production or injection wells are required.
C-3
<PAGE>
A summary overview of the current and intended features of the Projects is
presented in Table 1-1.
TABLE 1-1
OVERVIEW OF THE PROJECTS
<TABLE>
<CAPTION>
FACILITY (1) NET
NET OWNERSHIP COMMERCIAL POWER
CAPACITY INTEREST OPERATION CONTRACT CONTRACT POWER
(MW) (MW) (YEARS) EXPIRATION TYPE PURCHASER
-------------- ----------- ------------ ------------ ------------ ---------------
<S> <C> <C> <C> <C> <C> <C>
SALTON SEA PROJECTS
Salton Sea Unit I ....... 10.0 10.0 16 6/2017 Negotiated SCE
Salton Sea Unit II ...... 20.0 20.0 8 4/2020 SO4 SCE
Salton Sea Unit III ..... 49.8 49.8 9 2/2019 SO4 SCE
Salton Sea Unit IV ...... 39.6 39.6 2 5/2026 Negotiated SCE
Salton Sea Unit V ....... 49.0 49.0 0 N/A SPOT Zinc Recovery
----- ----- Project and PX
Subtotal ............... 168.4 168.4
PARTNERSHIP PROJECTS
Elmore .................. 38.0 38.0 10 12/2018 SO4 SCE
Del Ranch ............... 38.0 38.0 10 12/2018 SO4 SCE
Leathers ................ 38.0 38.0 8 12/2019 SO4 SCE
Vulcan .................. 34.0 34.0 12 2/2016 SO4 SCE
CE Turbo ................ 10.0 10.0 0 N/A N/A PX
----- -----
Subtotal ............... 158.0 158.0
===== =====
Total ................... 326.4 326.4
</TABLE>
- ----------
(1) Power Project capacity is a nominal number that varies with operating and
reservoir conditions.
PROJECT LOCATION
The Salton Sea and Partnership Projects are located in Imperial County
California in the Salton Sea Area. A map showing the general location of the
Projects is provided in Figure 1-1.
C-4
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FIGURE 1-1
PLANT LOCATION MAP
[MAP SHOWING THE GENERAL LOCATION OF THE PROJECTS]
GEOTHERMAL PROJECT AGREEMENTS
As shown in Table 1-1, the Existing Projects sell power to Southern
California Edison Company (SCE) in accordance with power purchase agreements
and related agreements for transmission system interconnection. Salton Sea Unit
V will sell approximately one-third of its net output to the CalEnergy Minerals
LLC Zinc Recovery Project and also sell power through the Power Exchange (PX).
CE Turbo will sell all its power through the PX.
It is understood that the Salton Sea and Partnership Projects are, and
will continue to be, operated by CalEnergy Operating Corporation (CEOC). The
Existing Projects have been in commercial operation for numerous years.
Construction of a portion of the facilities is being performed under
Engineering, Procurement and Construction (EPC) contracts, with completion and
cost guarantees. The Salton Sea Unit V, CE Turbo and Region II Brine Processing
Construction Projects are being constructed by Stone and Webster Engineering
Corporation (S&W) under two separate guaranteed price contracts.
GEOTHERMAL PROJECT PARTICIPANTS
The Salton Sea Units I, II and III are owned by Salton Sea Power
Generation L.P. (SSPG). SSPG and Fish Lake Power Company (FLPC) are owners of
the Salton Sea Unit IV Project. Salton Sea
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Unit V will be owned by Salton Sea Power L.L.C. (Power LLC). SSPG, SSBP FLPC,
and Power LLC are referred to collectively as the "Salton Sea Guarantors".
The improvements to the brine processing facility part of the Region II
Brine Processing Construction will be owned by certain of the Existing
Projects. The CE Turbo Project will be owned by CE Turbo LLC. Agreements were
reviewed that indicate that the Salton Sea Royalty Company (the Royalty
Guarantor) receives royalties and other payments from Leathers, Elmore, and Del
Ranch.
SCHEDULE
The commercial operation date for Salton Sea Unit V is currently scheduled
for mid 2000. The commercial operation dates for the CE Turbo Project and the
Region II Brine Processing Construction are currently scheduled for the first
half of 2000.
1.2 CONCLUSIONS
On the basis of Fluor Daniel's review of the information provided by CE
Generation (CEG), and in reliance thereon, Fluor Daniel provides the following
opinions:
1.2.1 EXISTING PROJECTS -- OPERATIONS AND PERFORMANCE
o The Projects use commercially proven technology and are operated in
accordance with recognized electric utility industry practices.
o The useful life of the surface facilities are expected to exceed the
final maturity date of the debt Securities.
o Principal project participants possess the necessary experience to
successfully fulfill their project obligations.
o Operating plant capacity factors (expected forced and scheduled
outages) used in the projections are based on the operating results
for the operating years 1995, 1996, 1997 and 1998, and these are felt
to be reasonable. For the years 1995 through 1998, selected highlights
of the operating history reported by the CEG are as follows:
o Revenue increased 83 percent.
o Site operating costs decreased from 3.53 cents/net kWh to 1.77
cents/net kWh for the Salton Sea Units I-IV Projects, and from
3.17 cents/net kWh to 2.19 cents/net kWh for the Partnership
Projects. For the Existing Projects as a whole, operating costs
decreased from 3.28 cents/net kWh to 2.01 cents/net kWh.
o Nominal capacity factors in 1998 were maintained at 94.2 percent
for the Salton Sea I-IV Projects, 101.4 percent for the
Partnership Projects, and 98.2 percent on a combined basis.
o The pH Modification technology is proven and reliable, as has been
shown by the eight year operating history at Salton Sea Unit II and
the two years of operating history of this technology at Salton Sea
Units I, III, and IV. The pH Modification program should continue to
increase availability and decrease costs consistent with assumptions
in the financial projections.
o The Existing Projects are expected to continue operations in
accordance with all relevant existing permits and environmental laws.
1.2.2 NEW PROJECTS
SALTON SEA UNIT V
o The technology upon which the Salton Sea Unit V is based, is proven
and reliable. The scope of work is within demonstrated capabilities of
the principal project participants. The EPC
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contract for the Salton Sea Unit V Project provides for a guaranteed
completion date. It appears that the completion of the Salton Sea Unit
V Project can be achieved within the guaranteed date in the EPC
contract.
o The pH Modification technology is proven and reliable. Similar
technology has been installed and has operated successfully throughout
Salton Sea Units I -- IV. As demonstrated by the eight year operating
history at Salton Sea Unit II, and the more recent operating history
of Salton Sea Units I, III, and IV, the pH Modification program should
continue to operate at the same or improved levels of reliability.
o Reasonable selections have been made in selecting the EPC Contractor
for this work, and in preparing the list of equipment suppliers. Major
equipment suppliers approved by Power LLC are recognized as qualified
suppliers in the geothermal power industry.
o The Salton Sea Unit V Project should meet the guaranteed performance
criteria contained in the EPC contracts and should comply with all
applicable environmental regulations.
o Based upon a review of the EPC contract for the Salton Sea Unit V
Project, the capital cost budget appears adequate for the facilities
provided under the contract. The guaranteed price in the S&W contract,
plus S&W's substantial prior experience with geothermal plants, should
mitigate the risk of cost overruns and schedule delays, and should
thus adequately protect both the Bondholders and Owners. Power LLC
should have adequate Contractor resources available to cover the
possibility of performance shortfalls by S&W for the Salton Sea Unit V
Project . The contractual Liquidated Damages provisions provided in
the EPC contract are typical for securing contractor completion of
projects utilizing proven technology such as that utilized on the
Salton Sea Unit V Project.
o Construction on the Salton Sea V Project has just started with
grubbing and site clearing. At this point construction appears to be
on schedule. The Permit-to-Construct for this work is also in place.
o Based on Fluor Daniel's knowledge of conventional power project
financing, Owner's costs, such as administration costs, insurance,
financing costs, contingency funds, working capital, etc., estimated
by the Power LLC appear to be reasonable.
o All discretionary permit approvals have been obtained for
construction.
o The useful life of the Salton Sea Unit V Project can be expected to
exceed the final maturity date of the Securities.
REGION II BRINE PROCESSING CONSTRUCTION
o The technology upon which brine processing is based has been
demonstrated to be proven and reliable. The EPC contract for the
Region II Brine Processing Construction provides for a guaranteed
completion date. It appears that the completion of the Region II Brine
Processing Construction can be achieved within the guaranteed date in
the EPC contract.
o The pH Modification technology has been demonstrated to be proven and
reliable at the Existing Projects. Similar technology has been serving
Salton Sea Units I -- V and has a proven operating history. The pH
Modification system should increase availability and decrease
operating costs and maintenance consistent with assumptions in the
financial projections.
o Reasonable selections have been made in selecting the EPC Contractor
for this work, and in preparing the list of equipment suppliers. Major
equipment suppliers approved for this project are recognized as
qualified suppliers in the geothermal field.
o A review of the EPC contract for the Region II Brine Processing
Construction provided confidence that the capital cost budget should
be adequate for the facilities provided under the contract. The
guaranteed price in the S&W EPC contract, plus S&W's substantial prior
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experience with geothermal installations, should mitigate the risk of
cost overruns and schedule delays. The contractual Liquidated Damage
provisions in the EPC contract are typical for securing contractor
completion of projects utilizing proven technology such as that
utilized, and should adequately protect both the Bondholders and the
Owners.
o The Region II Brine Processing Construction should meet the guaranteed
performance criteria contained in the EPC contract and should comply
with all applicable environmental regulations.
o All discretionary permit approvals have been obtained for
construction.
o Construction on the Region II Brine Processing Project has yet to
begin, but is scheduled to begin as planned. A Permit-to-Construct for
this work is in place.
CE TURBO PROJECT
o The CE Turbo Project uses technology which has been demonstrated to be
proven and reliable. The scope of work is within demonstrated
capabilities of the principal project participants which should make
the currently scheduled completion during the first quarter of 2000
achievable.
o The EPC Contract for the Region II Brine Processing Construction,
which also encompasses the CE Turbo Project provides for a guaranteed
completion date. It appears that the completion of the CE Turbo
Project can be achieved within the guaranteed date in the EPC
contract.
o S&W, the EPC contractor for this work, is recognized as an experienced
contractor in this field. The major equipment suppliers that have been
approved for S&W's selection are recognized as qualified suppliers to
the industry.
o The CE Turbo Project should meet the guaranteed performance criteria
contained in the EPC contract and should comply with all current
applicable environmental regulations.
o On the basis of the EPC contract reviewed for the CE Turbo Project,
the capital cost budget appears adequate for the facilities provided
under those contracts. The guaranteed price in the S&W contract, plus
S&W's substantial prior experience with geothermal power plants,
should mitigate the risk of cost overruns and schedule delays. CE
Turbo LLC should have adequate contractor resources available to cover
the possibility of performance shortfalls by S&W for the CE Turbo
Project. The contractual Liquidated Damages provisions in the EPC
contract are typical for securing contractor completion of projects
utilizing proven technology such as that utilized in CE Turbo Project,
and should adequately protect both the Bondholders and the Owners.
o Based on Fluor Daniel's knowledge of conventional power project
financing, the Owner's costs, such as administration costs, insurance,
financing costs, contingency funds, working capital, etc., estimated
by CE Turbo LLC appear to be reasonable.
o All required discretionary permit approvals have been obtained for the
construction of the CE Turbo Project.
o The useful life of the CE Turbo Project can be expected to exceed the
final maturity date of the Securities.
o Construction on the CE Turbo Project has yet to begin, but is
scheduled to begin as planned. The Permit-to-Construct for this work
is in place.
ENVIRONMENTAL PERMITTING AND LICENSING
o The reviewed records show no environmental Notices of Violation for
any media (air emissions, wastewater, solid/hazardous waste) have been
filed against the Existing Projects in the last two years.
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o The Existing Projects appeared to be neat and well maintained.
o The H2S abatement systems consist of existing biofilters for Salton
Sea Units I, II, III and IV. A review of the preliminary design
indicated that sufficient capacity appears to exist to handle any
anticipated increase of H2S loads resulting from the operation of
Salton Sea Unit V.
o The water and brine pond designs appear adequate to minimize or
eliminate the potential for water and brine release into the
underlying soil and groundwater.
o Solid waste handling and disposal appears adequate.
o Dust control in the solid waste handling operation should be improved
by planned dust handling equipment and dust abatement measures.
o All discretionary environmental permit approvals have been received
for the proposed new construction.
PROJECT AGREEMENTS
o Major project agreements (as listed in Attachment 2-1) for the Salton
Sea Projects and Partnership Projects, including Power Purchase
agreements, EPC contracts, major subcontracts, Zinc Extraction
Services Agreement, O&M Services Agreement, and related contracts for
transmission system interconnection appear reasonable from a technical
perspective and are consistent with the financial projections reviewed
herein.
FINANCIAL PROJECTIONS
o An economic/financial model, presented in Exhibit 1, has been
developed by CEG which represents the projected performance of the
Salton Sea and Partnership Projects. The assumptions underlying the
economic/financial model appear to be reasonable, and the projected
operating results reasonably represent the future financial profile of
CEG.
o Fluor Daniel has confirmed that the input assumptions regarding
revenues in the Imperial Valley model are reasonably consistent with
the Power Purchase and Royalty documents provided to Fluor Daniel.
o Projected operating and maintenance costs and capital expenditures for
major maintenance projects appear to be reasonable and representative
of the planned operations of the Salton Sea and Partnership Projects.
o Financial projections, based on the Base Case assumptions recommended
by CEG, appear to be reasonable and indicate that revenues should be
adequate to pay operations and maintenance expenses and provide cash
flow for debt service and distributions.
SECTION 2.0
2.0 SCOPE OF SERVICES
On the basis of information and documents provided by CEG, Fluor Daniel,
as Independent Engineer, has reviewed certain technical, environmental and
economic aspects of the Projects as listed below:
o Current status of Existing Projects
o Project participants
o Plant designs and projected performance
o Project capital cost estimates
o Operations and maintenance
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o Project agreements
o Environmental permitting and licensing
o Financial projections (Exhibit 1)
o Project completion testing
Fluor Daniel conducted this analysis, and prepared this report, utilizing
reasonable care and skill in applying methods of analysis consistent with
normal industry practice. In the preparation of this report and the opinions
expressed, Fluor Daniel 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 Fluor Daniel in the preparation of
this report are provided in Attachment 2-1. The information set forth herein
has been obtained from sources which are believed to be reliable, but it is not
guaranteed as to accuracy or completeness by, and is not construed as a
representation by, Fluor Daniel or the Project sponsors.
SECTION 3.0
3.0 FACILITIES OVERVIEW
3.1 GENERAL DESCRIPTION
The Existing Projects consist of eight operating geothermal power plants
near the Salton Sea in the Imperial Valley of Southern California. These plants
produce net power generation of approximately 288 MW from high temperature
geothermal brines produced by drilling deep production wells into the Salton
Sea Known Geothermal Resource Area (SSKGRA). Imperial Valley brines are
characterized by heavy concentrations of compounds of silica, zinc, manganese
and other metals. Over twenty million pounds of brine per hour are produced and
flashed to supply the steam for electric power generation. After the brine is
flashed to produce steam, it is reinjected into the subsurface reservoir
through separate injection wells constructed for that purpose.
As mentioned above, the Salton Sea and Partnership Projects are located in
the SSKGRA and are within a central radius of approximately five miles. A
representative map showing approximate plant locations is provided in Figure
1-1.
Hot brine from the geothermal resource is flashed into high pressure,
standard pressure, and low pressure steam which is expanded through steam
turbine generators to produce electric power. The steam is condensed and then
used for cooling tower make-up. Excess condensate is injected back into the
geothermal reservoir. Brine from the steam flash process is further processed
to remove solids, or maintain them in solution, and is injected back into the
geothermal reservoir. The Existing Projects employ proven geothermal resource
flash technology which has been commercially operated worldwide for over 30
years.
Plant design and operation are affected by the geothermal resource which,
in the SSKGRA, is relatively high in solids content at approximately 250,000 to
300,000 parts per million. Leathers, Elmore, Del Ranch, and Vulcan utilize the
crystallizer-reactor-clarifier (CRC) process to control scaling and to
precipitate solids. The majority of the solids are disposed of in an
appropriately licensed landfill and the remainder are recycled to the
crystallizers to promote crystal growth (seeding) to control scaling on vessel
walls.
Salton Sea Units I, II, III, and IV utilize the pH Modification process to
control scaling. This process involves injection of a pH modification agent
into the liquid brine resource to maintain solids in solution so that the brine
may be injected directly into the reservoir without precipitation and removal
of the solids. Implementation of this process as part of the Region II Brine
Processing Construction is expected to simplify resource handling in a similar
fashion, thus improving availability and reducing costs.
Noncondensible gases from the Existing Projects are removed from the
condensers for efficient power generation and turbine operation using a
combination of steam jet ejectors and vacuum pumps.
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Systems for abatement of hydrogen sulfide present in the noncondensible gases
are not currently required for the Partnership Projects since ambient hydrogen
sulfide concentrations are at acceptable levels. However, hydrogen sulfide
abatement systems were installed for Salton Sea Units I, II, III and IV as part
of an earlier Salton Sea expansion project. The technology for such abatement
systems is proven and reliable.
The cooling systems for all operating projects consist of surface
condensers and wet mechanical draft cooling towers. Utility systems are
provided to support each operating plant. Fire protection systems are also
provided, including cooling tower wetdown systems which keep the tower wet
during shutdown periods, and fire monitors which are provided at grade around
the perimeter of each tower. Standby diesel generators are available to support
plant safety systems during shutdowns.
Brine is injected into the reservoir by injection pumps after solids
processing. Brine ponds are provided at each plant for temporary storage of
brine during startup/shutdown periods and for emergency use.
3.2 MANAGEMENT AND ORGANIZATION
An Operations Manager is responsible for operations, maintenance, and
plant performance of the Existing Projects. The Salton Sea Projects, Vulcan and
Del Ranch, and Elmore and Leathers each have a Region Supervisor who is
responsible for operations, maintenance, and plant performance. The plant's
Control Operators are trained to operate the plants, perform routine lab tests
and supervise the Outside Operators. The plant's onsite staff is trained to
conduct routine maintenance activities.
In support of these Project sites, CEOC provides centralized
administrative support, engineering support, maintenance support, and
analytical lab support. A Maintenance Supervisor is responsible for the
Mechanics as well as the Instrument and Electrical Technicians. When additional
manpower is required at the Project sites, the Central Maintenance shop
provides the necessary staff. This organization and staffing procedure is
typical for these types of plants.
Fluor Daniel is of the opinion that the overall operating and maintenance
organization is adequate to support operation of the Salton Sea and Partnership
Projects and should continue to provide operating and maintenance cost
reductions.
SAFETY
CEOC has an established safety program based on a Corporate Safety Manual
and Imperial Valley Site Specific Safety Procedures. These safety procedures
appear to be generally consistent with general industry practices.
CEOC is staffed with a Safety Manager and two Safety Engineers. All are
trained in Safety procedures as well as environmental response, pursuant to
stated procedures. The Safety personnel conduct ongoing safety reviews at each
of the Project sites and monthly training sessions for all-hands. These
sessions are designed to emphasize compliance with current CEOC Safety
Procedures in place and to convey new safety procedures and execution methods.
CEOC utilizes a "Safe Work Permit" procedure that must be implemented by
maintenance and operating personnel prior to starting any work. CEOC also has a
plant lockout/tagout procedure for isolating systems for maintenance and
personnel protection.
All procedures were found to be sound and in line with safety procedures
normally found in this type of industry.
TRAINING
CEOC has a very comprehensive training program, which includes Operator
and Maintenance Technician certification. There are five classifications of
Operators: Operator 1, 2, and 3, Control Operator, and Senior Operator. Each
classification, except Senior Operator, has a Certification
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Manual. The manual contents and associated tests have been developed in
accordance with CEOC's organizational structure. The certification program
includes written tests administered by the CEOC Training Department and a plant
walk-through test conducted by the Training Review Board.
The CEOC Senior Operator classification was recently implemented, but no
certification program is currently in place. A job description and
certification testing procedure is being prepared for this new classification
In Fluor Daniel's opinion, the program appears to be in line with training
programs found in the power industry.
OPERATING PROCEDURES
Operating Procedures are in place for the Salton Sea and Partnership
Projects. They included step-by-step methods for start-up, normal operation,
and shutdown of the Projects. Fluor Daniel is of the opinion that the operating
procedures are satisfactory.
MAINTENANCE PROGRAM
Maintenance at each plant is supervised by a Maintenance Supervisor. Most
of the routine maintenance is performed in the centralized maintenance shop
with specialty maintenance being performed by specialty contractors on a
subcontract basis. The Salton Sea and Partnership Projects are using a
commercially available Central Maintenance Management System (CMMS) software
package, which has reportedly improved management of plant maintenance
activities.
Since the Salton Sea Projects are using the pH modification process which
results in cleaner equipment than the CRC process, these plants are currently
on a four-year major turnaround cycle. Major turnarounds are generally
scheduled for twelve days and include process valve maintenance, cleaning, and
descaling of process pipe and vessels. Mini-outages (three to five days) are
scheduled each spring in preparation for the summer peak runs.
For the Partnership Projects, major overhaul planning is also performed by
Central Maintenance with input from the sites. Major twelve day overhauls are
scheduled every two years with mini-outages (three to five days) scheduled each
spring in preparation for the summer peak runs.
In all plants, specialized maintenance such as turbine overhaul and
electrical protective relay calibration is performed by outside contractors.
