SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K *
Annual Report Pursuant to Section 13 or 15 (d) of
the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1999
Commission File No. 333-89521
CE Generation, LLC.
(Exact name of registrant as specified in its charter)
Delaware 47-0818523
(State or other jurisdiction of (I.R.S. Employer
Incorporation or organization) Identification No.)
302 South 36th Street, Suite 400 Omaha, NE 68131
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (402) 341-4500
Securities registered pursuant to Section 12(b) of the Act: N/A
Securities registered pursuant to Section 12(g) of the Act: N/A
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days:
Yes X No _____
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ]
The members equity accounts are held 50% by MidAmerican Energy Holdings
Company and 50% by El Paso CE Generation Holding Company as of March 30, 2000.
* This Annual Report on Form 10-K is being filed pursuant to Rule 15d-2
under the Securities Exchange Act of 1934 and contains certified financial
statements as required by Rule 15d-2.
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TABLE OF CONTENTS
Part I.........................................................................1
Item 1. Business...........................................................1
General.....................................................................1
The Projects...................................................................2
Geothermal Facilities..........................................................2
Gas Facilities.................................................................4
Projects in Construction.......................................................5
Description of the Securities...............................................6
General.....................................................................6
Collateral for the Securities...............................................6
Payment of Interest and Principal...........................................6
Interest....................................................................6
Principal...................................................................7
Priority of Payments........................................................8
Debt Service Reserve Account................................................8
Optional Redemption.........................................................9
Mandatory Redemption--At Par................................................9
Mandatory Redemption--With Yield Maintenance Premium........................9
Distributions...............................................................9
Nature of Recourse on the Securities........................................9
Covenants...................................................................9
Employees..................................................................10
Item 2. Properties............................................................10
Item 3. Legal Proceedings.....................................................10
Item 4. Submission of Matters to a Vote of Security Holders...................10
Part II.......................................................................11
Item 5. Market for Registrant's Common Equity and Related Stockholder's
Matters....................................................................11
Item 6. Selected Financial Data...............................................12
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations .....................................................13
Item 7A. Qualitative and Quantitative Disclosures About Market Risk...........20
Item 8. Financial Statements and Supplementary Data...........................21
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.......................................................85
Part III......................................................................86
Item 10. Directors and Executive Officers....................................86
Item 11. Executive Compensation..............................................88
Item 12. Security Ownership of Certain Beneficial Owners and Management ......88
Item 13. Certain Relationships and Related Transactions......................88
Part IV.......................................................................89
Item 14. Exhibits, Financial Statements Schedule and Reports on Form 8-K.....89
SIGNATURES....................................................................90
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PART I
Item 1. Business
General
CE Generation, LLC ("CE Generation" or the "Company"), is a special
purpose Delaware limited liability company created by MidAmerican Energy
Holdings Company ("MEHC" or "MidAmerican") on February 8, 1999, for the sole
purpose of issuing securities and holding the equity investments in certain
subsidiaries. On March 3, 1999, MEHC sold 50% of its ownership interests in CE
Generation to El Paso CE Generation Holding Company ("El Paso Power"), a
subsidiary of El Paso Energy Corporation ("El Paso" or "El Paso Energy"). The
principal executive office of CE Generation is located at 302 South 36th Street,
Omaha, Nebraska 68131 and its telephone number is (402) 341-4500.
Due to the then pending merger of MEHC with an electric utility, MEHC
was required to divest a portion of its ownership interests in the Company's
power projects in order to permit those projects to maintain their status as
qualifying facilities (QFs) under the Public Utilities Regulatory Policies Act
of 1978. This law requires that a non-electric utility own at least 50% of a QF.
The sale to El Paso Power, which does not own an electric utility, was intended
to permit the Company's power projects to satisfy this ownership requirement. By
maintaining QF status, the Company's 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 QFs during the term
of those agreements.
The Company's 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 made by the Company.