The plants historically operate reliably as a result of these maintenance and
overhaul scheduling practices.
Fluor Daniel's review of the plants during a site walk-through found the
plants to be well maintained. Plant personnel indicated that spare parts were
available when required.
3.3 SALTON SEA PROJECTS
Salton Sea Units I and II are located adjacent to the Salton Sea; the
shoreline has appropriate dikes and levies designed to protect these units from
increases in the Salton Sea water level. The dikes appear to be adequately
maintained. Salton Sea Unit III and IV are located approximately 0.5 miles from
the Salton Sea.
Salton Sea Unit I has been in service since 1982. Power generation
equipment consists of a 10 MW Fuji steam turbine operating with standard
pressure (SP) steam originally produced by CRC technology. This process also
produces high pressure (HP) and low pressure (LP) steam. The generation voltage
of 13.8 kV is stepped up to 34.5 kV for transmission to Southern California
Edison (SCE).
Salton Sea Unit II was placed in service in 1990. A total of three steam
turbines produce electrical power. Salton Sea Unit II was the original plant to
operate on the pH Modification process and has done so successfully for eight
years. The Mitsubishi turbine-generator produces electrical power at 4,160
volts which is stepped-up to 13.8 kV; the other generators produce power at
13.8 kV. One transformer steps-up power from these three generators to 92 kV
for transmission by the Imperial Irrigation District (IID) to the Rancho Mirage
substation for sale to SCE.
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Salton Sea Unit III is a 49.8 MW plant with a Mitsubishi turbine that
operates on SP and LP steam. The turbine is a 5-stage, dual flow, condensing
turbine. Three stages of steam jet air ejectors remove noncondensible gases
from the steam. Operational flexibility provided by steam jet air ejector
trains are used to respond to varying noncondensible gas content. Commercial
operation was declared on February 14, 1989. Power is stepped up to 92 kV for
transmission by the IID to the Rancho Mirage substation for sale to SCE.
Salton Sea Unit IV is a General Electric steam turbine generator installed
next to the Salton Sea Unit III site to provide additional capacity of 39.6 MW.
Salton Sea Unit IV's design involved modification of existing steam and brine
processing equipment and related systems. All of the steam used is processed
through this system.
3.4 PARTNERSHIP PROJECTS
The Vulcan Project was commissioned in February 1986. It generates
electrical power for transmission to SCE via IID lines. Noncondensible gases
are directed to the cooling tower using two stages of steam jet air ejectors
and a vacuum pump. Each of these components has at least one spare. A standby
diesel generator is available to provide emergency power. Solids precipitated
from the CRC process are monitored for metals concentrations and hauled by
truck to a permitted landfill. Covered solids storage is provided onsite on a
concrete slab for emergency purposes.
Electrical power is generated at 14.4 kV and is transmitted to SCE over 92
kV IID lines. The Del Ranch and the Vulcan Projects are connected via an
electrical tie-line.
The Del Ranch Project achieved commercial operation in October 1988. The
plant is very similar to the Vulcan Project. A dual pressure nine-stage Fuji
turbine produces electrical power for transmission to SCE via IID.
Commercial operation was achieved at the Elmore Project in December 1988
and at the Leathers Project in January 1990. These two plants are identical in
all major design respects to the Del Ranch Project, including the main turbine.
Three spare turbine rotors and two spare sets of diaphragms are available for
the Del Ranch, Elmore, and Leathers Projects.
3.5 ROYALTY PROJECTS
Magma receives royalties, fees and other payments ("Royalties") from the
Leathers, Del Ranch and Elmore Projects based on a percentage of each project's
annual revenue. Total Royalties from these Partnership Projects paid to Magma
annually are projected to be $21,766,000 in 1999, stepping down to $9,427,000
in 2000 as revenues from the three Partnership Projects revert to avoided cost
pricing. The Royalties from the Leathers, Del Ranch and Elmore Projects are
included in the financial projections.
3.6 PH MODIFICATION PROCESS
The pH Modification process currently used for Salton Sea Unit I, II, III
and IV lowers the pH of the geothermal resource by injection of a pH
modification agent into the liquid brine stream. As a result, solids remain in
solution rather than precipitate out of solution as in the CRC process
previously used at Salton Sea Units I and III, and at the Partnership Projects.
Therefore, scaling is minimized and solids in solution can be injected into the
reservoir. Certain aspects of the process were a proprietary process developed
by Unocal and subsequently licensed to Magma, which was purchased in 1995 by
CalEnergy. The pH Modification process has operated successfully since 1990.
SECTION 4.0
4.0 NEW PROJECTS
4.1 GENERAL DESCRIPTION -- SALTON SEA UNIT V PROJECT
4.1.1 DESIGN CONSIDERATIONS
The Salton Sea Unit V geothermal power plant (49.0 MW net) is being
designed to produce electrical energy from the spent brine that would otherwise
be reinjected following usage in Salton
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Sea Units I -- IV. This brine is currently reinjected at a temperature of
approximately 360 degreesF and at the current rate contains over 40 MW of
available thermal energy to be used by Salton Sea Unit V. Additional power will
be produced utilizing minimal increased brine flows through the existing Salton
Sea Units I -- IV brine handling facilities. Therefore, the Salton Sea Unit V
Project will produce electrical energy by significantly increasing the thermal
efficiency of existing brine usage with only a minor increase in the quantity
of brine production.
The Salton Sea Unit V Project will include a multiple inlet pressure
turbine utilizing standard pressure (SP) steam, low pressure (LP) steam, and
very low pressure (VLP) steam, operating at approximately 110/30/10 psig,
respectively. The SP steam will be provided from additional production from the
existing Region I facilities. The LP and VLP steam will be produced at the
Salton Sea Unit V Project by flashing the brine delivered from the Salton Sea
Units I -- IV brine processing facilities (producing LP steam) and subsequent
flashing of the brine (producing VLP steam). Other equipment necessary for the
Salton Sea Unit V Project includes a pH modification agent handling system, wet
cooling tower, surface condenser, non-condensable gas system, electrical
switchgear, and associated cooling water pumps, condensate pumps, and brine
pumps. Auxiliary equipment includes a lube oil system, expanding the existing
fire protection system, and plant air.
Salton Sea Units I -- IV are using pH Modification of the geothermal brine
to prevent precipitation of silica dissolved in the brine during the power
production cycle. The Salton Sea Unit V Project will utilize refinements in pH
Modification technology. Additional pH modification agent will be injected into
the brine prior to flashing/cooling the brine below 360 degreesF. This has been
shown to prevent precipitation of silica at the lower temperatures, which would
otherwise cause scaling/plugging of brine handling equipment. The brine will
then be flashed to produce LP and VLP steam for conversion into electrical
power. Just before being delivered to the Zinc Recovery Plant, the remaining
brine passes through an atmospheric flash/reactor vessel which removes residual
heat and most of the silica. The silica will initially be disposed of in a
licensed landfill but may later be marketed to potential consumers such as
cement and tire manufacturers.
The facilities will produce a significant quantity of steam as part of the
brine cooling process. A majority of this steam will normally be utilized by
Salton Sea Unit V, with very low pressure steam being used by the Zinc Recovery
Project as process heat.
4.2 GENERAL DESCRIPTION -- REGION II BRINE FACILITIES CONSTRUCTION
4.2.1 CE TURBO PROJECT
The CE Turbo Project is being designed to produce 10.0 MW net of
electrical power output. The CE Turbo Project will use existing unutilized
geothermal energy and additional geothermal energy made available through
efficiency improvements via the Region II Brine Processing Construction; no new
production or injection wells or associated pipelines will be required. The new
power generation will be transmitted through IID power lines.
The new turbine will be an Atlas Copco Rotoflow design. The system will
consist of a turbo-expander, a gearbox, and a generator coupled together in a
power delivery train. All auxiliary equipment required to operate the turbine
will be included in the package.
4.2.2 REGION II BRINE FACILITIES CONSTRUCTION
PROJECT SUMMARY
The Region II Brine Processing Construction upgrade project is installing
modern brine processing facilities designed to service the total brine flow now
provided to Vulcan and Del Ranch. This centralized brine plant will service the
total brine demand for both Vulcan and Del Ranch. These Facilities are being
designed with technology developed and proven at the Salton Sea Projects, to
provide steam production for power generation. Process design and equipment
specifications have been developed and are intended to minimize the long term
cost of plant operations. The existing
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brine gathering system, and upgraded cement lined production and injection
systems, should facilitate the conversion to a the new facilities. It is
intended that proven existing designs, and equipment where possible, will be
used to minimize cost, schedule and project risk.
SILICA CONTROL PROCESS
The silica control process for this development combines features common
to the pH Modification process and the CRC process. This process is designed to
be lower in capital cost and in projected operating cost than a traditional CRC
process. The pH Modification technology is designed to increase the service
interval between shutdowns of its respective equipment. This technology also
allows a smaller, more efficient standard pressure brine-steam separator vessel
to be used in place of the two SP crystallizers required for the current Region
II SP brine flow. Two low pressure crystallizer and atmospheric flash tank
trains, a primary clarifier, a secondary clarifier, filter press, and brine
booster pump system complete the major equipment. These are traditional CRC
components, but upgraded for long term reliability and performance.
H2S ABATEMENT
The high pressure steam from the turbo-expander will flow through various
standard pressure steam components to arrive at the SP Turbine's condenser,
where the additional noncondensible gas stream must be removed. An H2S
abatement unit will be added downstream of this condenser to ensure the
projected air quality standards are met. This unit will be a biofilter type
device, similar to the ones used at Salton Sea Units I -- IV.
4.3 MATERIALS OF CONSTRUCTION
A review of the design documents and specifications for the mechanical
components revealed that the New Projects have specified design requirements
typically found in the geothermal industry. In some cases, the specifications
and design criteria further defined very specific requirements that are based
on the operating history and proven experience with similar equipment that has
been in similar service for a number of years. As presented on the reviewed
documents, the materials of construction are appropriate for these facilities.
4.4 NEW PROJECTS MANAGEMENT ORGANIZATION
Salton Sea Unit V will be managed as part of the Salton Sea Units I, II,
III, and IV group of units (Region I). These units are managed by a Region
Supervisor and the combined units are operated by three Control Operators and
Outside Operators. The operations program includes a safety program, a training
program, and operating procedures. Maintenance programs include CMMS, training,
and spare parts inventory control.
Fluor Daniel considers the overall operating and maintenance organization
planned for these new facilities to be adequate to support expanded operations.
4.5 PROJECT SITE GEOTECHNICAL DESCRIPTION
The project sites are located in the Salton Trough geologic region. This
region is a result of extensive tectonic activity due to three active or
potentially active faults in the area. The site area is classified by Uniform
Building Code (UBC) as an earthquake zone of 4.
The subsurface geologic site conditions typically consist of stiff to firm
silty clay at shallow depth. At depth, loose to medium dense silty sand exists
with a potential for liquefaction. The silty clay exists with the potential for
long term settlements. The depth to groundwater at the site varies, but is in
the range of 5 to 6 feet below grade.
On the basis of geotechnical reports prepared by Southland Geotechnical,
the project sites are believed to be suitable for the proposed new Projects.
Foundation designs proposed in the report are similar to designs previously
used on other geothermal projects in this area which have operated for numerous
years and are believed to be adequate for these facilities.
C-15
<PAGE>
4.6 SCHEDULE
4.6.1 SALTON SEA UNIT V PROJECT
Stone & Webster Engineering Corporation (S&W) was selected as the
Contractor to engineer, procure, construct, and startup the Salton Sea Unit V
Project and is currently executing this work. S&W is a world-wide EPC power
project Contractor with a background in, and experience with geothermal
projects. S&W has engineering and construction experience with some of the
Existing Projects, including the original design for Salton Sea Unit III and is
familiar with the site conditions and resources of the Imperial Valley.
Additionally, S&W previously worked for the Salton Sea Funding Corporation as
consultant for the existing Bondholders. Belmont Construction (a subsidiary of
S&W) is being utilized for the construction phase, having previously performed
construction services for Salton Sea Unit IV.
The project schedule milestones require:
o Notice to Proceed October 13, 1998
o Startup Commissioning March 16, 2000
o Substantial Completion July 12, 2000
Under the EPC contract, S&W guarantees that substantial completion will be
attained by July 12, 2000, or S&W will be assessed for delay damages.
S&W acknowledged that the procurement, fabrication, delivery and erection
of the Turbine Generator is the critical path of the Salton Sea Unit V Project.
In support of this understanding they have awarded the Turbine Generator and
other critical equipment. The overall schedule duration is approximately 7
months for engineering, 18 months for construction, and 4 months for startup
and testing. This schedule provides that the project be substantially complete
approximately 6 weeks prior to the guaranteed Substantial Completion milestone.
Fluor Daniel has reviewed the current Salton Sea Unit V Project EPC
schedule. To date, planned progress has been achieved and it appears that the
EPC schedule can be achieved as indicated, subject to customary permitted
delays under the contract. S&W has identified and addressed the major project
components, allowing for sufficient time and interface to meet the schedule
objectives such as tie-ins and support to other facilities. Critical equipment
purchases have been made and the deliveries support the current scheduled
delivery dates. Construction is also underway with grubbing and grading of the
site.
Given S&W's qualifications and past experience at the Existing Projects
and elsewhere, the EPC project schedule should be achievable.
4.6.2 REGION II BRINE PROCESSING CONSTRUCTION
S&W was selected as the contractor to engineer, procure, construct, and
startup the CE Turbo Project and Region II Brine Processing Construction, and
is currently executing the work. S&W has engineering and construction
experience with some of the Existing Projects, including the original design
for Salton Sea Unit III and is familiar with the site conditions and resources
of the Imperial Valley. Additionally, S&W previously worked for the Salton Sea
Funding Corporation as consultant for the existing Bondholders. Belmont
Construction (a subsidiary of S&W) is being utilized for the construction
phase, having previously performed construction services for Salton Sea Unit
IV.
The Project Schedule Milestones require:
o Notice to Proceed October 13. 1998
o Startup Commissioning November 17, 1999
o Substantial Completion -- Brine Facilities
Construction February 22, 2000
o Substantial Completion CE Turbo Project April 13, 2000
C-16
<PAGE>
Under its EPC contract, S&W guarantees that substantial completion will be
attained by February 22, 2000 for the Brine Facilities Construction and by
April 13, 2000 for the CE Turbo Project, or S&W will be assessed for delay
damages.
S&W has acknowledged that the procurement, fabrication, delivery and
erection of the CE Turbo is the critical path of the Region II facilities
construction. They have awarded the CE Turbo and other critical equipment. Even
though construction has not begun, Fluor Daniel has reviewed the current Region
II Construction Schedule and believes that Substantial Completion as planned
should be achievable, subject to customary permitted delays under the contract.
4.7 CAPITAL COST ANALYSIS
4.7.1 SALTON SEA UNIT V PROJECT
The fixed price of $91.8 million equates to approximately $1,874 per net
kilowatt of new installed capacity, which is consistent with the cost of
similar geothermal facilities requiring solids removal technology. Currently,
S&W is executing the project under a fixed price contract with no change orders
having been identified. To date, S&W has invoiced for 22 percent of the fixed
price.
4.7.2 REGION II BRINE FACILITIES CONSTRUCTION
The fixed price of $49.8 million appears reasonable for this project.
Currently, S&W is executing the project under a fixed price contract with no
change orders having been identified. To date, S&W has invoiced 15 percent of
the fixed price.
4.7.3 CAPITAL IMPROVEMENTS
Proceeds from the October 7, 1998 Salton Sea Funding Corporation debt
offering and equity will be used to fund certain capital expenditures involving
plant and wellfield facilities at Elmore and Leathers. These costs are
presented below:
<TABLE>
<CAPTION>
1998 1999 2000 TOTAL ($000'S)
---- ---- ---- --------------
<S> <C> <C> <C> <C>
Elmore ............ $9,858 $7,109 0 $16,967
Leathers .......... 0 $ 977 $3,393 $ 4,370
------ ------ ------ -------
Total ............. $9,858 $8,086 $3,393 $21,337
</TABLE>
At Elmore, approximately $9.9 million of the total was used in 1998 for a
regularly scheduled plant overhaul and various other capital expenditure items.
At Leathers, approximately $2.3 million will be spent in 2000 for an overhaul.
The remaining expenditures in that year are for various other plant capital
expenditure items. On the basis of past expenditures for this type of similar
installations, Fluor Daniel finds these expenditures to be reasonable.
The remaining capital expenditure amounts are wellfield-related and are
separately analyzed by GeothermEx.
SECTION 5.0
5.0 PROJECT OPERATIONS
The Salton Sea and Partnership Projects use proven technology and have
operated reliably since initiating commercial operation. The most significant
operating and maintenance activities for the Salton Sea and Partnership
Projects are caused by the geothermal resource which corrodes and deposits
solids in the geothermal resource processing systems. These activities were
significantly reduced at the Salton Sea Projects with the implementation of the
pH Modification program and should be significantly reduced at Vulcan and Del
Ranch with the same system. This should result in similar decreases in cost at
Vulcan and Del Ranch.
C-17
<PAGE>
SECTION 6.0
6.0 PERMITTING AND ENVIRONMENTAL
6.1 ENVIRONMENTAL COMPLIANCE
Fluor Daniel has conducted a walk through of the Existing Projects in the
Imperial Valley. This walk through included an environmental overview of the
facilities. Facilities' inspections included Salton Sea Units I -- IV, and the
proposed sites for the New Projects. The environmental overview focused on the
H2S air emissions abatement systems; water and brine ponds design and
operation; stormwater control; solid waste handling and disposal; general noise
environment; and the associated solvent extraction sites.
The plants appeared neat and well maintained. The H2S abatement systems
consisted of existing biofilters for Salton Sea Units I, II, III and IV. A
review of the design indicated that there should be sufficient capacity to
handle any anticipated increase of H2S loads from Salton Sea Unit V. The water
and brine ponds design appeared adequate to minimize or eliminate the potential
for water and brine release into the underlying soil and groundwater. The
build-up of brine solids in the brine pond and subsequent land disposal should
be minimized in the future by enhanced solids retention in the brine injected
into the geothermal reservoir by project pH modification features.
Stormwater onsite is collected and injected into the geothermal reservoir.
Solid waste handling and disposal appear to be adequate. Dust control in the
solid waste handling operation should be improved by proposed dust handling
equipment and dust abatement measures.
The noise environment encountered appears to be comparable to other
similar power plant designs. Noise was qualitatively experienced within
acceptable OSHA limits near equipment. Excessive noise was not experienced at
the nearest residence. The preliminary design of the proposed ion exchange
units, central solvent extraction and electrowinning plant appeared feasible
and environmentally protective, evidenced by the pilot plant walk-through and
review of system process flow diagrams.
In reviewing two years worth of available files, Fluor Daniel has found no
environmental Notices of Violation for any media (air emissions, wastewater,
solid/hazardous waste).
6.2 APPLICABLE ENVIRONMENTAL PERMIT AND LICENSING REQUIREMENTS
All Existing Projects and the New Projects have received appropriate
regulatory approvals/exemptions in all media (air emissions,
stormwater/wastewater, brine injection), and have appropriate solid and
hazardous waste transportation and disposal contracts or agreements in place.
The New Projects have received the required Imperial County Conditional Use
Permits and Imperial County Air Pollution Control District air permits.
6.3 ENVIRONMENTAL REQUIREMENT COMPLIANCE, DEFICIENCIES AND LIMITATIONS
It is the opinion of Fluor Daniel that the New Projects have appropriate
designs and have or plan to have trained personnel to comply with all
environmental laws and regulations, have received all environmental permits and
approvals, and have contracts and agreements in place with licensed waste
transportation and disposal companies. If operated in accordance with the
provided design, and good utility practices the projects should not have any
environmental deficiencies or limitations.
SECTION 7.0
7.0 ASSESSMENT OF FINANCIAL PROJECTIONS
7.1 BASE CASE PROJECTION ASSUMPTIONS
7.1.1 CONSTRUCTION EXPENDITURES
CEG provided what we believe to be reasonable assumptions regarding new
capital expenditures to be funded in accordance with the October 7, 1998
issuance of Salton Sea Funding Corporation
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<PAGE>
securities, including the construction cost of the Salton Sea Unit V Project,
the CE Turbo Project, Region II Brine Facilities Construction and the Capital
Improvements. As used in the summary, the Project construction costs include
certain owner's administration costs, owner's contingency funds and other costs
for construction and services not included in the fixed price EPC contracts.
These assumptions along with the financing plan, are shown below.
USES AND SOURCES OF FUNDS
(X$000'S)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
1998 1999 2000 TOTAL
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Salton Sea Unit V Project 15,983 77,284 13,596 106,863
- --------------------------------------------------------------------------------
Zinc Recovery Project 31,779 104,640 43,911 180,330
- --------------------------------------------------------------------------------
CE Turbo Project 1,502 8,504 215 10,221
- --------------------------------------------------------------------------------
Region II Brine Processing 6,908 39,097 987 46,992
Construction
- --------------------------------------------------------------------------------
Capital Improvements 10,817 7,127 3,393 21,337
- --------------------------------------------------------------------------------
Interest and Financing Cost 9,908 21,305 10,564 41,770
- --------------------------------------------------------------------------------
TOTAL USES $76,897 $257,957 $76,666 $407,513
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
Bond Proceeds 76,897 208,110 0 285,000
- --------------------------------------------------------------------------------
Equity 0 49,847 72,666 122,513
- --------------------------------------------------------------------------------
TOTAL SOURCES $76,897 $257,957 $72,666 $407,513
- --------------------------------------------------------------------------------
</TABLE>
7.1.2 POWER PRODUCTION
Existing operations at the Salton Sea consist of eight power plants:
Salton Sea Units I, II, III, and IV, Vulcan, Del Ranch, Elmore, and Leathers.
These facilities have demonstrated reliable operation in the range of 95-100
percent average plant availability . The assumptions regarding future
operations are shown in the table below. The capacity factors for the Existing
Projects are shown for 1998.
C-19
<PAGE>
PROFORMA OPERATING ASSUMPTIONS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------
NAMEPLATE AVERAGE AVAILABILITY
LOCATION CAPACITY (KW) FACTOR (1)
- -----------------------------------------------------------------
<S> <C> <C>
Salton Sea Unit I 10,000 92%
- -----------------------------------------------------------------
Salton Sea Unit II 20,000 96%
- -----------------------------------------------------------------
Salton Sea Unit III 49,800 98%
- -----------------------------------------------------------------
Salton Sea Unit IV 39,650 99%
- -----------------------------------------------------------------
Leathers 41,000 98%
- -----------------------------------------------------------------
Elmore 41,000 98%
- -----------------------------------------------------------------
Vulcan 34,000 98%
- -----------------------------------------------------------------
Del Ranch 38,000 99%
- -----------------------------------------------------------------
Salton Sea Unit V 49,000 95%
- -----------------------------------------------------------------
CE Turbo 10,000 95%
- -----------------------------------------------------------------
TOTAL 332,450
- -----------------------------------------------------------------
</TABLE>
- ----------
(1) For years 2000 through 2004.
On the basis of past plant performance, Fluor Daniel finds the capacity
factor assumptions used in the financial projections to be reasonable.
7.1.3 REVENUES
All of the Existing Projects sell power under contract to Southern
California Edison Company. Six of the eight Existing Projects have a 10-year
provision for fixed energy pricing at rates that are now considered to be
substantially above market. These six Existing Projects have already reached,
or by 2000 will reach the expiration of the 10-year fixed energy price period
by 2000 causing a drop in project revenue. Pricing for electrical energy beyond
these fixed price termination dates will be subject to pricing under the new
deregulated wholesale power market in California. The chart showing the
forecast of gross revenues for the Projects is shown below.
CEG PROJECTED REVENUES -- GEOTHERMAL PROJECTS
[LINE CHART SHOWING PROJECTED REVENUES OF THE GEOTHERMAL PROJECTS]
C-20
<PAGE>
7.1.4 OPERATING EXPENSES
CEOC presently operates the Existing Projects under contract to the
various ownership entities. As evidenced by the information provided by the
CEG, over the last three years operating expenses have been reduced through
consolidation of operations. Projected operating costs have been developed in
detail by CEOC and appear to be reasonable.
A significant annual expense associated with operation of each facility is
the payment of royalties for use of the geothermal brine. Under the present
ownership arrangement, the majority of royalties paid by each project flow back
to the Royalty Guarantor. This impact is captured in the cash flow analysis.
7.1.5 ONGOING CAPITAL EXPENDITURE
The CE Generation has prepared a ten-year plan for ongoing geothermal
capital expenditures. This plan was reviewed by Fluor Daniel, was determined to
be reasonable, and is used as the basis for projecting future capital
expenditures in the forecasting model (Exhibit 1). Categories of expenditure
include such items as geothermal well drilling, power plant improvements, and
power plant overhaul.
7.1.6 ESCALATION
All expenses in the financial projection (Exhibit 1) have been escalated
at an assumed rate of 2.5 percent. Unless specified otherwise.
7.1.7 CASH FLOW
The cash flow model (Exhibit 1) computes cash flow available for
distribution. Operating expenditures, capital expenditures, and debt service
are then calculated and subtracted from total receipts to determine cash flow
available for distribution.
C-21
<PAGE>
ATTACHMENT 2-1
ASSUMPTIONS, QUALIFICATIONS AND REVIEW DOCUMENTS
THIS REPORT WAS PREPARED BY FLUOR DANIEL, INC. EXPRESSLY FOR USE BY CE
GENERATION. IT IS FLUOR DANIEL'S UNDERSTANDING THAT THIS REPORT WILL BE INCLUDED
IN THE PUBLIC OFFERING MEMORANDUM AND SUBSEQUENT PROSPECTUS FOR THE OFFERING OF
THE BONDS, AS DESCRIBED HEREIN. NEITHER FLUOR DANIEL NOR ANY PERSON ACTING IN
ITS BEHALF, MAKES ANY WARRANTY, EXPRESS OR IMPLIED, OR ASSUMES ANY LIABILITY
WITH RESPECT TO THE USE OF ANY INFORMATION, TECHNOLOGY, ENGINEERING, OR METHODS
DISCLOSED IN THIS REPORT, EXCEPT FOR SUCH LIABILITY AS MAY ARISE UNDER THE
FEDERAL SECURITIES LAWS.
It is believed that the information contained in the Salton Sea Project
Analysis is reliable under conditions and subject to the limitations set forth
therein. Except only as to the revisions to the Salton Sea Project Analysis
required to reflect the Updated Events, the analysis or conclusions contained
in that report are incorporated herein. This Report therefore summarizes our
work as of September 23, 1998, modified to reflect the Updated Events and
information contained in Attachment 2-1, up to the date of the Report. Thus,
changed conditions occurring or becoming known after such date could affect the
material presented to the extent of such changes.
In the preparation of this Report and the opinions contained therein,
Fluor Daniel 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 for the purpose of this Report, they are dependent
upon future events and actual conditions may differ from those assumed. In
addition, we have used and relied exclusively upon the information specified in
the list of Review documents. Neither CE Generation nor Fluor Daniel Inc. has
made an analysis, verified, or rendered an independent judgment of the validity
of the information provided by others. While it is believed that the
information contained herein will be reliable under the conditions and subject
to the limitations set forth herein, neither CE Generation nor Fluor Daniel,
Inc. guarantee the accuracy thereof. Further, 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. The principal
assumptions and considerations utilized by Fluor Daniel in developing the
results and conclusions presented in this report include the following:
o Only the power plants and above ground geothermal resource piping and
processing facilities were evaluated. The adequacy, reliability, and
costs of geothermal resources and wells were assessed by GeothermEx.
o The projected interest rates on the Securities, reinvestment rates,
cost of arranging the financing and the amortization schedule of the
Securities used in the debt service coverage analysis have been
provided to Fluor Daniel.
o Fluor Daniel's inspection of the existing Salton Sea operations were
limited to a visit of personnel on July 24, 1998 and February 9, 1999.
o CE Generation provided 1998 financial statements for the CE Generation
and other cost accounting information as well as future projections of
cost, expenses, prices, and other key assumptions.
o Brine quantities and depletion rates were provided by GeothermEx.
o The electricity pricing forecast was provided by Henwood Energy
Services.
o Fluor Daniel has not undertaken an independent review with all
regulatory agencies which could under any circumstances have
jurisdictions over or interests pertaining to the project.
C-22
<PAGE>
REVIEW DOCUMENTS
<TABLE>
<CAPTION>
DOCUMENT
DATE DOCUMENT
- ---- --------
<S> <C>
7/18/95 Salton Sea Funding Corporation Confidential Offering Circular
6/17/96 Salton Sea Funding Corporation Confidential Offering Circular
3/31/93 Technology Transfer Agreement -- Units I, II, & III
7/28/98 Second Amended and Restated Waste Disposal Agreement -- Units I, II, III, & IV
11/24/93 Ground Lease -- Units I & II
9/25/90 Plant Connection Agreement -- Unit II
7/20/88 Plant Connection Agreement -- Unit III
3/31/93 Ground Lease -- Units III & IV
7/14/95 Plant Connection Agreement -- Unit IV
6/9/88 Plant Connection Agreement -- Del Ranch, L.P.
3/14/88 Ground Lease -- Del Ranch, L.P.
3/14/88 Technology Transfer Agreement -- Del Ranch, L.P.
6/9/88 Plant Connection Agreement -- Elmore, L.P.
3/14/88 Ground Lease -- Elmore, L.P.
3/14/88 Technology Transfer Agreement -- Elmore, L.P.
9/25/89 Plant Connection Agreement -- Leathers, L.P.
10/26/88 Ground Lease -- Leathers, L.P.
8/15/88 Technology Transfer Agreement -- Leathers, L.P.
12/6/88 Plant Connection Agreement -- Vulcan Power Company
4/14/98 IID Construction Agreement -- Salton Sea Unit V
4/1/98 IID Plant Connection Agreement -- Salton Sea Unit V
4/14/98 IID Transmission Services Agreement -- Salton Sea Unit V
7/30/98 Lump Sum Cost Proposal -- Salton Sea Unit V Project Schedule
9/11/98 Conditional Use Permit G91-0001 -- Region II Power Plant Modification Project
4/98 Geotechnical Report -- Salton Sea Unit V & Zinc Extraction Facilities
8/98 Geotechnical Investigation -- Upgrade To Vulcan Power Plant
8/5/98 Imperial Valley Operating Statistics
8/5/98 Excerpts from 5 Year Operating Plan
8/98 GeothermEx Report -- Assessment of the Resource Supply
8/5/98 BHP Royalty Agreement and Amendment
8/5/98 California Energy Commission, State of California Energy Resources Conservation
and Development Commission Clearance/Acknowledgement that the Desert
Valley/Salton Sea Unit V Project is not subject to the Commission's jurisdiction.
6/26/98 Conditional Use Permit (#G94-0001) Second Amendment, Granted by Imperial
County and Recorded on 6/26/98 to Allow Brine Flow Increase to Accommodate New
49 MW Power Plant Site.
6/25/98 Conditional Use Permit (#G98-0001) Granted by Imperial County and Recorded on
6/25/98 for a New 23 acre, 49 MW Power Plant generating 0.35 Tons Filter Cake per
Net Megawatt.
7/22/98 Agreement To Conditional Use Permit (G91-0001) Del Ranch, L.P. -- Region 2
(dated July 22, 1998)
7/22/98 Agreement To Conditional Use Permit (G84-0001) Vulcan/BN Geo. Power CO/CE
Turbo LLC -- Region 2 (dated July 22, 1998)
7/1/98 Imperial County Air Pollution Control District, Amended Conditions For Authority
To Construct and Permit To Operate #1894C. Amended Conditions Issued 7/1/98.
This permit is for amended conditions for construction and operation of the elements
in Region I, Unit III.
</TABLE>
C-23
<PAGE>
<TABLE>
<CAPTION>
DOCUMENT
DATE DOCUMENT
- ---- --------
<S> <C>
9/17/98 Imperial County Air Pollution Control District, Amended Conditions For Authority
To Construct and Permit To Operate #1672B. Amended Conditions Issued 9/17/98.
This permit is for amended conditions for construction and operation of the elements
at the Vulcan Power Plant.
9/17/98 Imperial County Air Pollution Control District, Amended Conditions For Authority
To Construct and Permit To Operate #1891E. Amended Conditions Issued 9/17/98.
This permit is for amended conditions for construction and operation of the elements
at the A. W. Hoch Power Plant.
8/5/98 Imperial County Air Pollution Control District Permit to Construct # 2743 -- Permit
to construct Unit V
8/5/98 Imperial County Public Health Department Water System Permit for 1998, Permit
Number 637
4/1/96 Laidlaw Environmental Services Contract for Facilities Waste Removal and Disposal
Services, dated April 1, 1996, expiring April 1, 2001. Contract NO. 963093.
6/13/96 State of California, Department of Conservation, Division of Oil, Gas, and
Geothermal Resources, Unit 3 Permanent Injection Project Approval.
4/1/98 Cal/EPA State Water Resources Control Board, Letters of Receipt and Processing of
Notices of Intent (2) to Comply with the General Permit to Discharge Stormwater
Associated with Construction Activity, dated April 1, 1998 effective 9/1/98 through
7/1/2000.
9/13/94 California Regional Water Quality control Board, Colorado River Basin, Region 7
Waste Discharge Order (Permit) NO. 94-081for the Injection of Brine and operation
of a brine pond and Holding Basin, effective 9/13/94.
8/5/98 Material Safety Data Sheet, Nalco 1387 Scale Inhibitor (phosphonomethylated amine).
9/2/98 Salton Sea Unit V Engineering, Procurement, and Construction Contract
9/11/98 Region II Upgrade Engineering, Procurement, and Construction Contract
8/12/98 Draft Amendments to Power Purchase Agreement
3/31/98 Salton Sea Funding Corp. Securities and Exchange Commission Form 10-Q
12/31/97 Salton Sea Funding Corp. Securities and Exchange Commission Form 10-K
02/10/99 Draft Amended and Restated Zinc Extraction Services Agreement
</TABLE>
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<PAGE>
[THIS PAGE INTENTIONALLY LEFT BLANK]
C-25
<PAGE>
EXHIBIT 1
CE GENERATION IMPERIAL VALLEY
Projected Operating Results ($'000s)
Base Case
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 2004
--------- --------- --------- --------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
RECEIPTS:
Revenue $ 216,272 $ 164,994 $ 160,363 $ 171,989 $ 176,884 $181,718
Magma and other revenues 1,000 1,000 1,000 1,000 1,000 1,000
Interest income 5,048 2,264 2,252 2,758 2,603 2,804
--------------------------------------------------------------------------
Total Receipts 222,320 168,258 163,615 175,747 180,487 185,522
OPERATING EXPENDITURES:
Royalty Expense (26,313) (14,356) (14,715) (16,236) (16,823) (17,339)
Operations (12,095) (11,193) (11,445) (11,458) (11,743) (12,036)
Maintenance (4,280) (3,816) (3,505) (3,477) (3,564) (3,653)
Machine shop (439) (451) (462) (474) (487) (499)
Engineering (326) (599) (617) (634) (650) (665)
Well workovers (4,639) (3,496) (3,687) (4,378) (3,055) (1,564)
Services, general & administrative (5,757) (5,570) (5,391) (5,718) (5,853) (5,997)
Accounting, legal & land (1,317) (1,589) (1,630) (1,682) (1,721) (1,760)
Management fees (5,029) (3,377) (3,306) (3,576) (3,641) (3,758)
Guaranteed capacity (3,199) (1,333) (1,389) (1,591) (1,782) (1,735)
Insurance (2,119) (2,286) (2,457) (2,489) (2,551) (2,613)
Property tax (7,561) (5,743) (6,061) (6,049) (5,928) (5,866)
IID transmission line fee (5,068) (6,003) (6,007) (6,085) (6,165) (6,252)
Magma Expenses/Obligations (1,089) (1,040) (903) (903) (903) (903)
Adjustment - Royalties / Fees Paid to Magma 23,783 11,160 11,191 12,469 13,099 13,406
Other 0 (44) (78) (84) (85) (85)
--------------------------------------------------------------------------
Total Operating Expenditures (55,448) (49,737) (50,462) (52,366) (51,852) (51,319)
CAPITAL EXPENDITURES:
Ongoing Capital Expenditures (21,525) (21,159) (17,305) (7,334) (17,779) (15,598)
Construction Expenditures (142,812) (23,546) -- -- -- --
--------------------------------------------------------------------------
Total Capital Expenditures (164,337) (44,705) (17,305) (7,334) (17,779) (15,598)
FINANCING PROCEEDS:
Bond Proceeds 118,681 -- -- -- -- --
Equity Contributions 24,131 23,546 -- -- -- --
--------------------------------------------------------------------------
Total Financing Proceeds 142,812 23,546 -- -- -- --
DEBT SERVICE
Project loan interest payments (24,904) (26,473) (30,424) (28,651) (26,667) (24,602)
Project loan principal payments (57,836) (25,073) (23,027) (26,465) (26,682) (28,832)
--------------------------------------------------------------------------
Total Debt Service (82,740) (51,546) (53,451) (55,115) (53,349) (53,433)
CASH AVAILABLE FOR DISTRIBUTION $ 62,608 $ 45,816 $ 42,397 60,931 $ 57,507 $ 65,172
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2005 2006 2007 2008
--------- --------- --------- -------
<S> <C> <C> <C> <C>
RECEIPTS:
Revenue $ 186,591 $ 179,658 $ 177,732 $ 183,985
Magma and other revenues 1,000 1,000 1,000 1,000
Interest income 2,565 2,733 2,586 2,949
------------------------------------------------
Total Receipts 190,156 183,391 181,318 187,934
OPERATING EXPENDITURES:
Royalty Expense (18,602) (17,504) (17,643) (18,469)
Operations (12,336) (12,646) (12,963) (13,286)
Maintenance (3,744) (3,839) (3,935) (4,034)
Machine shop (511) (524) (536) (549)
Engineering (680) (697) (714) (731)
Well workovers (2,097) (2,080) (2,130) (2,175)
Services, general & administrative (6,166) (6,296) (6,451) (6,609)
Accounting, legal & land (1,799) (1,840) (1,882) (1,924)
Management fees (3,933) (3,924) (3,930) (4,127)
Guaranteed capacity (2,028) (1,852) (2,033) (2,029)
Insurance (2,679) (2,748) (2,817) (2,887)
Property tax (5,778) (5,682) (5,427) (5,280)
IID transmission line fee (6,339) (6,429) (6,519) (6,610)
Magma Expenses/Obligations (903) (903) (903) (903)
Adjustment - Royalties / Fees Paid to Magma 14,685 14,322 14,708 15,395
Other (86) (86) (87) (87)
------------------------------------------------
Total Operating Expenditures (52,997) (52,726) (53,260) (54,305)
CAPITAL EXPENDITURES:
Ongoing Capital Expenditures (26,092) (14,562) (16,215) (7,609)
Construction Expenditures -- -- -- --
------------------------------------------------
Total Capital Expenditures (26,092) (14,562) (16,215) (7,609)
FINANCING PROCEEDS:
Bond Proceeds -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------------
Total Financing Proceeds -- -- -- --
DEBT SERVICE
Project loan interest payments (22,037) (20,310) (18,289) (16,257)
Project loan principal payments (28,618) (25,916) (25,090) (28,067)
------------------------------------------------
Total Debt Service (50,654) (46,226) (43,378) (44,323)
CASH AVAILABLE FOR DISTRIBUTION $ 60,413 $ 69,877 68,464 $ 81,697
</TABLE>
C-26
<PAGE>
EXHIBIT I
CE GENERATION IMPERIAL VALLEY
Projected Operating Results ($'000s)
Base Case
<TABLE>
<CAPTION>
2009 2010 2011 2012 2013 2014
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
RECEIPTS:
Revenue $ 181,895 $ 185,178 $ 184,499 $ 184,817 $ 190,380 $ 193,049
Magma and other revenues 1,000 1,000 1,000 1,000 1,000 1,000
Interest income 2,655 2,877 2,724 2,884 2,657 3,037
--------------------------------------------------------------------------
Total Receipts 185,550 189,055 188,223 188,701 194,037 197,086
OPERATING EXPENDITURES:
Royalty Expense (18,102) (18,524) (18,534) (18,416) (19,433) (19,442)
Operations (13,618) (13,958) (14,307) (14,664) (15,031) (15,407)
Maintenance (4,133) (4,238) (4,344) (4,453) (4,564) (4,679)
Machine shop (562) (574) (587) (602) (616) (631)
Engineering (750) (770) (791) (811) (831) (852)
Well workovers (256) (1,532) (1,391) (1,000) (3,407) (2,361)
Services, general & administrative (6,774) (6,944) (7,117) (7,295) (7,478) (7,664)
Accounting, legal & land (1,967) (2,014) (2,061) (2,109) (2,156) (2,208)
Management fees (4,062) (4,165) (4,153) (4,163) (4,309) (4,337)
Guaranteed capacity (2,127) (2,017) (2,200) (2,039) (2,312) (2,129)
Insurance (2,959) (3,033) (3,109) (3,187) (3,267) (3,348)
Property tax (5,131) (5,037) (4,885) (4,751) (4,536) (4,275)
IID transmission line fee (6,704) (6,797) (6,893) (6,991) (7,089) (7,189)
Magma Expenses/Obligations (903) (903) (903) 0 0 0
Adjustment - Royalties / Fees Paid to Magma 15,332 15,486 15,807 15,485 16,553 16,281
Other (88) (89) (89) (90) (91) (92)
--------------------------------------------------------------------------
Total Operating Expenditures (52,804) (55,109) (55,556) (55,087) (58,568) (58,332)
CAPITAL EXPENDITURES:
Ongoing Capital Expenditures (17,666) (10,456) (14,570) (8,944) (18,198) (7,529)
Construction Expenditures -- -- -- -- -- --
--------------------------------------------------------------------------
Total Capital Expenditures (17,666) (10,456) (14,570) (8,944) (18,198) (7,529)
FINANCING PROCEEDS:
Bond Proceeds -- -- -- -- -- --
Equity Contributions -- -- -- -- -- --
--------------------------------------------------------------------------
Total Financing Proceeds -- -- -- -- -- --
DEBT SERVICE
Project loan interest payments (14,085) (11,809) (9,758) (8,491) (7,286) (6,140)
Project loan principal payments (26,210) (26,741) (19,991) (16,615) (14,665) (17,338)
--------------------------------------------------------------------------
Total Debt Service (40,294) (38,551) (29,749) (25,106) (21,951) (23,477)
CASH AVAILABLE FOR DISTRIBUTION $ 74,786 $ 84,940 $ 88,348 $ 99,564 $ 95,319 $ 107,747
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2015 2016 2017 2018
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
RECEIPTS:
Revenue $ 196,809 $ 196,491 $ 193,806 $ 193,582
Magma and other revenues 1,000 1,000 1,000 1,000
Interest income 3,106 3,045 2,909 2,939
------------------------------------------------
Total Receipts 200,915 200,536 197,715 197,521
OPERATING EXPENDITURES:
Royalty Expense (20,227) (20,616) (20,750) (21,002)
Operations (15,792) (16,188) (16,592) (17,008)
Maintenance (4,795) (4,915) (5,038) (5,164)
Machine shop (647) (663) (681) (699)
Engineering (873) (894) (915) (937)
Well workovers (2,930) (1,270) (1,627) (980)
Services, general & administrative (7,856) (8,053) (8,253) (8,459)
Accounting, legal & land (2,259) (2,311) (2,363) (2,419)
Management fees (4,427) (4,372) (4,314) (4,344)
Guaranteed capacity (2,407) (2,558) (2,560) (2,656)
Insurance (3,432) (3,518) (3,606) (3,697)
Property tax (3,983) (3,728) (3,339) (2,987)
IID transmission line fee (7,290) (7,394) (7,498) (7,604)
Magma Expenses/Obligations 0 0 0 0
Adjustment - Royalties / Fees Paid to Magma 17,169 17,427 17,611 18,017
Other (93) (93) (94) (95)
------------------------------------------------
Total Operating Expenditures (59,839) (59,145) (60,019) (60,035)
CAPITAL EXPENDITURES:
Ongoing Capital Expenditures (6,427) (8,828) (10,036) (8,315)
Construction Expenditures -- -- -- --
------------------------------------------------
Total Capital Expenditures (6,427) (8,828) (10,036) (8,315)
FINANCING PROCEEDS:
Bond Proceeds -- -- -- --
Equity Contributions -- -- -- --
------------------------------------------------
Total Financing Proceeds -- -- -- --
DEBT SERVICE
Project loan interest payments (4,814) (3,372) (1,859) (559)
Project loan principal payments (18,926) (20,371) (19,866) (9,969)
------------------------------------------------
Total Debt Service (23,740) (23,743) (21,725) (10,528)
CASH AVAILABLE FOR DISTRIBUTION 110,909 $ 108,820 $ 105,934 $ 118,642
</TABLE>
C-27
<PAGE>
APPENDIX D
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 -- 2018
PREPARED FOR:
CE GENERATION, LLC
FEBRUARY 11, 1999
PREPARED BY:
HENWOOD ENERGY SERVICES, INC.