CE Generation owns all of the common stock interests in Magma Power
Company ("Magma"), Falcon Seaboard Resources, Inc. ("FSRI") and California
Energy Development Corporation ("CEDC") and their subsidiaries. Through its
subsidiaries, CE Generation is primarily engaged in the development, ownership
and operation of environmentally responsible independent power production
facilities in the United States utilizing geothermal and natural gas resources.
CE Generation has an aggregate net ownership interest of 756 MW of electrical
generating capacity in power plants in operation or under construction in the
United States, which have an aggregate net capacity of 816 MW.
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The Projects
The following table sets out information concerning CE Generation
projects:
PROJECT FUEL COMMERCIAL CAPACITY LOCATION
OPERATION
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
CE Turbo Geothermal 2000 10 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
Power Resources Gas 1988 200 MW Texas
Yuma Gas 1994 50 MW Arizona
Saranac Gas 1994 240 MW New York
On December 2, 1999, the NorCon project was transferred to General
Electric Capital Corporation and, therefore, CE Generation no longer has any
interest in the NorCon project.
Geothermal Facilities
CE Generation affiliates currently operate eight geothermal plants in
the Imperial Valley in California (the "Imperial Valley Project"). Four of these
Imperial Valley Project plants (the "Partnership Projects") were developed by
Magma which originally owned a 50% interest. On April 17, 1996, the Company
completed the Partnership Interest Acquisition pursuant to which the Company
acquired the remaining 50% interests in each of the Partnership Projects for $70
million. The Partnership Projects consist of the Vulcan, Hoch (Del Ranch),
Elmore and Leathers projects (the "Vulcan Project," the "Hoch (Del Ranch)
Project," the "Elmore Project" and the "Leathers Project," respectively).
The remaining four operating Imperial Valley Project plants (the
"Salton Sea Projects") are wholly owned by subsidiaries of Magma. Three of these
plants were purchased by Magma on March 31, 1993 from Union Oil Company of
California. These geothermal power plants consist of the Salton Sea I project
(the "Salton Sea I Project"), the Salton Sea II project (the "Salton Sea II
Project") and the Salton Sea III project (the "Salton Sea III Project"). The
fourth plant, the Salton Sea IV project (the "Salton Sea IV Project"), commenced
commercial operations in 1996.
Vulcan. The Vulcan Project sells electricity to Southern California
Edison ("Edison") under a 30-year Standard Offer No. 4 Agreement ("SO4
Agreement") that commenced on February 10, 1986. The Vulcan Project has a
contract capacity and contract nameplate of 29.5 MW and 34 MW, respectively.
Under the SO4 Agreement, Edison is obligated to pay the Vulcan Project a
capacity payment, a capacity bonus payment and an energy payment. The price for
contract capacity payments is fixed for the life of such SO4 Agreement. The
as-available capacity price is based on a payment schedule as approved by the
CPUC from time to time. The contract energy payment increased each year for the
first ten years, which period expired on February 9, 1996. Thereafter, the
energy payments are based on Edison's Avoided Cost of Energy.
Hoch (Del Ranch). The Hoch (Del Ranch) Project sells electricity to
Edison under a 30-year SO4 Agreement that commenced on January 2, 1989. The
contract capacity and contract nameplate are 34 MW and 38 MW, respectively. The
provisions of such SO4 Agreement are substantially the same as the SO4 Agreement
with respect to the Vulcan Project. The price for contract capacity payments is
fixed for the life of the SO4 Agreement. The fixed price period for energy
payments per kWh expired on January 1, 1999. Thereafter, the energy payments are
based on Edison's Avoided Cost of Energy.
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Elmore. The Elmore Project sells electricity to Edison under a 30-year
SO4 Agreement that commenced on January 1, 1989. The contract capacity and
contract nameplate are 34 MW and 38 MW, respectively. The provisions of such SO4
Agreement are substantially the same as the SO4 Agreement with respect to the
Vulcan Project. The price for contract capacity payments is fixed for the life
of SO4 Agreement. The fixed price period for energy payments per kWh expired on
December 31, 1998. Thereafter, the energy payments are based on Edison's Avoided
Cost of Energy.