2710 GATEWAY OAKS WAY, SUITE 300 NORTH
SACRAMENTO, CA 95833
D-1
<PAGE>
TABLE OF CONTENTS
THE SOUTHERN CALIFORNIA
ELECTRICITY MARKET AND
PRICE FORECAST
1999 -- 2018
TABLE OF CONTENTS
<TABLE>
<CAPTION>
SECTION PAGE
- ------- ----
<S> <C> <C>
EXECUTIVE SUMMARY ........................................... D-4
1 THE U.S. ELECTRIC POWER MARKET .............................. D-6
1.1 INTRODUCTION ................................................ D-6
1.2 FEDERAL LEGISLATIVE AND REGULATORY INITIATIVES .............. D-6
1.2.1 Public Utility Regulatory Policies Act -- 1978 .............. D-6
1.2.2 Energy Policy Act -- 1992 ................................... D-6
1.2.3 FERC Order 888 -- 1996 ...................................... D-6
1.3 CALIFORNIA LEGISLATIVE INITIATIVES .......................... D-7
1.3.1 Assembly Bill 1890 .......................................... D-7
2 THE CALIFORNIA WHOLESALE POWER MARKET ....................... D-8
2.1 THE MARKET 1998 AND BEYOND .................................. D-8
2.1.1 Diversity of Energy Supply .................................. D-8
2.1.2 California Investor Owned Utilities ......................... D-9
2.1.3 Treatment of Qualifying Facilities (QFs) .................... D-9
2.2 CALIFORNIA MUNICIPAL UTILITIES AND AUTHORITIES .............. D-10
2.3 SYSTEM RELIABILITY .......................................... D-10
2.4 PX MARKET ................................................... D-10
2.4.1 PX Prices ................................................... D-10
2.4.2 Short Run Avoided Costs ..................................... D-11
2.5 PX PRICES AS A MEASURE OF AVOIDED COST ...................... D-12
3 PX PRICE FORECAST: KEY ASSUMPTIONS AND METHODOLOGY .......... D-13
3.1 MODELING METHODOLOGY AND TECHNIQUES ......................... D-13
3.2 ASSUMPTIONS REGARDING THE CALIFORNIA MARKET TRANSITION
PERIOD ..................................................... D-13
3.3 KEY ASSUMPTIONS FOR MODELING CALIFORNIA MARKET .............. D-14
3.3.1 Forecast Horizon ............................................ D-14
3.3.2 Market Structure ............................................ D-14
3.3.3 Existing Resource Base ...................................... D-14
3.3.4 Resource Retirements ........................................ D-14
3.3.5 Generic Resource Additions .................................. D-14
3.3.6 Loads ....................................................... D-15
3.3.7 Load Shape .................................................. D-15
3.3.8 Load Growth ................................................. D-15
3.3.9 Inflation ................................................... D-15
3.3.10 Fuel Prices ................................................. D-15
3.3.11 Operations & Maintenance .................................... D-17
3.3.12 Property Taxes .............................................. D-17
3.3.13 Insurance ................................................... D-17
3.3.14 Other Costs ................................................. D-17
</TABLE>
D-2
<PAGE>
<TABLE>
<CAPTION>
SECTION PAGE
- ------- ----
<S> <C> <C>
3.4 WSCC TRANSMISSION SYSTEM CONFIGURATION ........................................... D-17
3.5 HYDRO POWER ...................................................................... D-18
3.5.1 Median Year Case ................................................................. D-18
3.5.2 Transactions ..................................................................... D-19
4 PX PRICE FORECAST: RESULTS ....................................................... D-20
4.1 BASE CASE 1999-2018 .............................................................. D-20
4.2 SENSITIVITY CASES ................................................................ D-21
4.2.1 Low Gas 1 Case ................................................................... D-21
4.2.2 Low Gas 2 Case ................................................................... D-21
5 THE POWER PROJECTS AND THE CALIFORNIA MARKET ..................................... D-22
5.1 MARKET ANALYSIS RESULTS .......................................................... D-22
5.2 PX PRICES AND THE MARKET POSITION OF THE POWER PROJECTS .......................... D-24
6 THE CALIFORNIA GREEN POWER MARKET AND ITS IMPLICATIONS
FOR THE POWER PROJECTS .......................................................... D-26
6.1 CEC RENEWABLE RESOURCE FUNDING ................................................... D-26
6.2 EXISTING RENEWABLE RESOURCE ACCOUNT .............................................. D-26
6.3 NEW RENEWABLE RESOURCE ACCOUNT ................................................... D-27
6.4 EMERGING RENEWABLES ACCOUNT ...................................................... D-28
6.5 CONSUMER-SIDE INCENTIVES ......................................................... D-28
6.6 DISCUSSION OF GREEN POWER MARKET BENEFITS ........................................ D-28
LIST OF TABLES
Table 2-1 1996 Net System Power (Electric Generation) ...................................... D-9
Table 2-2 Monthly Average California PX Prices -- April 1998 to January 1999 ($/MWh) ....... D-11
Table 2-3 SCE and SDG&E Annual Average Short-Run Avoided Costs of Energy ................... D-12
Table 3-1 Generic Resource Characteristics (1996 dollars) .................................. D-15
Table 4-1 Base Case PX Price Forecast 1999 -- 2018, $/MWh................................... D-20
Table 4-2 PX Prices Under Low Gas Case 1 ................................................... D-21
Table 4-3 PX Prices Under Low Gas Case 2 ................................................... D-21
Table 5-1 Average Operating Costs by Plant Type in the WSCC from Prosym Model Simulation
in 2005 ......................................................................... D-22
Table 5-2 PX Price Frequency Analysis in Southern California Transmission Area, 2005 ....... D-25
Table 6-1 AB 1890 Accounts -- Total Funding Allocations by Technology, $Millions ........... D-26
Table 6-2 Existing Renewable Resource Account Allocations by Tier, $Millions................ D-27
Table 6-3 New Renewable Resource Account Allocations by Year, $Millions .................... D-27
LIST OF FIGURES
Figure 2-1 California PX Daily Prices -- High, Low and Average .............................. D-12
Figure 3-1 WSCC Transmission System Configuration ........................................... D-18
Figure 5-1 PX Prices and Project Operating Costs, Units I to IV ............................. D-23
Figure 5-2 PX Prices and Project Operating Costs, Other Units ............................... D-23
Figure 5-3 PX Prices and New Power Project Operating Costs .................................. D-24
Figure 5-4 PX Prices and Yuma Operating Costs ............................................... D-24
LIST OF APPENDICES
A SCE SRAC FORECAST ................................................................ D-30
</TABLE>
D-3
<PAGE>
EXECUTIVE SUMMARY
BACKGROUND
CE GENERATION, LLC ("CEG") will issue securities to finance, among other
things, two new geothermal power plants -- Salton Sea Unit V and the CE Turbo
Project(the "New Power Projects"), which will have a combined net generation
capacity of 59 MW. The New Power Projects are located in the Salton Sea area of
California. The financing will encompass further investment in eight existing
geothermal units which sell power to Southern California Edison under Standard
Offer contracts authorized by the California Public Utilities Commission (the
"CPUC"). In addition, the financing includes a 50 MW gas-fired project, "Yuma",
in Yuma Arizona, which sells power to San Diego Gas and Electric under a
Standard Offer contract. The New Power Projects, the Existing Projects and Yuma
together comprise the "Power Projects". The financing requires an in-depth
assessment of the regulatory issues and electric energy markets in California
including information on the structure and operation of the California market
and an assessment of the competitive position of the Power Projects in the
market.
Henwood Energy Services, Inc (HESI) has developed an independent
assessment of (i) the wholesale electricity market in California for the 20
year period 1999 through 2018; (ii) the competitive position of the Power
Projects in the California market, and; (iii) the outlook for renewable energy
in the emerging Green Power market.
This assessment is presented in both quantitative and qualitative fashion
as listed below:
1. A brief description of the California wholesale electricity market.
2. The key assumptions used in assessing the market and as inputs into
the HESI Electric Market Simulation System.
3. Forecasts of average electricity prices in the California market and
the methodology to develop them. HESI used its proprietary Electric
Market Simulation System (EMSS) to produce the forecasts of market
clearing prices. The base case scenario was developed using
assumptions developed and tested by HESI. Two low gas price scenarios
were developed to assess the Power Projects' sensitivity to market
prices.
4. A specific competitive assessment of the Power Projects on a
stand-alone basis using revenue and variable cost estimates generated
by HESI.
5. An assessment of the Power Projects within the context of the
competitive market and how the Power Projects compare with other
generators.
6. An assessment of the Green Power and renewable energy markets.
7. An analysis of the changes to Qualifying Facility (QF) payments, the
transition formula for calculating such payments, and forecasts of the
payments for the Power Projects.
Based on these analyses, our report contains the following conclusions:
1. Our Base Case forecast indicates that the Southern California annual
Power Exchange (PX) market clearing price (MCP) will increase from
$28.3/MWh in 1999 to $50.3/MWh by 2018 in nominal dollars -- which
translates into an average annual rate of increase of 3.1 percent over
that period.
2. We expect all of the Power Projects to be low cost producers in all
years of the study. The annual average operating cost of the Power
Projects in 2005 is $17.5/MWh (excluding Yuma). In fact, about 66
percent of the electricity produced in the WSCC in 2005 -- the first
year of full competition -- is generated from units with higher costs,
a strong indication that the Power Projects will be dispatched as
baseload. The new units, Salton Sea Unit V and the CE Turbo Project,
are even better positioned with operating costs of $10.0 and $9.3 per
MWh respectively. Of all the generation in the region, only
hydroelectric generators have lower operating costs.
D-4
<PAGE>
3. The annual average operating costs of the Power Projects, in $/MWh,
are below the annual average PX prices. In fact, the Power Projects'
operating costs are close to the off-peak PX price in 1999 through
2002 and significantly below that in all years thereafter.
4. The low-cost relationship between PX prices and the Power Projects'
operating costs also prevails with the Low Gas Price sensitivity
cases. In these cases, operating costs are also well below the PX
prices. The range of annual average PX prices in the Low Gas Case 1 is
$27.9/MWh in 2000 to $47.0/MWh in 2018.
5. A significant finding of the study is that Salton Sea Unit V and the
CE Turbo Project will have operating costs lower than all other
generator types, except hydro, and will be extremely well-positioned
to be dispatched any hour in the year. The operating costs of these
units are about $18.5 to $20/MWh lower than PX prices in 2000 and
2001. The difference increases to $30/MWh by 2005 and to nearly
$40/MWh by 2018. The margin is so significant it is extremely unlikely
that any new significant capacity with lower operating costs will be
built. The Yuma plant appears very cost competitive compared to HESI
estimates of natural gas cogeneration. Yuma operating costs are about
$9.0/MWh below power market prices in 2000 and $15 to $17/MWh below
forecast PX prices in all years after 2005.
6. We also find that the PX price will be greater than or equal to
$20.3/MWh in 96 percent of all hours in 2005. This means that the
Power Projects, with an average operating cost of $17.5/MWh, will be
below the PX price in each of those hours and will be dispatched
accordingly.
7. The transition of short--run avoided cost determination to
competitively determined pricing, while subject to regulatory and
market dynamics, is expected to be complete by the beginning of 2000.
We forecast the Southern California Edison SRAC to be $30.3/MWh in
1999 and $31.1/MWh in 2000, on an annual average basis. SRAC prices
for QF sales to San Diego Gas and Electric are estimated at $30.9/MWh
in 1999 and $31.7/MWh in 2000.
8. In addition to being low cost producers, the Power Projects have the
added competitive advantage of being a renewable and environmentally
preferred (or "green") energy resource.
o Surveys indicate that 40 to 70 percent of California residential
consumers are willing to pay a 5 to 15 percent premium for green
power products. Current retail premiums for green power products
range from 0.7 to 3.1 cents per kWh.
o California is a world leader in the promotion and development of
clean renewable energy and its energy consumers are
environmentally aware. While the traditional power utilities are
cutting back on renewable expenditures, the State of California
has established a $543 million fund to subsidize existing and new
sources of renewable energy. HESI's analysis of the disbursement
criteria and delivery mechanisms, as well as CalEnergy's own
demonstrated expertise in acquiring such funds, all suggest that
the Power Projects will derive substantial benefits from
generating clean and renewable energy.
D-5
<PAGE>
SECTION 1.0
THE U.S. ELECTRIC POWER MARKET
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.
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
D-6
<PAGE>
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 in California
is Assembly Bill 1890, which achieves a number of goals, including:
o An immediate 10 percent rate reduction for residential and small
commercial users.
o A new power market structure with an Oversight Board (OB), an
Independent System Operator (ISO) and a PX.
o Limits the amount of costs (e.g. stranded assets) that are recoverable
in the transition to a deregulated market.
o Preserves public programs supporting energy efficiency, research &
development and low-income households.
o Provides approximately $540 million in subsidies to support renewable
energy programs, including geothermal power generation, such as the
Power Projects.
D-7
<PAGE>
SECTION 2.0
THE CALIFORNIA WHOLESALE POWER MARKET
In September 1996, the California legislature passed Assembly Bill 1890
("AB 1890") that deregulated parts of the electric power business in
California. The California market, originally scheduled to begin on January 1,
1998, was delayed to March 31, 1998. At that time, the PX and ISO began
operation. AB 1890 permits a fully competitive electric generation market to
phase in over a four-year transition period between January 1998 and March 2002
(the "Transition"). 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 shop for 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, 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. 2.1.1 Market Size
California's energy market is very large, with a non-coincident peak
energy demand of 51,280 MW(1) in 1996 and total energy consumption of 245,900
GWh. The average retail cost of electricity is 9.4 cents/kWh (1996 $), with
total electric revenue accounting for over $20 billion. Peak demand for
electricity is forecast to reach 68,100 megawatts by 2015 -- a growth rate of
1.5 percent per year between 1996 and 2015.
California's three largest IOU's -- PG&E, SCE, and SDG&E account for
188,470 GWh, or approximately 77 percent, of California's statewide energy
consumption.
2.1.1 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 gigawatt-hours 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.
- ----------
(1) "Electricity Report," California Energy Commission, August 1997.
D-8
<PAGE>
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. Demand for natural gas in 1990
exceeded 2,025 trillion cubic feet and one-third of California's electrical
energy is generated by natural gas. According to the California Energy
Commission, natural gas will account for 38 percent of energy used for power
generation by 2009.
TABLE 2-1
1996 NET SYSTEM POWER
(ELECTRIC GENERATION)
<TABLE>
<CAPTION>
FUEL TYPE GIGAWATT-HOURS PERCENT
- ------------------------------- ---------------- ----------
<S> <C> <C>
Coal * ...................... 40,283 15.6%
Large Hydro * ............... 64,958 25.1%
Natural Gas * ............... 84,110 32.5%
Nuclear ..................... 39,753 15.4%
Other(Oil, Diesel) .......... 693 0.3%
Biomass & Waste ............. 5,848 2.3%
Geothermal .................. 13,541 5.2%
Small Hydro ................. 5,767 2.2%
Solar ....................... 807 0.3%
Wind ........................ 3,041 1.2%
------ ----
Total ....................... 258,801 100%
======= ====
</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.(2)
2.1.2 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
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.
2.1.3 TREATMENT OF QUALIFYING FACILITIES (QFS)
Qualifying Facilities are currently compensated under a Transition Formula
- -- the Short Run Avoid Cost (SRAC) -- that in its current form is tied directly
to changes in the price of natural gas.
- ----------
(2) Deliverability on the Interstate Natural Gas Pipeline System, Energy
Information Administration, May 1998.
D-9
<PAGE>
However, this relationship is not likely to persist much longer. The 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 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 turn-over its transmission system to ISO control.
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. 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 PX MARKET
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, 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.
D-10
<PAGE>
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 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.
TABLE 2-2
MONTHLY AVERAGE CALIFORNIA PX PRICES -- APRIL 1998 TO JANUARY 1999
($/MWH)
<TABLE>
<CAPTION>
AVERAGE AVERAGE
MONTH ON-PEAK AVERAGE OFF-PEAK ALL HOURS
- ----- ------- ---------------- ---------
<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 Power Projects' QFs currently receive payment under the SRAC
"Transition Formula" for Southern California Edison (SCE) and San Diego Gas and
Electric (SDG&E). 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 and SDG&E. The gas prices (southern California
border prices) used to make this calculation are the same as the gas prices
used in the HESI model to produce the forecast of PX prices.
D-11
<PAGE>
FIGURE 2-1
CALIFORNIA PX DAILY PRICES -- HIGH, LOW AND AVERAGE
[GRAPH SHOWING CALIFORNIA PX PRICES DURING APRIL THROUGH DECEMBER PERIOD]
TABLE 2-3
SCE AND SDG&E ANNUAL AVERAGE
SHORT-RUN AVOIDED COSTS OF ENERGY
<TABLE>
<CAPTION>
PRICE OF GAS SCE AVOIDED SDG&E AVOIDED
YEAR ($/MMBTU) COST ($/MWH) COST ($/MWH)
- ---- --------- ------------ ------------
<S> <C> <C> <C>
1999 ......... 2.30 30.3 30.9
2000 ......... 2.38 31.2 31.7
2001 ......... 2.46 32.0 32.4
</TABLE>
- ----------
Note: The SRAC prices shown are weighted averages with the weights based on the
number of hours in each "time-of use" period.
While the SRAC is projected through 2001, we believe PX pricing will
replace SRAC pricing as early as the start of 2000.
SCE's 1995 forecast of avoided costs of energy is included in Appendix A
for comparison purposes, containing low, medium, and high forecasts.
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 is the divestiture by California IOUs of their
California fossil-fired generation, a process expected to be completed in the
next twelve months for all major utilities. 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 at least
several more months before determining the PX is functioning properly, a
determination which could be subject to several months of regulatory delay.
However, if PX market prices are substantially below transition SRAC prices,
utilities will be motivated to seek a change in SRAC pricing through the CPUC
more quickly. PX trading prices through June 1998 were substantially lower than
SRAC payments, a situation that was reversed in July. HESI's market price
forecasting supports the notion that the trend of annual average PX prices
being lower than SRAC will likely continue through the Transition years
(1999-2001) of California restructuring.
Given the above considerations, the change from Transition Formula to PX
pricing should occur at the beginning of Year 2000.
D-12
<PAGE>
SECTION 3.0
PX PRICE FORECAST: KEY ASSUMPTIONS AND METHODOLOGY
3.1 MODELING METHODOLOGY AND TECHNIQUES
To develop a forecast of PX 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 (Trade Mark) 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:
o individual power plant characteristics;
o transmission line interconnections, ratings, losses, and wheeling
rates;
o forecasts of resource additions and fuel costs; and
o forecasts of loads for each utility in the region.
MULTISYM (Trade Mark) 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.
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
Transition. Must-Take includes power from QF resources -- including the
Existing Power Projects -- nuclear units, and existing purchase power
agreements that have minimum-take provisions, is not subject to competition and
will be scheduled with the ISO on a must-take basis. Must-Run contracts are
between IOU generators and the ISO for the purposes of system reliability and
provide a capacity payment to the owners during all, or part, of the
Transition.
Must-Take units owned by municipal and public power agencies are assumed
to continue operating as they did in the past. Other Must-Take units, like QFs,
will continue to operate under existing contracts.
Units identified on the ISO's must-run 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" which allows the generators to cover
its fixed costs of operation through the ISO's payment. 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, like hydroelectric. There will be few
Must-Run "C" contracts which dedicate the units 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
with a 90 day 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
D-13
<PAGE>
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, 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, 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 CALIFORNIA MARKET
3.3.1 FORECAST HORIZON
The forecast period covers a twenty-year period beginning January 1,1999
and ending December 31, 2018.
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
2018 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 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.
D-14
<PAGE>
Table 3-1 lists the cost and performance assumptions for these resources.
TABLE 3-1
GENERIC RESOURCE CHARACTERISTICS (1996 DOLLARS)
<TABLE>
<CAPTION>
COMBUSTION COMBINED
UNIT CHARACTERISTIC TURBINE 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
Capital Cost ($/kW) ................... 300.00 500.00
Cost of Money (%) ..................... 10% 10%
Capital Amort. Period (years) ......... 15 15
</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.
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, the cost of new
resource additions, and is combined with expectations of real escalation to
result in future fuel prices. For this study inflation was assumed to be 2.5
percent.
3.3.10 FUEL PRICES
There are two principal fuels that drive electricity prices in the WSCC
region -- natural gas and coal.
NATURAL GAS
The natural gas price forecast utilized in this study was developed based
on the price of gas futures contracts for the 1999 period and estimates of gas
transportation costs associated with moving gas from the relevant gas basin to
the power plant. Each power plant in EMSS is assigned a fuel group. Each fuel
group is comprised of two components: a commodity price and a gas
transportation price.
D-15
<PAGE>
Gas Commodity Prices
Gas Commodity prices are tied to the San Juan basin in the southwest and
to the AECO C Hub in Canada, the two main gas-producing basins in the WSCC
region. The price of a series of gas futures contracts for gas delivered to the
San Juan Basin was used as the basis for the study's southwest gas basin price.
Gas basin prices at the AECO C Hub were based on forward gas futures at Henry
Hub plus the price of a financial swap tying Henry Hub prices to the AECO C
Hub. Although generators within the WSCC often use gas from more than one of
these basins, it is assumed that only one gas basin will set the key marginal
gas price for each generator. Each gas basin is mapped to generation regions
within the WSCC as discussed below:
San Juan
This basin is assumed to be the dominant gas basin supply generating
stations in the New Mexico, southern Nevada, Arizona, and California.
Additional pipeline and Local Distribution Company (LDC) charges must be added
to the San Juan price to yield the delivered price of gas to each generating
unit.
Alberta
This basin is assumed to supply generating stations within Alberta; the
same gas price is also applied to generators in British Columbia. Alberta gas
is also assumed to supply electric generators located in the following states:
Washington, Oregon, Idaho, Montana, Wyoming, Utah, and Northern Nevada. Again,
gas transportation costs are added to yield the gas prices to generators in
those states.
Gas Transport Prices
Pipeline transportation costs are added to basin prices to determine
Citygate gas prices. The gas transportation price is a combination of gas
pipeline charges and the cost to move gas across a gas LDC. In many areas,
Citygate prices are the relevant marginal gas costs used by electric generators
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 intrastate or LDC
transportation must be added to yield the dispatch price of gas. These costs
are based on the difference in historic Citygate and basin prices.
Additionally, the monthly price profile of the referenced basin's natural gas
futures contract is used to approximate the seasonality of the gas
transportation price.
Local Distribution Company Charges
For those generators with gas delivered by an LDC, additional charges must
be added. These charges were again estimated using data developed from relevant
regulatory filings and other publicly available company information. The key
generators receiving LDC gas service are California's electric generators. The
LDC charges for each of these were estimated using 1996 charges. These charges
were assumed to remain flat in nominal terms through the study horizon, based
on data that has been published by the California Energy Commission. HESI
assumes the utilities will not continue their current practice of recognizing
only a small portion of their total transportation costs in their dispatch
decisions; rather, the utilities will likely recognize their average
transportation cost in each dispatch decision, or run the risk of substantial
under-recovery of their transportation costs.
Total Gas Costs
The total cost of gas for each "gas price region" within the WSCC is
developed by combining the above costs to yield a forecast of delivered gas
prices.
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
D-16
<PAGE>
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.
3.3.11 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.
3.3.12 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.
3.3.13 INSURANCE
Insurance is calculated as 0.2 percent of the remaining, undepreciated
book value of the power plant.
3.3.14 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.
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 3-1. This characterization reflects the zones
proposed by the California IOUs in their PX applications to FERC.
D-17
<PAGE>
FIGURE 3-1
WSCC TRANSMISSION SYSTEM CONFIGURATION
[GRAPHIC SHOWING WSCC TRANSMISSION SYSTEM CONFIGURATION]
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.
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.
D-18
<PAGE>
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.
D-19
<PAGE>
SECTION 4
PX PRICE 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 will continue to be marginal cost producers
and therefore a major influence on the PX price. Any additional baseload
capacity, including the New Power Projects, would be low cost producers and
price takers. 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 the PX 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 1999-2018
The Base Case annual average PX price forecast for the Southern California
transmission area is presented in Table 4-1.
Annual average PX prices decrease at an annual average of 0.18 percent per
year from 1999 through 2001. This is the Transition period during which most
market players bid selling prices into the market which reflect their short run
marginal fuel 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 PX price increasing from
$28.16/MWh in 2001 to $33.99/MWh in 2002.
TABLE 4-1
BASE CASE PX PRICE FORECAST 1999 -- 2018, $/MWH
<TABLE>
<CAPTION>
ANNUAL AVERAGE AVERAGE
AVERAGE OFF-PEAK ON-PEAK
YEAR MCP $/MWH MCP $/MWH MCP $/MWH
---- --------- --------- ---------
<S> <C> <C> <C>
1999 28.31 23.18 33.94
2000 28.19 23.49 33.42
2001 28.16 22.71 34.16
2002 33.99 26.73 41.98
2003 35.23 27.79 43.43
2004 36.82 28.80 45.65
2005 40.09 30.97 50.14
2006 39.91 31.02 49.68
2007 40.19 31.02 50.30
2008 43.05 32.17 55.02
2009 42.04 31.77 53.35
2010 43.48 33.03 54.99
2011 43.48 33.08 54.93
2012 43.26 33.10 54.45
2013 45.70 34.37 58.18
2014 45.89 34.95 57.93
2015 47.57 35.87 60.46
2016 47.79 35.67 61.12
2017 49.16 36.78 62.79
2018 50.31 37.19 64.75
</TABLE>
D-20
<PAGE>
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 PX price increases at an annual average rate of 5.7
percent during this period.
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 PX price increases from $40.09/MWh in 2005
to $50.31/MWh by 2018 -- an average rate of increase of 1.8% per year, which is
less than the assumed rate of inflation.
4.2 SENSITIVITY CASES
4.2.1 LOW GAS 1 CASE
In the Low Gas Case 1, the inflation rate is set at zero, thereby keeping
the gas price flat relative to the Base Case. The gas price decreases each year
to the point it is 10 percent below the Base Case. It was held at a constant 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 period of recovery
and market demand.
A total of 6 simulations, representing the sample years listed in Table
4-2, were run to calculate the annual average PX prices for those years
(intervening years can be interpolated).
TABLE 4-2
PX PRICES UNDER LOW GAS CASE 1
<TABLE>
<CAPTION>
BASE CASE LOW GAS 1
ANNUAL AVE ANNUAL AVE PERCENT BELOW BASE
SAMPLE YEAR MCP $/MWH MCP $/MWH CASE PRICE
----------- --------- --------- ----------
<S> <C> <C> <C>
2000 28.19 27.92 1.0
2001 28.16 27.86 1.1
2005 40.09 38.70 3.5
2010 43.48 40.25 7.4
2014 45.89 42.89 6.5
2018 50.31 46.95 6.7
</TABLE>
4.2.2 LOW GAS 2 CASE
In the Low Gas Case 2, the Base Case gas price forecast is reduced by
three percent each year from 1999 through 2004, so that by 2004 the gas price
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 analysis. This scenario also requires an oversupply of
gas or a dramatic decline in demand followed by a lengthy period of recovery.
A total of 6 simulations, representing the sample years listed in Table
4-3, were run to calculate the annual average PX prices for those years.
TABLE 4-3
PX PRICES UNDER LOW GAS CASE 2
<TABLE>
<CAPTION>
BASE CASE LOW GAS 2
ANNUAL AVE ANNUAL AVE PERCENT BELOW BASE
SAMPLE YEAR MCP $/MWH MCP $/MWH CASE PRICES
----------- --------- --------- -----------
<S> <C> <C> <C>
2000 28.19 27.23 3.4
2001 28.16 26.47 6.0
2005 40.09 35.58 11.0
2010 43.48 38.47 12.0
2014 45.89 39.98 13.0
2018 50.31 43.31 14.0
</TABLE>
D-21
<PAGE>
SECTION 5
THE POWER PROJECTS AND THE CALIFORNIA MARKET
5.1 MARKET ANALYSIS RESULTS
This section presents an analysis of the Power Projects and their position
in the competitive California market and consists of two sets of comparisons:
1) a comparison of unit operating cost estimates provided by CEG and operating
costs of other types of generation; 2) a comparison of Power Project operating
costs and forecasted PX prices. The latter set of comparisons were performed
using the Base Case and two Low Gas price cases.
We expect all of the Power Projects to be low cost producers 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 Power
Projects. We selected the year 2005 for this analysis as it is the first year
in which we assumed a fully competitive market. The average operating cost of
the Power Projects in 2005 is $17.50/MWh -- which makes them low cost
producers. In fact, about 66 percent of the electricity produced in the WSCC in
2005 is generated from units with higher costs, a strong indication that the
Power Projects will be dispatched as baseload. The new units, Salton Sea Unit V
and the CE Turbo Project, are even better positioned at $10.00 and $9.30 per
MWh respectively. Of all the generation in the region, only hydroelectric
generators have lower operating costs.
TABLE 5-1
AVERAGE OPERATING COSTS BY PLANT TYPE IN THE WSCC FROM PROSYM MODEL SIMULATION
IN 20051
<TABLE>
<CAPTION>
ELECTRICITY AVERAGE OPERATING
PLANT TYPE GENERATION (GWH) COST ($/MWH)2
- ---------- ---------------- -------------
<S> <C> <C>
Internal Combustion Engines ......... 62 62.22
Gas Turbine ......................... 26,177 39.94
Geothermal (3)....................... 18,890 37.49
Gas/Cogeneration .................... 21,917 26.85
Gas/Combined Cycle .................. 151,804 25.41
YUMA COGENERATION ................... 351 23.70
Other Renewables (4)................. 6,737 23.29
Steam Plants ........................ 335,527 18.21
THE POWER PROJECTS (5)............... 2,879 17.50
Nuclear ............................. 35,885 13.33
Wind ................................ 3,435 10.45
SALTON SEA UNIT V (5)................ 421 10.00
CE Turbo Project (5)................. 82 9.30
Hydroelectric ....................... 246,434 4.91(7)
Total ............................... 846,867(8)
</TABLE>
- ----------
[1] 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.
[2] Cost based on fuel and variable O&M in nominal dollars.
[3] 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. In the case of the Power Projects, the steam supply
and facility owners are all Guarantors.
[4] Includes solar, biomass, and other renewables.
[5] Based on weighted facility operating cost (includes fuel, variable O&M and
fixed O&M) and consists of Salton Sea Units 1-5, Elmore, Leathers, Del
Ranch, Vulcan, and CE Turbo Project. Source: IPP Co.
[6] Cost based on average aggregated operating expenses of hydroelectric
facilities in the WSCC as reported to FERC on FERC Form 1.
[7] The generation totals in bold are not included in the total, but are
included in the total geothermal production. They are listed here to
provide relative scale to the market.
D-22
<PAGE>
Operating Costs of the Power Projects, in $/MWh, are compared to the Base
Case annual average PX prices in the figures below. All units have operating
costs below the annual average PX price, with the exception of the Leathers
unit, which has an operating cost above the annual average PX price in the
first year. This occurrence is because 1) Leathers is still in the S04 fixed
price energy period, and 2) certain costs such as geothermal royalties are
directly linked to revenues. In fact, all of the Power Projects' operating
costs are close to the off-peak PX price in 1999 through 2002 and significantly
below that in all years thereafter.
FIGURE 5-1
PX PRICES AND PROJECT OPERATING COSTS, UNITS I TO IV
[LINE CHART SHOWING PX PRICES AND OPERATING COSTS FOR UNITS I TO IV]
FIGURE 5-2
PX PRICES AND PROJECT OPERATING COSTS, OTHER UNITS
[LINE CHART SHOWING PX PRICES AND OPERATING COSTS FOR OTHER UNITS]
D-23
<PAGE>
FIGURE 5-3
PX PRICES AND NEW POWER PROJECT OPERATING COSTS
[LINE CHART SHOWING PX PRICES AND OPERATING COSTS FOR NEW PROJECTS]
FIGURE 5-4
PX PRICES AND YUMA OPERATING COSTS
[LINE CHART SHOWING PX PRICES AND OPERATING COSTS FOR YUMA PROJECT]
Most important is the comparison between the PX prices and the New Power
Projects, Salton Sea Unit V and CE Turbo Project as shown in Figure 5-3. These
units are about $20/MWh lower than the PX prices in 2000 and 2001, a difference
that increases to $30/MWh in 2005 and to nearly $40/MWh by 2018. The margin is
so significant it is extremely unlikely that any new generators with lower
operating costs will be built. It is very unlikely that any significant hydro
generation capacity, even with lower operating costs, due to siting and
licensing difficulties. Thus, we conclude that the New Power Projects will have
operating costs lower than all other generator types, except hydro, and will be
extremely well-positioned to be dispatched any hour in the year.
The differential between PX prices and operating costs is perpetuated in
the Low Gas Price Cases -- namely, operating costs are well below the PX
prices. PX prices in the Low Gas Case 1 range between $27.92/MWh in 2000 to
$46.95/MWh in 2018. In Low Gas Case 2, forecast PX prices range from $27.23/MWh
in 2000 to $43.31/MWh by 2018.
5.2 PX PRICES AND THE MARKET POSITION OF THE POWER PROJECTS
For an additional perspective of the relative position of the Power
Projects in the market, a table summarizing the frequency of PX prices
(Marginal Prices) is developed. This approach captures more
D-24
<PAGE>
of the hour by hour price variability than the preceding results. First, the
hourly PX 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 PX price is greater
than, or equal to, $20.30/MWh. This means that the Power Projects, with an
average operating cost of $17.50/MWh will be below the PX price 96 percent of
the time.
TABLE 5-2
PX PRICE FREQUENCY ANALYSIS IN SOUTHERN CALIFORNIA TRANSMISSION AREA, 2005
<TABLE>
<CAPTION>
MINIMUM% OF PX PRICE
TIME $/MWH
---- -----
<S> <C>
70 28.73
75 25.65
80 24.12
85 23.15
90 21.73
95 20.68
96 20.30
</TABLE>
D-25
<PAGE>
SECTION 6
THE CALIFORNIA GREEN POWER MARKET AND
ITS IMPLICATIONS FOR THE POWER PROJECTS
The sweeping regulatory changes initiated by Federal and California
regulators present significant opportunities for providers of electricity from
renewable energy sources. HESI believes a number of emerging market factors
bode well for the most efficient renewable energy projects in general including
the Existing Projects and the New Power Projects in particular. These factors
are listed and discussed below. First, however, this section presents a brief
summary of the renewable funding programs.
6.1 CEC RENEWABLE RESOURCE FUNDING
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, including the New and Existing Projects. 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. Existing facilities that are substantially
refurbished on or after September 23, 1996 can apply for funding from the new
technology category. 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 most of the consumer-side funds, and secondly, a consumer
information account.
6.2 EXISTING RENEWABLE RESOURCE ACCOUNT
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.
D-26
<PAGE>
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 3 --
TIER 1- BIOMASS, TIER 2 -- GEOTHERMAL, SMALL
SOLAR, THERMAL WIND HYDRO, OTHERS 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.
The amount of funds available annually to each tier declines over the four
year period. The CEC expects renewable generation facilities to become more
cost efficient and therefore more competitive as the unregulated market
evolves.
The subsidy is distributed monthly to renewable energy suppliers through a
cents per kWh payment. However, the payment is based on the lowest of three
possible calculations: 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), a pre-determined cents per kWh price cap, and a
funds adjusted price (the adjustment ensures that the amount disbursed does not
exceed the amount of funds available). The CEC designated target price and
price cap for existing technology tier 3 geothermal facilities are 3.0 and 1.0
cents per kWh, respectively. Thus the Existing Projects benefit from these
subsidies on a cent per kWh basis to the extent that the SRAC is below 3 cents
per kWh. SRAC prices applicable to Southern California Edison have recently
been in the 2.7 to 3.1 per kWh range.
6.3 NEW RENEWABLE RESOURCE ACCOUNT
The New Renewable Resources Account contains $162 million to support new
renewable electricity generation projects. According to the AB 1890
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.
TABLE 6-3
NEW RENEWABLE RESOURCE ACCOUNT ALLOCATIONS BY YEAR, $MILLIONS
<TABLE>
<CAPTION>
1998 1999 2000 2001 TOTAL
---- ---- ---- ---- -----
<S> <C> <C> <C> <C> <C>
New Renewables .......... $ 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.
The New Power Projects were awarded $31.3 million in this auction, one of
the largest subsidies granted by the CEC. This subsidy directly and positively
impacts the ability of the New Power
D-27
<PAGE>
Projects to produce competitively priced power. HESI also notes that the award
is a strong indication that the New Power Projects are among the lowest unit
cost producers of new renewable energy in California.
6.4 EMERGING RENEWABLES ACCOUNT
The purpose of the emerging renewable subsidy or Buy-Down 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 kilowatts or less, fuel cells that convert renewable fuels
such as methane gas into electricity, 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.
6.5 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' electricity
bill who purchase renewable energy will automatically be credited up to 1.5
cents for every kilowatt-hour of renewable electricity 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. This program directly reduces
the retail cost of renewable energy and thus makes power produced by the New
Power Projects more attractive to customers who otherwise would not have
purchased renewable-based power.
The $5.4 million consumer information account is to fund a renewable
energy public information program. The objective of the program is to help
build a viable customer-driver market for renewable energy through consumer
education.
6.6 DISCUSSION OF GREEN POWER MARKET BENEFITS
The New Power Projects can earn the market clearing price by selling power
directly into the PX. However, an alternative marketing strategy exists --
tapping into the retail market by selling directly to green power marketers.
Based on our analysis, we believe this option may reap additional benefits for
the New Power Projects. This section of the report discusses the potential
benefits to the New Power Projects from participation in the California green
power energy market.
Surveys consistently show that 40 to 70 percent of California residential
customers are willing to pay a 5 to 15 percent premium for green power
products.(1)(3) Current retail premiums for green power products range from
about 0.7 to 3.1 cents per kWh, depending upon the percentage of renewable
energy contained in the resource mix. Assuming that 50 percent of the New Power
Projects' output is sold into the green power market and that 2.5 cents per kWh
can be obtained from such sales, assumptions we believe to be reasonable, the
New Power Projects would earn additional revenue of approximately $6.5 million a
year.
- ----------
(3) See, for example a summary of customer survey results in "Selling Green
Power in California: Product, Industry, and Market Trends," by Ryan H.
Wiser and Steven J. Pickle, Ernest Orlando LawrenceBerkeley National
Laboratory, University of California, Berkeley, California, May 1998,
page 5.
D-28
<PAGE>
A study by the Lawrence Berkeley Laboratory2(4) estimates that between 25
to 60 thousand households will have switched to a green power energy source by
the end of 1998.(3) However, expectations among renewable energy marketers are
much higher. In proceedings before the California Energy Commission, marketers
suggested that the number of customers switching to a renewable energy source
could reach as high as 175,000 households within the first twelve months.
The study also suggests that a combination of rising consumer demand for
renewable energy and a scarcity of renewable energy projects will result in a
higher renewable energy price premium in the near future. This situation is
likely to continue until higher cost renewable projects are developed and
eventually brought on-line.
While California possesses a large amount of renewable generation, the
significant majority of it is either tied up in long term contracts with the
IOUs or is owned outright by them and thus not available to the green power
market in the near term. Consequently, the short-term supply of non-utility
renewable energy available to marketers is very small -- perhaps no more than
200 MW.(4) Because of this situation, new renewable resource projects that can
offer competitively priced power, such as the New Power Projects, will likely be
in a position to capture a significant portion of the rising premiums that are
excepted in the near future. Further, the improved market position of low cost
renewable energy providers is also likely to be reflected in more attractive
contract terms. According to the Lawrence Berkeley Laboratory report, the
majority of green power marketers expect contracts of one to five years to
become the standard within 5 years.(5) Contracts with existing renewable energy
providers are, in contrast, generally two years at a maximum.
In conclusion, the California green power market can potentially provide
significant additional benefits to the New Power Projects above and beyond the
proven financial return these plants can earn dealing through the PX market.
CEG has indicated to HESI that while it intends to fully exploit the green
power market, none of the anticipated benefits discussed in this section have
been reflected in its analysis.
- ----------
(4) The Ernest Orlando Lawrence Berkeley National Laboratory (Berkeley Lab) is
a multi-program national research facility operated by the University of
California for the Department of Energy (DOE). Its fundamental mission is
to provide national scientific leadership and technological innovation in
support of DOE's objectives. Founded in 1931, it is the oldest of the
national laboratories. The Laboratory specializes in research related to
technology and the environment, such as advanced materials science, life
sciences, energy efficiency and energy supply, and nuclear physics. The
Berkeley Lab has been awardednine Nobel prizes in the fields of physics and
chemistry for this research.
(5) IBID, page 5.
(6) IBID, page 26. In comparison, the CEC estimates about 500 MW. See "Policy
Report on AB 1890 Renewables Funding:Report to the Legislature," 1997.
(7) IBID, page 27.
D-29
<PAGE>
APPENDIX A
SCE SRAC FORECAST
SCE'S SRAC FORECAST
FOR 1995 THROUGH 2015
CENTS/KWH
<TABLE>
<CAPTION>
YEAR LOW MEDIAN HIGH
- ---- --- ------ ----
<S> <C> <C> <C>
1995 .......... 2.41 2.41 2.41
1996 .......... 2.48 2.51 2.54
1997 .......... 2.55 2.60 2.68
1998 .......... 2.72 2.83 2.97
1999 .......... 2.91 2.99 3.28
2000 .......... 3.11 3.22 3.60
2001 .......... 3.30 3.46 3.91
2002 .......... 3.42 3.59 4.13
2003 .......... 3.52 3.72 4.36
2004 .......... 3.62 3.88 4.61
2005 .......... 3.72 4.11 4.86
2006 .......... 3.83 4.31 5.16
2007 .......... 3.95 4.44 5.48
2008 .......... 4.06 4.59 5.82
2009 .......... 4.18 4.74 6.19
2010 .......... 4.31 4.89 6.59
2011 .......... 4.43 5.06 7.07
2012 .......... 4.57 5.22 7.60
2013 .......... 4.70 5.40 8.16
2014 .......... 4.84 5.58 8.76
2015 .......... 4.99 5.76 9.41
</TABLE>
D-30
<PAGE>
APPENDIX E
ASSESSMENT OF THE RESOURCE SUPPLYING
GEOTHERMAL FACILITIES
AT SALTON SEA, CALIFORNIA
FOR
CE GENERATION, LLC
OMAHA, NEBRASKA
BY
GEOTHERMEX, INC.
RICHMOND, CALIFORNIA
FEBRUARY 1999
E-1
<PAGE>
EXECUTIVE SUMMARY
Introduction
Presented herein are the review and analyses (the "Report") by GeothermEx,
Inc. ("GeothermEx") of the long-term resource sufficiency of the Salton Sea
Known Geothermal Resource Area (the "Salton Sea Field") to supply geothermal
resource to existing and proposed power plants and a proposed zinc recovery
facility. CalEnergy Company, Inc. ("CECI"), has established CE Generation, LLC
("CEG") to issue notes and bonds to investors which are supported by revenue
produced by the power plants which are as follows:
o Salton Sea Guarantors: Salton Sea Units I, II, III and IV ("Salton Sea
Projects"), including the construction of Salton Sea Unit V;
o Partnership Guarantors: partnership interests in the Vulcan, Del Ranch
(Hoch), Elmore and Leathers Projects (the "Partnership Projects"),
including certain royalty and other payments; and
o Royalty Guarantor: Royalty interests paid by the Royalty Projects
consisting of three of the Partnership Projects.
Affiliates of CEG are constructing two additional power facilities at the
Salton Sea: 1) Unit V, a 49 MW (net) facility; and 2) the CE Turbo Project, a
10 MW (net) facility. A third project, a zinc recovery facility, is being
constructed by a CECI affiliate. Collectively, these are the "New Projects."
GeothermEx has prepared this report as an independent resource consultant for
CEG and for future potential bondholders.
Scope of Work and Assumptions
GeothermEx has reviewed the behavior of the wells and resource supplying
the existing geothermal power plants in the Salton Sea Field, located in
Imperial County, California. Well locations are shown in figure 1. The purposes
of this report are: 1) to assess the long-term resource sufficiency and
suitability for supplying the existing plants and the proposed additional
facilities mentioned above and 2) to assess the reasonableness of the projected
workover and wellfield capital budget for the program.
In the preparation of this report and the opinions expressed, GeothermEx
has made certain assumptions about conditions which may exist or events which
may occur in the future. The principal assumptions and considerations made and
the database used by GeothermEx in developing the results and conclusions
presented in this report are described below.
GeothermEx has provided several due-diligence evaluations for the Salton
Sea Projects and the Partnership Projects. These have included evaluations
prepared in 1995 and 1998 in support of the first and third bond offerings of
Salton Sea Funding Corporation ("Funding Corporation"). As such, GeothermEx
holds a large amount of information on the Salton Sea wells, which has been
presented in numerous technical reports in the past.
For the current study, CEG provided updated production and injection
histories from the California Division of Oil, Gas, and Geothermal Resources
(CDOGGR), new chemical analyses, information on the drilling and logging of
recent wells, and budget information for future wellfield expenditures.
Together, all of this information constitutes the database used in the present
study. Reports that have formed a significant part of GeothermEx's current
evaluation are included in the document list in section 5.
GeothermEx has independently reviewed and relied upon data from the Salton
Sea Field supplied by CEG, in addition to other data mentioned above. In our
opinion, the data is reliable and accurate, based on our extensive knowledge of
the resource and the history of operations at the Salton Sea Field.
E-2
<PAGE>
Conclusions
Based upon our review and the considerations and assumptions set forth
above, we have reached the following conclusions:
o The Salton Sea Field is highly productive and wells have historically
behaved favorably with minimal flow rate or pressure declines.
o The proposed Unit V will utilize the heat energy in reinjection brine
which is presently separated from the steam supplying Units I -- IV.
The nominal additional production fluid needed for Salton Sea Unit V
will be supplied from existing wellhead capacity.
o The nominal additional production fluid needed for the CE Turbo
Project can be supplied by spare capacity at existing wells. In
addition, a new production well is planned and budgeted for drilling
in 1999.
o Numerical simulation studies undertaken to date forecast acceptable
well behavior for the existing and planned level of power generation
and zinc recovery. Well behavior has historically been consistent with
results predicted by earlier simulation models; therefore, future well
behavior is expected to be adequate to support the Salton Sea,
Partnership and New Projects.
o The recoverable geothermal energy reserves from the reservoir are more
than sufficient to support existing projects and the planned
additional increments of capacity resulting in a total capacity of
326.4 MW. We estimate that 1,200 MW of reserves are available within
the portion of the Salton Sea Field dedicated to the Salton Sea,
Partnership and New Projects.
o The recoverable reserves of geothermal energy will not be affected by
either the planned capacity expansion or the zinc recovery project.
o In unescalated dollars, CEG's projected budget through 2020 includes
$70.4 million for wellfield capital (new wells, re-drills, and
tie-ins) and $38.4 million for well workovers. The budget for
wellfield costs is reasonable and should allow the CEG facilities to
achieve the forecasted levels of electrical generation and zinc
production.
1. OVERVIEW AND DESCRIPTION OF THE SALTON SEA GEOTHERMAL FIELD
1.1 DEVELOPMENT HISTORY AND PRESENT STATUS
CEG and its subsidiaries own and operate eight geothermal power plants and
propose to develop two additional power plants in the Salton Sea Field. The
plant names, capacities and start-up dates are listed below.
<TABLE>
<CAPTION>
PLANT NAME CAPACITY (NET MW) START-UP DATE
- ---------- ----------------- -------------
<S> <C> <C>
Vulcan 34.0 1986
Del Ranch (Hoch) 38.0 1989
Elmore 38.0 1989
Leathers 38.0 1990
Unit I 10.0 1982
Unit II 20.0 1990
Unit III 49.8 1989
Unit IV 39.6 1996
Unit V 49.0 2000(planned)
CE Turbo Project 10.0 2000(planned)
-----
Total 326.4
</TABLE>
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<PAGE>
1.2 NEW PLANTS
Salton Sea Unit V is scheduled to start-up in 2000, concurrently with a
facility to recover zinc from the geothermal brine. The CE Turbo Project is
scheduled for start-up in mid-2000. The third of the New Projects is the
30,000-metric-tonne zinc recovery facility. Satellite process facilities will
be located at four existing power plant facilities: Leathers, Elmore,
Vulcan/Hoch and the Region 1 (Units I -- V) brine processing facility. These
sites will be connected by pipelines to the central processing facility, which
will process the solution from the satellite plants into a final marketable
product of metallic zinc.
2. WELL BEHAVIOR
2.1 HISTORICAL
A total of about 130 production or injection wells have been drilled
within the Salton Sea field to date. Production and injection histories were
obtained from the archives of the CDOGGR, which receives monthly average flow
rate (or injection rate), wellhead pressure and wellhead temperature from the
field operators. GeothermEx has adjusted the production and injection rates
from the CDOGGR archives to reflect actual steam usage rates as reported by the
CEG facilities. To the best of our knowledge, this information represents the
most consistent and complete production and injection database available.
There are 31 active production wells in the Salton Sea field with an
average capacity of 9 MW per well, which exceeds the US industry average. The
plants are often operated at higher levels than their net capacity ratings, and
many of the wells are routinely operated in a throttled condition that does not
draw on their full capacity.
Both the production and injection wells have been worked over periodically
because of scaling and corrosion. In general, these workovers have helped to
maintain the productivity and injectivity of the wells; however, as in most
geothermal projects, it has been necessary to redrill some wells because of
mechanical problems which sometimes occur during a workover operation, or
because of other mechanical damage.
Despite the need for workovers and/or redrills, the project wells have
behaved very favorably to date. Flow rate declines have been small, and many
wells have excess capacity.
In May 1996, output from the field was increased when new wells were
brought on line to supply Unit IV. As shown in figure 2, production and
injection rates have been relatively stable since then.
2.2 ANTICIPATED WELL AND FIELD BEHAVIOR
It will be shown in the following chapter of this report that the
recoverable geothermal energy reserves are more than sufficient to support the
existing projects and the New Projects. While it is a necessary condition,
adequacy of geothermal reserves by itself does not guarantee commercial success
of a geothermal project. Future behavior of the field, in general, and the
wells, in particular, will dictate how much of these reserves can be
economically recovered. As mentioned above, the wells have behaved very
favorably to date, and CEG is using numerical modeling to forecast and optimize
future well and field behavior under various operating scenarios.
GeothermEx independently developed a numerical simulation model of the
Salton Sea field in 1997and 1998, and CEG independently developed a numerical
simulation of the Salton Sea Field in 1998. These models are used to evaluate
future well and reservoir behavior in response to production and injection
under specified scenarios, including the modification of injection well
locations to optimize zinc recovery, and the additional production required to
supply Unit V and the CE Turbo project. CEG developed and utilizes its model as
a reservoir management tool, to maximize both power production and zinc
recovery from the field. The CEG model incorporates the most recent production
and injection data, as well as current development and operational plans. The
results of
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<PAGE>
both modeling efforts indicate that the existing and planned production
facilities can be supported by the existing wells (maintained as needed) and by
those budgeted wells which may be drilled in the near future.
3. RECOVERABLE GEOTHERMAL ENERGY RESERVES
This study confirms that there are sufficient geothermal energy reserves
to support the existing projects and the New Projects. For calculating the
reserves, the area under consideration includes the acreage dedicated to Units
I -- V, and the Vulcan, Del Ranch (Hoch), Elmore and Leathers units. This is
referred to herein as the "Subject Area".
The first step in making a volumetric reserve estimate is to calculate the
heat energy in place within the subject area using the subsurface temperature
distribution. The volume considered is an irregular block confined by the
downward vertical projections of the boundaries of the subject area between
elevations of -1,500 feet and -6,500 feet (msl). The volume of reservoir
considered is also limited by temperature constraints; the minimum acceptable
temperature used herein is 380 degreesF. Certain assumptions were then made
regarding the recoverability of the heat-in-place, the efficiency of converting
heat energy to electrical energy, and the annual plant capacity factor. The
methodology is described in detail below.
Reserves in a geothermal area can be expressed as the maximum electric
power plant capacity that can be supplied commercially for 30 years. Volumetric
calculation of reserves requires estimation of four parameters:
1. Gross thermal energy in place (H, Btu);
2. Fraction of the gross in-place thermal energy that can be recovered
commercially (recovery factor, R);
3. Fraction of recoverable thermal energy that can be converted to
electrical energy (conversion efficiency, E); and
4. Power plant load factor (F).
Using the above-defined quantities, the maximum sustainable power plant
capacity is expressed as:
H o R o E
MW = 1.11 x 10-12 ---------
F (1)
where MW= average gross MWe over 30 years.
We can calculate the gross heat in place as:
H = (Cvr + Cvb) V (T -- To) (2)
where Cvr = volumetric specific heat of rock (Btu/ft3/degreesF)
Cvb = volumetric specific heat of brine (Btu/ft3/degreesF)
V = reservoir bulk volume (ft3),
T = average reservoir temperature (degreesF), and
To = a reference or base temperature (degreesF).
Within the Subject Area, the volume of rock with temperatures exceeding
380 degreesF (parameter V in equation 2 above) was calculated to be
1.26 x 10(12) cubic feet. Average temperature (T) was estimated to be
522 degreesF on the basis of the subsurface temperature distribution.
In equation (2),
Cvr = Pr Cr (1-- o NS) (3),
and Cvb = Pf Cf - o NS (4),
where Pf = bulk density of reservoir fluid,
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<PAGE>
= 60 lbs/ft(3)
Cf = specific heat capacity of reservoir brine,
= 0.85 Btu/lb/ degreesF,
P = reservoir porosity,
= 20%;
Pr = bulk density of rock matrix,
= 168 lbs/ft3;
Cr = specific heat capacity of rock matrix,
= 0.255 Btu/lb/ degreesF; and
NS = net sand fraction
= 0.35.
Using the above estimates of the various parameters, the heat in place (H)
is calculated for the subject area using equation 2:
H = 5.84 x 10(13) (522 -- To) Btu for the subject area. (5).
Now the parameters R (recovery factor), E (conversion efficiency) and F
(power plant capacity factor) need to be estimated to complete the calculation
of gross MW available for 30 years. We assume a conversion efficiency of 15%,
which is typical for power plants like those presently in operation at Salton
Sea, and a capacity factor of 85%. The recovery factor (R) cannot be readily
estimated as it depends critically on the degree of heterogeneity in the
reservoir, whereas the model used for volumetric reserve estimation is assumed
to be homogeneous.
For the purpose of volumetric reserve estimation, the following approach
was considered to estimate an approximate value for R. In this case, R is
estimated to be 0.35, based on the reasonable assumptions that: (a) 35% of the
reservoir bulk volume is permeable because the average sand fraction in the
Salton Sea reservoir is 35%; (b) there is no in-situ boiling; and (c) the
injected water can cool the entire porous and permeable volume (sand layers) of
the reservoir (including the sand grains) to T0 (here assumed to be the
temperature of the power plant waste water, or 225 degreesF). We have
conservatively assumed essentially no heat recovery from shale for our
single-phase heat extraction model. This assumption is balanced to some degree
by assuming that there is 100% sweep of all sand layers by injection water.
Our analysis is that 30-year energy reserves of 1,200 MW were calculated
for the subject area. A total capacity of 267.4 MW has been installed to date
and another 59 additional MW (Salton Sea Unit V and the CE Turbo Project) are
planned, resulting in a total capacity of 326.4 MW. Accordingly, our analysis
indicates that the energy reserves are more than sufficient to support the
existing and planned facilities within the subject property.
4. REVIEW OF FUTURE WELLFIELD COSTS
CEG's estimate of projected wellfield costs includes two components. The
first component is wellfield capital, which comprises new production wells, new
injection wells, and tie-ins for these wells (that is, connections from the
wellheads to the gathering system pipelines). The second component is workovers
(that is, repairs of existing wells to correct such problems as wellbore
scaling or casing damage). Figure 3 shows the projected annual expenditures for
these components through the year 2020. The dollar values in figure 3 and in
the following discussion are in unescalated 1998 dollars.
The total projected budget for wellfield costs from 1999 to 2020 is $108.8
million, of which $70.4 million is for wellfield capital and $38.4 million is
for workovers. Wellfield costs are expected to be higher in the first three
years (through 2001), reflecting the planned drilling of several new production
wells with titanium casing and several new injection wells. Workover costs are
also
E-6
<PAGE>
somewhat higher in the first few years, reflecting continuing repairs to older
wells with carbon steel casing that are being gradually replaced by new wells.
The titanium casing in the new production wells is less prone to wellbore
scaling, and the injection water after start-up of the zinc extraction
facilities is expected to have less entrained solids, which should extend the
lives of the injection wells. For these reasons, annual workover expenditures
after the first few years of the project life are expected to be lower.
GeothermEx agrees with this conclusion.
New production wells with titanium casing are expected to cost about $4
million each. New injection wells are expected to cost somewhat less (about
$2.5 million each) because they do not require titanium casing. A re-drill
(that is, a well drilled to a new down-hole location from an existing wellhead)
is expected to cost about $0.8 million. The number, timing, and location of new
wells during the project life will depend on field performance. However, the
projected budget contains sufficient funds for roughly 10 new producers, 10 new
injectors, and 8 re-drills, including the costs of tie-ins for these wells. In
GeothermEx's opinion, the budget amounts are reasonable estimates for the
forecasted levels of electrical generation and zinc production over the next 20
years.
5. DOCUMENT LIST
ADA International Consulting, Ltd., "TETRAD Version 12.0 User's Manual."
Calgary, Alberta, Canada. Reservoir simulation software.
California Division of Oil, Gas, and Geothermal Resources, "Monthly
Reports of Geothermal Operations." Production and injection statistics for
Salton Sea wells.
CE Generation, LLC
-- maps of existing and proposed well locations in Salton Sea Field
-- recent production and injection statistics for Salton Sea wells
-- database of chemical analyses from Salton Sea wells
-- input deck for CEG's numerical simulation of Salton Sea Field using
TETRAD software
-- Imperial Valley Capital Expenditures by Year (budget forecast of
wellfield costs)
GeothermEx (1995), "Assessment of the Geothermal Resource Underlying
Geothermal Power Projects, Salton Sea Geothermal Field, California." Report
prepared for Salton Sea Funding Corporation, Omaha, Nebraska.
GeothermEx (1998), "Assessment of the Resource Supplying Geothermal
Facilities at Salton Sea, California." Report prepared for Salton Sea Funding
Corporation, Omaha, Nebraska.
E-7
<PAGE>
[MAP OF THE SALTON SEA GEOTHERMAL AREA]
E-8
<PAGE>
[LINE CHART SHOWING HISTORICAL PRODUCTION RATE]
[LINE CHART SHOWING HISTORICAL INJECTION RATE]
E-9
<PAGE>
FIGURE 3. PROJECTED EXPENDITURES FOR WELLFIELD CAPITAL AND WORKOVERS AT
CE GENERATION'S GEOTHERMAL FACILITIES AT SALTON SEA, CALIFORNIA
[BAR GRAPH SHOWING PROJECTED EXPENDITURES FOR WELLFIELD CAPITAL AND WORKOVERS]
E-10
<PAGE>
ADDRESS OF EXCHANGE AGENT:
CHASE MANHATTAN BANK AND TRUST COMPANY, NATIONAL ASSOCIATION
101 CALIFORNIA STREET, NO. 2725
SAN FRANCISCO, CALIFORNIA 94111
TELEPHONE: (415) 954-9508
FAX: (415) 693-8850
<PAGE>
PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
CE Generation, LLC, a Delaware limited liability company, is empowered by
Section 18-108 of the Delaware Limited Liability Company Act, subject to the
procedures and limitations stated therein, to indemnify any person against
expenses (including attorneys' fees), judgments, fines and amounts paid in
settlement actually and reasonably incurred by him in connection with any
threatened, pending or completed action, suit or proceeding in which such
person is made a party by reason of his being or having been a director,
officer, employee or agent of CE Generation, LLC. The statute provides that
indemnification pursuant to its provisions is not exclusive of other rights of
indemnification to which a person may be entitled under any agreement, vote of
members or disinterested directors or otherwise. The limited liability company
operating agreement of CE Generation, LLC provides for indemnification of the
managers, officers and directors of CE Generation, LLC to the full extent
permitted by the Delaware Limited Liability Company Act.
MidAmerican Energy Holdings Company maintains an insurance policy
providing for indemnification of the officers and directors of its subsidiaries
against liabilities and expenses incurred by any of them in certain stated
proceedings and under stated conditions.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- --------------------------------------------------------------------------------------
<S> <C>
3.1* Certificate of Formation of CE Generation, LLC
3.2* Limited Liability Company Operating Agreement of CE Generation, LLC
4.1* Indenture, dated as of March 2, 1999, by and between CE Generation, LLC and Chase
Manhattan Bank and Trust Company, National Association
4.2* Form of First Supplemental Indenture to be entered into by and between CE Generation,
LLC and Chase Manhattan Bank and Trust Company, National Association, Trustee
4.3* Purchase Agreement, dated February 24, 1999, by and among CE Generation, LLC,
Credit Suisse First Boston Corporation and Lehman Brothers, Inc.
4.4* Exchange and Registration Rights Agreement, dated as of March 2, 1999, by and among
CE Generation, LLC, Credit Suisse First Boston Corporation and Lehman Brothers, Inc.
4.5* Debt Service Reserve Letter of Credit and Reimbursement Agreement, dated as of
March 2, 1999, by and among CE Generation, LLC, the banks named therein and Credit
Suisse First Boston, as Agent
4.6* Deposit and Disbursement Agreement, dated as of March 2, 1999, by and among CE
Generation, LLC, Magma Power Company, Salton Sea Power Company, Falcon Seaboard
Resources, Inc., Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company,
California Energy Development Corporation, CE Texas Energy LLC and Chase
Manhattan Bank and Trust Company, National Association, as Collateral Agent and
Depositary Bank
</TABLE>
II-1
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ---------------------------------------------------------------------------------------
<S> <C>
4.7* Intercreditor Agreement, dated as of March 2, 1999, by and among CE Generation, LLC,
Magma Power Company, Salton Sea Power Company, Falcon Seaboard Resources, Inc.,
Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company, California Energy
Development Corporation, CE Texas Energy LLC, Credit Suisse First Boston and Chase
Manhattan Bank and Trust Company, National Association, as Trustee, Collateral Agent
and Depositary Bank
4.8* Assignment and Security Agreement, dated as of March 2, 1999, by and among Magma
Power Company, Salton Sea Power Company, Falcon Seaboard Resources, Inc., Falcon
Seaboard Power Corporation, Falcon Seaboard Oil Company, California Energy
Development Corporation, CE Texas Energy LLC, Credit Suisse First Boston and Chase
Manhattan Bank and Trust Company, National Association, as Collateral Agent
4.9* Assignment and Security Agreement, dated as of March 2, 1999, by and between CE
Generation, LLC and Chase Manhattan Bank and Trust Company, National Association,
as Collateral Agent
4.10* Pledge Agreement (SSPC Stock), dated as of March 2, 1999, by Magma Power Company
in favor of Chase Manhattan Bank and Trust Company, National Association, as
Collateral Agent
4.11* Pledge Agreement (FSRI Stock and CEDC Stock), dated as of March 2, 1999, by CE
Generation, LLC in favor of Chase Manhattan Bank and Trust Company, National
Association, as Collateral Agent
4.12* Securities Account Control Agreement, dated as of March 2, 1999, by and among CE
Generation, LLC, Magma Power Company, Salton Sea Power Company, Falcon Seaboard
Resources, Inc., Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company,
California Energy Development Corporation, CE Texas Energy LLC, Credit Suisse First
Boston and Chase Manhattan Bank and Trust Company, National Association, as
Collateral Agent and Depositary Bank
5.1 Opinion of Latham & Watkins regarding the validity of the new securities
10.1 Trust Indenture, dated as of July 21, 1995, between Chemical Trust Company of
California and Salton Sea Funding Corporation (incorporated by reference to Exhibit
4.1(a) to Salton Sea Funding Corporation's Registration Statement on Form S-4 dated
August 9, 1995, 33-95538)
10.2 First Supplemental Indenture, dated as of October 18, 1995, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(b) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated August 9, 1995, 33-95538)
10.3 Second Supplemental Indenture, dated as of July 20, 1996, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(c) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated July 2, 1996, 333-07527)
10.4 Third Supplemental Indenture, dated as of July 29, 1996, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(d) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated July 2, 1996, 333-07527)
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ----------------------------------------------------------------------------------------------
<S> <C>
10.5 Fourth Supplemental Indenture, dated as of October 13, 1998, between Chase Manhattan
Bank and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(e) to Salton Sea Funding Corporation's Form
10-K/A dated March 27, 1999)
10.6 Fifth Supplemental Indenture, dated as of February 16, 1999, between Chase Manhattan
Bank and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(f) to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
10.7 Sixth Supplemental Indenture, dated as of June 29, 1999, between Chase Manhattan Bank
and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(g) to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
10.8 Amended and Restated Salton Sea Guarantors Credit Agreement, dated as of
October 13, 1998, by and among Salton Sea Power Generation L.P., Salton Sea Brine
Processing L.P., Salton Sea Power, L.L.C. and Fish Lake Power Company (incorporated
by reference to Exhibit 4.12 to Salton Sea Funding Corporation's Registration Statement
on Form S-4 dated June 29, 1999, 333-79581)
10.9 Second Amended and Restated Partnership Guarantors Credit Agreement, dated as of
October 13, 1998, by and among CalEnergy Operating Corporation, Vulcan Power
Company, Conejo Energy Company, Niguel Energy Company, San Felipe Energy
Company, BN Geothermal Inc., Del Ranch, L.P., Elmore, L.P., Leathers, L.P., Vulcan/BN
Geothermal Power Company, CalEnergy Minerals LLC, CE Turbo LLC and Salton Sea
Funding Corporation (incorporated by reference to Exhibit 4.19 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
10.10 Amended and Restated Deposit and Disbursement Agreement, dated as of October 13,
1998, by and among Salton Sea Funding Corporation, Salton Sea Power Generation L.P.,
Salton Sea Brine Processing L.P., Salton Sea Power, L.L.C., Fish Lake Power Company,
CalEnergy Operating Corporation, Vulcan Power Company, Conejo Energy Company,
Niguel Energy Company, San Felipe Energy Company, BN Geothermal Inc., Del Ranch,
L.P., Elmore, L.P., Leathers, L.P., Vulcan/BN Geothermal Power Company, CalEnergy
Minerals LLC, CE Turbo LLC, and Chase Manhattan Bank and Trust Company, National
Association, as Collateral Agent and Depositary Agent (incorporated by reference to
Exhibit 4.14 to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated June 29, 1999, 333-79581)
10.11** Amendment and Restatement, dated as of September 30, 1994, of the Loan Agreement,
dated as of December 29, 1992, by and among Saranac Power Partners, L.P., County of
Clinton Industrial Development Agency, North Country Gas Pipeline Corporation, the
financial institutions party thereto, Credit Suisse First Boston and General Electric Capital
Corporation
10.12** Amended and Restated Security Deposit Agreement, dated as of October 7, 1994, among
Saranac Power Partners, L.P., Credit Suisse, General Electric Capital Corporation, TPC
Saranac Partner One, Inc., TPC Saranac Partner Two, Inc., and The Fuji Bank and Trust
Company
10.13** Installment Sale Agreement, dated as of December 29, 1992, by and between County of
Clinton Industrial Development Agency and Saranac Power Partners, L.P.
</TABLE>
II-3
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- -------------------------------------------------------------------------------------
<S> <C>
10.14 Second Amended and Restated Agreement of Limited Partnership of Saranac Power
Partners, L.P., dated as of May 13, 1994, by and among Saranac Energy Company, Inc.,
TPC Saranac Partner One, Inc. and TPC Saranac Partner Two, Inc., as amended by the
First Amendment to Second Amended and Restated Agreement of Limited Partnership
of Saranac Power Partners, L.P., by and among Saranac Energy Company, Inc., TPC
Partner One, Inc., TPC Saranac Partner Two, Inc. and General Electric Capital
Corporation (incorporated by reference to Exhibit 10.2 to CalEnergy Company, Inc.'s
Form 10-Q for the quarterly period ended September 30, 1996)
10.15** Amended and Restated Term Loan Agreement, dated as of December 30, 1988, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 1 to
Amended and Restated Term Loan Agreement, dated as of March 1, 1989, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 2 to
Amended and Restated Term Loan Agreement, dated as of April 28, 1989, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 3 to
Amended and Restated Term Loan Agreement, dated as of June 1, 1990, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 4 to
Amended and Restated Term Loan Agreement, dated as of April 15, 1991, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., and Amendment No. 5
to Amended and Restated Term Loan Agreement, dated as of June 29, 1995, among
Kansallis-Osake-Pankki, Credit Suisse, the other lenders named therein and Power
Resources, Inc.
10.16 Contract for the Purchase and Sale of Electric Power from the Salton Sea Geothermal
Facility, dated May 9, 1987, between Southern California Edison Company and Earth
Energy, Inc. (incorporated by reference to Exhibit 10.4 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.17 Amendment No. 1 to Contract for the Purchase and Sale of Electric Power from the
Salton Sea Geothermal Facility, dated March 30, 1993, between Southern California
Edison Company and Earth Energy, Inc. (incorporated by reference to Exhibit 10.5 to
Salton Sea Funding Corporation's Registration Statement on Form S-4 dated August 9,
1995, 33-95538)
10.18 Amendment No. 2 to Contract for the Purchase and Sale of Electric Power from the
Salton Sea Geothermal Facility, dated November 29, 1994, between Southern California
Edison Company and Salton Sea Power Generation L.P. (incorporated by reference to
Exhibit 10.6 to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated August 9, 1995, 33-95538)
10.19 Contract for the Purchase and Sale of Electric Power, dated April 16, 1985, between
Southern California Edison Company and Westmoreland Geothermal Associates
(incorporated by reference to Exhibit 10.7 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.20 Amendment No. 1 to Contract for the Purchase and Sale of Electric Power, dated
December 18, 1987, between Southern California Edison Company and Earth Energy, Inc.
(incorporated by reference to Exhibit 10.8 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.21 Power Purchase Contract, dated April 16, 1985, between Southern California Edison
Company and Union Oil Company of California (incorporated by reference to Exhibit
10.9 to Salton Sea Funding Corporation's Registration Statement on Form S-4 dated
August 9, 1995, 33-95538)
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ------------------------------------------------------------------------------------------
<S> <C>
10.22 Power Purchase Contract, dated November 19, 1994, between Southern California Edison
Company, Salton Sea Power Generation L.P. and Fish Lake Power Company
(incorporated by reference to Exhibit 10.10 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.23 Long Term Power Purchase Contract, dated March 1, 1984, as amended, between
Southern California Edison Company and Vulcan/BN Geothermal Power Company, as
successor to Magma Electric Company (incorporated by reference to Exhibit 10.26 to
Salton Sea Funding Corporation's Registration Statement on Form S-4 dated July 2, 1996,
333-07527)
10.24 Long Term Power Purchase Contract, dated June 15, 1984, as amended, between Southern
California Edison Company and Elmore, L.P., as successor to Magma Electric Company
(incorporated by reference to Exhibit 10.31 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.25 Long Term Power Purchase Contract, dated August 16, 1985, as amended, between
Southern California Edison Company and Leathers, L.P., as successor to Imperial Energy
Corporation (incorporated by reference to Exhibit 10.36 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.26 Long Term Power Purchase Contract, dated February 22, 1974, as amended, between
Southern California Edison Company and Del Ranch, L.P., as successor to Magma
Electric Company (incorporated by reference to Exhibit 10.41 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.27** Amended and Restated Power Sales Agreement, dated as of November 1, 1988, by and
between CalEnergy Minerals LLC and Salton Sea Power L.L.C.
10.28 Agreement between New York State Electric & Gas Corporation and Saranac Energy
Company, Inc., dated as of April 27, 1987 and Amendment No. 1 to Power Purchase
Agreement between New York State Electric & Gas Corporation and Saranac Energy
Company, Inc. dated August 29, 1991 (incorporated by reference to Exhibit 10.1 to
CalEnergy Company, Inc.'s Form 10-Q for the quarterly period ended September 30,
1996)
10.29** Amendment No. 2 to Power Purchase Agreement between New York State Electric &
Gas Corporation and Saranac Energy Company, Inc. dated February 24, 1994
10.30** (Power Purchase) Agreement, dated July 30, 1986, between Falcon Seaboard Oil
Company and Texas Utilities Electric Company, First Amendment to (Power Purchase)
Agreement, dated December 23, 1986, between Falcon Seaboard Oil Company and Texas
Utilities Electric Company, and Second Amendment to (Power Purchase) Agreement,
dated May 27, 1988, between Falcon Seaboard Oil Company and Texas Utilities Electric
Company
10.31 Standard Offer Number 2 for Power Purchase with a Firm Capacity Qualifying Facility
effective June 13, 1990 between San Diego Gas & Electric Company and Bonneville
Pacific Corporation (incorporated by reference to Exhibit 10.42 to CalEnergy Company,
Inc.'s Form 10-K for the fiscal year ended December 31, 1993)
10.32 Amendment No. 1 to Standard Offer Number 2 for Power Purchase with a Firm Capacity
Qualifying Facility dated September 25, 1990 between San Diego Gas & Electric
Company and Bonneville Pacific Corporation (incorporated by reference to Exhibit 10.43
to CalEnergy Company, Inc.'s Form 10-K for the fiscal year ended December 31, 1993)
</TABLE>
II-5
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- -------------------------------------------------------------------------------------------
<S> <C>
10.33** Ground Lease, dated as of November 24, 1993, by and between Imperial Irrigation
District, Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P., and First
Amendment to Ground Lease, dated as of December 15, 1993, by and between Imperial
Irrigation District, Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P.
10.34** Ground Lease, dated as of March 31, 1993, by and between Magma Land Company I,
Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P.
10.35** Ground Lease, dated as of October 26, 1988, by and between Magma Power Company
and Leathers, L.P., and Clarification and Amendment, dated as of June 17, 1996, between
Magma Power Company and Leathers, L.P.
10.36** Ground Lease, dated as of March 14, 1988, by and between Magma Power Company and
Del Ranch, Ltd., and Clarification and Amendment, dated as of June 17, 1996, between
Magma Power Company and Del Ranch L.P.
10.37** Ground Lease, dated as of March 14, 1988, by and between Magma Power Company and
Elmore, Ltd., and Clarification and Amendment, dated as of June 17, 1996, by and
between Magma Power Company and Elmore, L.P.
10.38** Ground Lease, dated as of October 13, 1998, by and between Imperial Magma and Salton
Sea Power L.L.C.
10.39 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of March 14, 1988, by and between Magma Power Company and Del Ranch,
Ltd. (incorporated by reference to Exhibit 10.58 to Magma Power Company's Form 10-K
for the fiscal year ended December 31, 1987)
10.40 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of August 15, 1988, by and between Magma Power Company and Leathers, L.P.
(incorporated by reference to Magma Power Company's Form 10-K for the fiscal year
ended December 31, 1988)
10.41 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of March 14, 1988, by and between Magma Power Company and Elmore, Ltd.
(incorporated by reference to Exhibit 10.59 to Magma Power Company's Form 10-K for
the fiscal year ended December 31, 1988)
10.42** Lease Agreement, dated as of November 21, 1986, between Fina Oil and Chemical
Company and Power Resources, Inc., and First Amendment to Lease Agreement, dated
as of December 29, 1986, between Fina Oil and Chemical Company and Power
Resources, Inc.
10.43** Salton Sea Unit 5 Engineering, Procurement, and Construction Contract, dated
September 2, 1998, between Salton Sea Power L.L.C. and Stone & Webster Engineering
Corporation
10.44** Administrative Services Agreement, dated as of March 3, 1999, by and between
CalEnergy Company, Inc. and CE Generation, LLC
10.45** Fuel Management Services Agreement between El Paso Energy Marketing Company and
CE Generation, LLC
10.46** Power Marketing Services Agreement between El Paso Power Services Company and CE
Generation, LLC
10.47** Equity Purchase Agreement, dated as of February 21, 1999, by and between CalEnergy
Company, Inc. and El Paso Power Holding Company
</TABLE>
II-6
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- --------------- ---------------------------------------------------------------------------------------
<S> <C>
10.48** Equity Commitment Agreement, dated as of March 3, 1999, among CalEnergy Company,
Inc. and El Paso Power Holding Company
10.49*** Development Agreement, dated as of March 3, 1999, between CalEnergy Company, Inc.,
El Paso Power Holding Company and CE Generation, LLC
12.1* Computation of Ratio of Earnings to Fixed Charges
23.1 Consent of Latham & Watkins (included in their opinion filed as Exhibit 5.1)
23.2 Consent of Deloitte & Touche LLP
23.3*** Consent of Fluor Daniel, Inc.
23.4* Consent of R.W. Beck, Inc.
23.5* Consent of Henwood Energy Services, Inc.
23.6* Consent of GeothermEx, Inc.
23.7** Consent of C.C. Pace Consulting L.L.C.
25.1* Statement of Eligibility and Qualification (Form T-1) under the Trust Indenture Act of
1939 of Chase Manhattan Bank and Trust Company, National Association
27.1* Financial Data Schedule
99.1* Form of Letter of Transmittal to tender unregistered 7.416% Senior Secured Bonds Due
December 15, 2018 of CE Generation, LLC
99.2* Form of Letter to Registered Holders and DTC Participants from CE Generation, LLC
regarding the exchange offer
99.3* Form of Instruction to Registered Holder or DTC Participant from Beneficial Owner of
7.416% Senior Secured Bonds Due December 15, 2018 of CE Generation, LLC
99.4* Form of Letter to Clients from Registered Holder or DTC Participant regarding the
exchange offer
99.5* Form of Notice of Guaranteed Delivery
</TABLE>
- ----------
* Filed as an exhibit to CE Generation, LLC's Registration Statement filed
with the Securities and Exchange Commission on October 22, 1999.
** Filed as an exhibit to Amendment No. 1 to CE Generation, LLC's
Registration Statement filed with the Securities and Exchange Commission
on November 29, 1999.
*** Filed as an exhibit to Amendment No. 2 to CE Generation, LLC's
Registration Statement filed with the Securities and Exchange Commission
on December 20, 1999.
(b) Financial Statement Schedules
Financial statement schedules are not included because the required
information is inapplicable or is presented in the financial statements or the
notes to the financial statements.
ITEM 22. UNDERTAKINGS
The undersigned registrant hereby undertakes 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.
The undersigned registrant hereby undertakes as follows: prior to any
public reoffering of the securities registered hereunder through use of a
prospectus which is a part of this registration
II-7
<PAGE>
statement, by any person or party who is deemed to be an underwriter within the
meaning of Rule 145(c), such reoffering prospectus will contain the information
called for by the applicable registration form with respect to reofferings by
persons who may be deemed underwriters, in addition to the information called
for by the other Items of the application form.
The undersigned registrant hereby undertakes that every prospectus (i)
that is filed pursuant to the immediately preceding paragraph or (ii) that
purports to meet the requirements of Section l0(a)(3) of the Securities Act of
1933 and is used in connection with an offering of securities subject to Rule
415, will be filed as a part of an amendment to the registration statement and
will not be used until such amendment is effective, and that, for purposes of
determining any liability under the Securities Act of 1933, each such
post-effective amendment will be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time will be deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities
Act 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
or paid by 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 the issue.
The undersigned registrant hereby undertakes to file an application of the
purpose of determining the eligibility of the trustee to act under subsection
(a) of section 310 of the Trust Indenture Act in accordance with the rules and
regulations prescribed by the Securities and Exchange Commission under
section305(b)(2) of the Trust Indenture Act.
II-8
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended,
the Registrant has duly caused this Amendment No. 3 to be signed on its behalf
by the undersigned, thereunto duly authorized, in the City of Omaha, State of
Nebraska, on January 12, 2000.
CE GENERATION, LLC
By: /s/ Douglas L. Anderson
--------------------------------
Name: Douglas L. Anderson
Title: Vice President and General
Counsel
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 3 has been signed by the following persons in the capacities, as of the
dates and in the cities and states indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE CITY AND STATE
--------- ----- ---- --------------
<S> <C> <C> <C>
* President and Chief January 12, 2000 Omaha,
- ------------------------ Operating Officer; Nebraska
Robert S. Silberman Director
* Vice President and January 12, 2000 Omaha,
- ------------------------ Treasurer Nebraska
Brian K. Hankel
/s/ Douglas L. Anderson Vice President and January 12, 2000 Omaha,
- ------------------------ General Counsel; Nebraska
Douglas L. Anderson Director
* Vice President and January 12, 2000 Omaha,
- ---------------------- Commercial Officer Nebraska
Richard P. Johnston
* Director January 12, 2000 Omaha,
- ----------------------- Nebraska
Patrick J. Goodman
* Director January 12, 2000 Omaha,
- ----------------------- Nebraska
Larry Kellerman
* Director January 12, 2000 Omaha,
- ----------------------- Nebraska
John L. Harrison
* Director January 12, 2000 Omaha,
- ----------------------- Nebraska
Steven M. Pike
</TABLE>
* By /s/ Douglas L. Anderson
----------------------
Attorney-In-Fact
II-9
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- --------------------------------------------------------------------------------------
<S> <C>
3.1* Certificate of Formation of CE Generation, LLC
3.2* Limited Liability Company Operating Agreement of CE Generation, LLC
4.1* Indenture, dated as of March 2, 1999, by and between CE Generation, LLC and Chase
Manhattan Bank and Trust Company, National Association
4.2* Form of First Supplemental Indenture to be entered into by and between CE Generation,
LLC and Chase Manhattan Bank and Trust Company, National Association, Trustee
4.3* Purchase Agreement, dated February 24, 1999, by and among CE Generation, LLC,
Credit Suisse First Boston Corporation and Lehman Brothers, Inc.
4.4* Exchange and Registration Rights Agreement, dated as of March 2, 1999, by and among
CE Generation, LLC, Credit Suisse First Boston Corporation and Lehman Brothers, Inc.
4.5* Debt Service Reserve Letter of Credit and Reimbursement Agreement, dated as of
March 2, 1999, by and among CE Generation, LLC, the banks named therein and Credit
Suisse First Boston, as Agent
4.6* Deposit and Disbursement Agreement, dated as of March 2, 1999, by and among CE
Generation, LLC, Magma Power Company, Salton Sea Power Company, Falcon Seaboard
Resources, Inc., Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company,
California Energy Development Corporation, CE Texas Energy LLC and Chase
Manhattan Bank and Trust Company, National Association, as Collateral Agent and
Depositary Bank
4.7* Intercreditor Agreement, dated as of March 2, 1999, by and among CE Generation, LLC,
Magma Power Company, Salton Sea Power Company, Falcon Seaboard Resources, Inc.,
Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company, California Energy
Development Corporation, CE Texas Energy LLC, Credit Suisse First Boston and Chase
Manhattan Bank and Trust Company, National Association, as Trustee, Collateral Agent
and Depositary Bank
4.8* Assignment and Security Agreement, dated as of March 2, 1999, by and among Magma
Power Company, Salton Sea Power Company, Falcon Seaboard Resources, Inc., Falcon
Seaboard Power Corporation, Falcon Seaboard Oil Company, California Energy
Development Corporation, CE Texas Energy LLC, Credit Suisse First Boston and Chase
Manhattan Bank and Trust Company, National Association, as Collateral Agent
4.9* Assignment and Security Agreement, dated as of March 2, 1999, by and between CE
Generation, LLC and Chase Manhattan Bank and Trust Company, National Association,
as Collateral Agent
4.10* Pledge Agreement (SSPC Stock), dated as of March 2, 1999, by Magma Power Company
in favor of Chase Manhattan Bank and Trust Company, National Association, as
Collateral Agent
4.11* Pledge Agreement (FSRI Stock and CEDC Stock), dated as of March 2, 1999, by CE
Generation, LLC in favor of Chase Manhattan Bank and Trust Company, National
Association, as Collateral Agent
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ----------------------------------------------------------------------------------------
<S> <C>
4.12* Securities Account Control Agreement, dated as of March 2, 1999, by and among CE
Generation, LLC, Magma Power Company, Salton Sea Power Company, Falcon Seaboard
Resources, Inc., Falcon Seaboard Power Corporation, Falcon Seaboard Oil Company,
California Energy Development Corporation, CE Texas Energy LLC, Credit Suisse First
Boston and Chase Manhattan Bank and Trust Company, National Association, as
Collateral Agent and Depositary Bank
5.1 Opinion of Latham & Watkins regarding the validity of the new securities
10.1 Trust Indenture, dated as of July 21, 1995, between Chemical Trust Company of
California and Salton Sea Funding Corporation (incorporated by reference to Exhibit
4.1(a) to Salton Sea Funding Corporation's Registration Statement on Form S-4 dated
August 9, 1995, 33-95538)
10.2 First Supplemental Indenture, dated as of October 18, 1995, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(b) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated August 9, 1995, 33-95538)
10.3 Second Supplemental Indenture, dated as of July 20, 1996, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(c) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated July 2, 1996, 333-07527)
10.4 Third Supplemental Indenture, dated as of July 29, 1996, between Chemical Trust
Company of California and Salton Sea Funding Corporation (incorporated by reference to
Exhibit 4.1(d) to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated July 2, 1996, 333-07527)
10.5 Fourth Supplemental Indenture, dated as of October 13, 1998, between Chase Manhattan
Bank and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(e) to Salton Sea Funding Corporation's Form
10-K/A dated March 27, 1999)
10.6 Fifth Supplemental Indenture, dated as of February 16, 1999, between Chase Manhattan
Bank and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(f) to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
10.7 Sixth Supplemental Indenture, dated as of June 29, 1999, between Chase Manhattan Bank
and Trust Company, National Association, and Salton Sea Funding Corporation
(incorporated by reference to Exhibit 4.1(g) to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
10.8 Amended and Restated Salton Sea Guarantors Credit Agreement, dated as of
October 13, 1998, by and among Salton Sea Power Generation L.P., Salton Sea Brine
Processing L.P., Salton Sea Power, L.L.C. and Fish Lake Power Company (incorporated
by reference to Exhibit 4.12 to Salton Sea Funding Corporation's Registration Statement
on Form S-4 dated June 29, 1999, 333-79581)
10.9 Second Amended and Restated Partnership Guarantors Credit Agreement, dated as of
October 13, 1998, by and among CalEnergy Operating Corporation, Vulcan Power
Company, Conejo Energy Company, Niguel Energy Company, San Felipe Energy
Company, BN Geothermal Inc., Del Ranch, L.P., Elmore, L.P., Leathers, L.P., Vulcan/BN
Geothermal Power Company, CalEnergy Minerals LLC, CE Turbo LLC and Salton Sea
Funding Corporation (incorporated by reference to Exhibit 4.19 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated June 29, 1999, 333-79581)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ----------------------------------------------------------------------------------------------
<S> <C>
10.10 Amended and Restated Deposit and Disbursement Agreement, dated as of October 13,
1998, by and among Salton Sea Funding Corporation, Salton Sea Power Generation L.P.,
Salton Sea Brine Processing L.P., Salton Sea Power, L.L.C., Fish Lake Power Company,
CalEnergy Operating Corporation, Vulcan Power Company, Conejo Energy Company,
Niguel Energy Company, San Felipe Energy Company, BN Geothermal Inc., Del Ranch,
L.P., Elmore, L.P., Leathers, L.P., Vulcan/BN Geothermal Power Company, CalEnergy
Minerals LLC, CE Turbo LLC, and Chase Manhattan Bank and Trust Company, National
Association, as Collateral Agent and Depositary Agent (incorporated by reference to
Exhibit 4.14 to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated June 29, 1999, 333-79581)
10.11** Amendment and Restatement, dated as of September 30, 1994, of the Loan Agreement,
dated as of December 29, 1992, by and among Saranac Power Partners, L.P., County of
Clinton Industrial Development Agency, North Country Gas Pipeline Corporation, the
financial institutions party thereto, Credit Suisse First Boston and General Electric Capital
Corporation
10.12** Amended and Restated Security Deposit Agreement, dated as of October 7, 1994, among
Saranac Power Partners, L.P., Credit Suisse, General Electric Capital Corporation, TPC
Saranac Partner One, Inc., TPC Saranac Partner Two, Inc., and The Fuji Bank and Trust
Company
10.13** Installment Sale Agreement, dated as of December 29, 1992, by and between County of
Clinton Industrial Development Agency and Saranac Power Partners, L.P.
10.14 Second Amended and Restated Agreement of Limited Partnership of Saranac Power
Partners, L.P., dated as of May 13, 1994, by and among Saranac Energy Company, Inc.,
TPC Saranac Partner One, Inc. and TPC Saranac Partner Two, Inc., as amended by the
First Amendment to Second Amended and Restated Agreement of Limited Partnership
of Saranac Power Partners, L.P., by and among Saranac Energy Company, Inc., TPC
Partner One, Inc., TPC Saranac Partner Two, Inc. and General Electric Capital
Corporation (incorporated by reference to Exhibit 10.2 to CalEnergy Company, Inc.'s
Form 10-Q for the quarterly period ended September 30, 1996)
10.15** Amended and Restated Term Loan Agreement, dated as of December 30, 1988, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 1 to
Amended and Restated Term Loan Agreement, dated as of March 1, 1989, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 2 to
Amended and Restated Term Loan Agreement, dated as of April 28, 1989, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 3 to
Amended and Restated Term Loan Agreement, dated as of June 1, 1990, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., Amendment No. 4 to
Amended and Restated Term Loan Agreement, dated as of April 15, 1991, among
Kansallis-Osake-Pankki, Credit Suisse and Power Resources, Inc., and Amendment No. 5
to Amended and Restated Term Loan Agreement, dated as of June 29, 1995, among
Kansallis-Osake-Pankki, Credit Suisse, the other lenders named therein and Power
Resources, Inc.
10.16 Contract for the Purchase and Sale of Electric Power from the Salton Sea Geothermal
Facility, dated May 9, 1987, between Southern California Edison Company and Earth
Energy, Inc. (incorporated by reference to Exhibit 10.4 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- ------------------------------------------------------------------------------------------
<S> <C>
10.17 Amendment No. 1 to Contract for the Purchase and Sale of Electric Power from the
Salton Sea Geothermal Facility, dated March 30, 1993, between Southern California
Edison Company and Earth Energy, Inc. (incorporated by reference to Exhibit 10.5 to
Salton Sea Funding Corporation's Registration Statement on Form S-4 dated August 9,
1995, 33-95538)
10.18 Amendment No. 2 to Contract for the Purchase and Sale of Electric Power from the
Salton Sea Geothermal Facility, dated November 29, 1994, between Southern California
Edison Company and Salton Sea Power Generation L.P. (incorporated by reference to
Exhibit 10.6 to Salton Sea Funding Corporation's Registration Statement on Form S-4
dated August 9, 1995, 33-95538)
10.19 Contract for the Purchase and Sale of Electric Power, dated April 16, 1985, between
Southern California Edison Company and Westmoreland Geothermal Associates
(incorporated by reference to Exhibit 10.7 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.20 Amendment No. 1 to Contract for the Purchase and Sale of Electric Power, dated
December 18, 1987, between Southern California Edison Company and Earth Energy, Inc.
(incorporated by reference to Exhibit 10.8 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.21 Power Purchase Contract, dated April 16, 1985, between Southern California Edison
Company and Union Oil Company of California (incorporated by reference to Exhibit
10.9 to Salton Sea Funding Corporation's Registration Statement on Form S-4 dated
August 9, 1995, 33-95538)
10.22 Power Purchase Contract, dated November 19, 1994, between Southern California Edison
Company, Salton Sea Power Generation L.P. and Fish Lake Power Company
(incorporated by reference to Exhibit 10.10 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated August 9, 1995, 33-95538)
10.23 Long Term Power Purchase Contract, dated March 1, 1984, as amended, between
Southern California Edison Company and Vulcan/BN Geothermal Power Company, as
successor to Magma Electric Company (incorporated by reference to Exhibit 10.26 to
Salton Sea Funding Corporation's Registration Statement on Form S-4 dated July 2, 1996,
333-07527)
10.24 Long Term Power Purchase Contract, dated June 15, 1984, as amended, between Southern
California Edison Company and Elmore, L.P., as successor to Magma Electric Company
(incorporated by reference to Exhibit 10.31 to Salton Sea Funding Corporation's
Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.25 Long Term Power Purchase Contract, dated August 16, 1985, as amended, between
Southern California Edison Company and Leathers, L.P., as successor to Imperial Energy
Corporation (incorporated by reference to Exhibit 10.36 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.26 Long Term Power Purchase Contract, dated February 22, 1974, as amended, between
Southern California Edison Company and Del Ranch, L.P., as successor to Magma
Electric Company (incorporated by reference to Exhibit 10.41 to Salton Sea Funding
Corporation's Registration Statement on Form S-4 dated July 2, 1996, 333-07527)
10.27** Amended and Restated Power Sales Agreement, dated as of November 1, 1988, by and
between CalEnergy Minerals LLC and Salton Sea Power L.L.C.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- -------------------------------------------------------------------------------------------
<S> <C>
10.28 Agreement between New York State Electric & Gas Corporation and Saranac Energy
Company, Inc., dated as of April 27, 1987 and Amendment No. 1 to Power Purchase
Agreement between New York State Electric & Gas Corporation and Saranac Energy
Company, Inc. dated August 29, 1991 (incorporated by reference to Exhibit 10.1 to
CalEnergy Company, Inc.'s Form 10-Q for the quarterly period ended September 30,
1996)
10.29** Amendment No. 2 to Power Purchase Agreement between New York State Electric &
Gas Corporation and Saranac Energy Company, Inc. dated February 24, 1994
10.30** (Power Purchase) Agreement, dated July 30, 1986, between Falcon Seaboard Oil
Company and Texas Utilities Electric Company, First Amendment to (Power Purchase)
Agreement, dated December 23, 1986, between Falcon Seaboard Oil Company and Texas
Utilities Electric Company, and Second Amendment to (Power Purchase) Agreement,
dated May 27, 1988, between Falcon Seaboard Oil Company and Texas Utilities Electric
Company
10.31 Standard Offer Number 2 for Power Purchase with a Firm Capacity Qualifying Facility
effective June 13, 1990 between San Diego Gas & Electric Company and Bonneville
Pacific Corporation (incorporated by reference to Exhibit 10.42 to CalEnergy Company,
Inc.'s Form 10-K for the fiscal year ended December 31, 1993)
10.32 Amendment No. 1 to Standard Offer Number 2 for Power Purchase with a Firm Capacity
Qualifying Facility dated September 25, 1990 between San Diego Gas & Electric
Company and Bonneville Pacific Corporation (incorporated by reference to Exhibit 10.43
to CalEnergy Company, Inc.'s Form 10-K for the fiscal year ended December 31, 1993)
10.33** Ground Lease, dated as of November 24, 1993, by and between Imperial Irrigation
District, Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P., and First
Amendment to Ground Lease, dated as of December 15, 1993, by and between Imperial
Irrigation District, Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P.
10.34** Ground Lease, dated as of March 31, 1993, by and between Magma Land Company I,
Salton Sea Power Generation L.P. and Salton Sea Brine Processing L.P.
10.35** Ground Lease, dated as of October 26, 1988, by and between Magma Power Company
and Leathers, L.P., and Clarification and Amendment, dated as of June 17, 1996, between
Magma Power Company and Leathers, L.P.
10.36** Ground Lease, dated as of March 14, 1988, by and between Magma Power Company and
Del Ranch, Ltd., and Clarification and Amendment, dated as of June 17, 1996, between
Magma Power Company and Del Ranch L.P.
10.37** Ground Lease, dated as of March 14, 1988, by and between Magma Power Company and
Elmore, Ltd., and Clarification and Amendment, dated as of June 17, 1996, by and
between Magma Power Company and Elmore, L.P.
10.38** Ground Lease, dated as of October 13, 1998, by and between Imperial Magma and Salton
Sea Power L.L.C.
10.39 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of March 14, 1988, by and between Magma Power Company and Del Ranch,
Ltd. (incorporated by reference to Exhibit 10.58 to Magma Power Company's Form 10-K
for the fiscal year ended December 31, 1987)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- --------------- ---------------------------------------------------------------------------------------
<S> <C>
10.40 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of August 15, 1988, by and between Magma Power Company and Leathers, L.P.
(incorporated by reference to Magma Power Company's Form 10-K for the fiscal year
ended December 31, 1988)
10.41 Easement Grant Deed and Agreement Regarding Rights for Geothermal Development,
dated as of March 14, 1988, by and between Magma Power Company and Elmore, Ltd.
(incorporated by reference to Exhibit 10.59 to Magma Power Company's Form 10-K for
the fiscal year ended December 31, 1988)
10.42** Lease Agreement, dated as of November 21, 1986, between Fina Oil and Chemical
Company and Power Resources, Inc., and First Amendment to Lease Agreement, dated
as of December 29, 1986, between Fina Oil and Chemical Company and Power
Resources, Inc.
10.43** Salton Sea Unit 5 Engineering, Procurement, and Construction Contract, dated
September 2, 1998, between Salton Sea Power L.L.C. and Stone & Webster Engineering
Corporation
10.44** Administrative Services Agreement, dated as of March 3, 1999, by and between
CalEnergy Company, Inc. and CE Generation, LLC
10.45** Fuel Management Services Agreement between El Paso Energy Marketing Company and
CE Generation, LLC
10.46** Power Marketing Services Agreement between El Paso Power Services Company and CE
Generation, LLC
10.47** Equity Purchase Agreement, dated as of February 21, 1999, by and between CalEnergy
Company, Inc. and El Paso Power Holding Company
10.48** Equity Commitment Agreement, dated as of March 3, 1999, among CalEnergy Company,
Inc. and El Paso Power Holding Company
10.49*** Development Agreement, dated as of March 3, 1999, between CalEnergy Company, Inc.,
El Paso Power Holding Company and CE Generation, LLC
12.1* Computation of Ratio of Earnings to Fixed Charges
23.1 Consent of Latham & Watkins (included in their opinion filed as Exhibit 5.1)
23.2 Consent of Deloitte & Touche LLP
23.3*** Consent of Fluor Daniel, Inc.
23.4* Consent of R.W. Beck, Inc.
23.5* Consent of Henwood Energy Services, Inc.
23.6* Consent of GeothermEx, Inc.
23.7** Consent of C.C. Pace Consulting L.L.C.
25.1* Statement of Eligibility and Qualification (Form T-1) under the Trust Indenture Act of
1939 of Chase Manhattan Bank and Trust Company, National Association
27.1* Financial Data Schedule
99.1* Form of Letter of Transmittal to tender unregistered 7.416% Senior Secured Bonds Due
December 15, 2018 of CE Generation, LLC
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION OF EXHIBIT
- ------------- -------------------------------------------------------------------------------------
<S> <C>
99.2* Form of Letter to Registered Holders and DTC Participants from CE Generation, LLC
regarding the exchange offer
99.3* Form of Instruction to Registered Holder or DTC Participant from Beneficial Owner of
7.416% Senior Secured Bonds Due December 15, 2018 of CE Generation, LLC
99.4* Form of Letter to Clients from Registered Holder or DTC Participant regarding the
exchange offer
99.5* Form of Notice of Guaranteed Delivery
</TABLE>
- ----------
* Filed as an exhibit to CE Generation, LLC's Registration Statement filed
with the Securities and Exchange Commission on October 22, 1999.
** Filed as an exhibit to Amendment No. 1 to CE Generation, LLC's
Registration Statement filed with the Securities and Exchange Commission
on November 29, 1999.
*** Filed as an exhibit to Amendment No. 2 to CE Generation, LLC's
Registration Statement filed with the Securities and Exchange Commission
of December 20, 1999.
<PAGE>
[Latham & Watkins Letterhead]
---------
January 12, 2000
EXHIBIT 5.1
CE Generation, LLC
302 South 36th Street, Suite 400
Omaha, Nebraska 68131
Re: Registration Statement on Form S-4;
$400,000,000 Aggregate Principal
Amount of Senior Secured Bonds
------------------------------
Ladies and Gentlemen:
In connection with the registration of $400,000,000 7.416% Senior
Secured Bonds Due December 15, 2018 (the "Securities") by CE Generation, a
Delaware limited liability company (the "Registrant"), under the Securities Act
of 1933, as amended (the "Act"), on Form S-4 filed with the Securities and
Exchange Commission (the "Commission") on October 22, 1999, as amended by
Amendment No. 1 thereto filed with the Commission on November 29, 1999,
Amendment No. 2 thereto filed with the Commission on December 20, 1999 and
Amendment No. 3 thereto filed with the Commission on January 12, 2000 (the
"Registration Statement"), you have requested our opinion with respect to the
matters set forth below.
In our capacity as your special counsel in connection with such
registration, we are familiar with the proceedings taken by the Registrant in
connection with the authorization and issuance of the Securities. In addition,
we have made such legal and factual examinations and inquiries, including an
examination of originals or copies certified or otherwise identified to our
satisfaction of such documents, corporate records and instruments, as we have
deemed necessary or appropriate for purposes of this opinion.
In our examination, we have assumed the genuineness of all signatures,
the authenticity of all documents submitted to us as originals, and the
conformity to authentic original documents of all documents submitted to us as
copies.
<PAGE>
CE Generation, LLC
Page 2
We are opining herein as to the effect on the subject transaction only
of the internal laws of the State of New York and the Limited Liability Company
Act of the State of Delaware, including statutory and reported decisional law
thereunder, and we express no opinion with respect to the applicability thereto,
or the effect thereon, of the laws of any other jurisdiction or, in the case of
Delaware, any other laws, or as to any matters of municipal law or the laws of
any local agencies within any state.
Capitalized terms used herein without definition have the meanings
ascribed to them in the Registration Statement.
Subject to the foregoing and the other matters set forth herein, it is
our opinion that as of the date hereof:
The Securities have been duly authorized by all necessary limited
liability company action of the Registrant, and when executed, authenticated and
delivered by or on behalf of the Registrant will constitute legally valid and
binding obligations of the Registrant, enforceable against the Registrant in
accordance with their terms.
The opinions rendered in the preceding paragraph are subject to the
following exceptions, limitations and qualifications: (i) the effect of
bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or
other similar laws now or hereafter in effect relating to or affecting the
rights and remedies of creditors; and (ii) the effect of general principles of
equity, whether enforcement is considered in a proceeding in equity or law, and
the discretion of the court before which any proceeding therefor may be brought.
To the extent that the obligations of the Registrant under the
Indenture may be dependent upon such matters, we assume for purposes of this
opinion that the Trustee is duly organized, validly existing and in good
standing under the laws of its jurisdiction of organization; that the Trustee is
duly qualified to engage in the activities contemplated by the Indenture; that
the Indenture has been duly authorized, executed and delivered by the Trustee
and constitutes the legally valid, binding and enforceable obligation of the
Trustee enforceable against the Trustee in accordance with its terms; that the
Trustee is in compliance, generally and with respect to acting as a trustee
under the Indenture, with all applicable laws and regulations; and that the
Trustee has the requisite organizational and legal power and authority to
perform its obligations under the Indenture.
<PAGE>
CE Generation, LLC
Page 3
We consent to your filing this opinion as an exhibit to the
Registration Statement and to the reference to our firm contained under the
heading "Legal Matters" in the Prospectus.
Very truly yours,
/s/ Latham & Watkins
<PAGE>
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
We consent to the use in this Amendment No. 3 to Registration Statement No.
333-89521 of CE Generation, LLC of (i) our report dated January 28, 1999
(February 22, 1999 as to the first paragraph in Note 1 and March 3, 1999 as to
Note 15) relating to the financial statements of CE Generation, LLC, (ii) our
report dated January 28, 1999 (March 3, 1999 as to Note 11) relating to the
financial statements of Magma Power Company and (iii) our report dated January
28, 1999 (March 3, 1999 as to Note 9) relating to the financial statements of
Falcon Seaboard Resources, Inc., all appearing in the Prospectus, which is part
of this Registration Statement and to the reference to us under the heading
"Experts" in such Prospectus.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
January 12, 2000