Leathers. The Leathers Project sells electricity to Edison pursuant to
a 30-year SO4 Agreement that commenced on January 1, 1990. The contract capacity
and contract nameplate are 34 MW and 38 MW, respectively. The provisions of such
SO4 Agreement are substantially the same as the SO4 Agreement with respect to
the Vulcan Project. The price for contract capacity payments is fixed for the
life of the SO4 Agreement which expired on December 31, 1999. Thereafter, the
energy payments will be based on Edison's Avoided Cost of Energy.
Salton Sea I Project. The Salton Sea I Project sells electricity to
Edison pursuant to a 30-year negotiated power purchase agreement, as amended
(the "Salton Sea I PPA"), which provides capacity and energy payments. The
contract capacity and contract nameplate are each 10 MW. The capacity payment is
based on the firm capacity price which is currently $132.58 per kW-year. The
contract capacity payment adjusts quarterly based on a basket of energy indices
for the term of the Salton Sea I PPA. The energy payment is calculated using a
Base Price (defined as the initial value of the energy payment (4.701 cents per
kWh for the second quarter of 1992)), which is subject to quarterly adjustments
based on a basket of indices. The time period weighted average energy payment
for Salton Sea I was 5.3 cents per kWh during 1999. As the Salton Sea I PPA is
not an SO4 Agreement, the energy payments do not revert to Edison's Avoided Cost
of Energy.
Salton Sea II Project. The Salton Sea II Project sells electricity to
Edison pursuant to a 30-year modified SO4 Agreement that commenced on April 5,
1990. The contract capacity and contract nameplate are 15 MW (16.5 MW during
on-peak periods) and 20 MW, respectively. The contract requires Edison to make
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 Agreement. The energy payments for the first ten-year period,
which period expires on April 4, 2000, are levelized at a time period weighted
average of 10.6 cents per kWh. Thereafter, the monthly energy payments will be
based on Edison's Avoided Cost of Energy. Edison is entitled to receive, at no
cost, 5% of all energy delivered in excess of 80% of contract capacity through
September 30, 2004.
Salton Sea III Project. The Salton Sea III Project sells electricity
to Edison pursuant to a 30-year modified SO4 Agreement that commenced on
February 13, 1989. The contract capacity is 47.5 MW and the contract nameplate
is 49.8 MW. The SO4 Agreement requires Edison to make capacity payments,
capacity bonus payments and energy payments for the life of the SO4 Agreement.
The price for contract capacity payments and capacity bonus payments is fixed at
$175/kW per year. The energy payments for the first ten-year period, which
period expired on February 12, 1999, were levelized at a time period weighted
average of 9.8 cents per kWh. Thereafter, the monthly energy payments are based
on Edison's Avoided Cost of Energy.
Salton Sea IV Project. The Salton Sea IV Project 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 I PPA option
(20 MW) and to the original Salton Sea IV SO4 Agreement ("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.
<PAGE>
Gas Facilities
Yuma Project. The Yuma Project is a 50 net MW natural gas-fired
cogeneration project in Yuma, Arizona providing 50 MW of electricity to San
Diego Gas & Electric Company ("SDG&E") under an existing 30-year power purchase
contract ("Yuma PPA"). 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 Yuma PPA. The
power is wheeled to SDG&E over transmission lines constructed and owned by
Arizona Public Service Company ("APS"). The Yuma Project commenced commercial
operation in May 1994. The project entity, Yuma Cogeneration Associates ("YCA"),
has executed steam sales contracts with an adjacent industrial entity to act as
its thermal host. Since the industrial entity has the right under its agreement
to terminate the agreement upon one year's notice if a change in its technology
eliminates its need for steam, and in any case to terminate the agreement at any
time upon three years notice, there can be no assurance that the Yuma Project
will maintain its status as a QF. However, if the industrial entity terminates
the agreement, YCA anticipates that it will be able to locate an alternative
thermal host in order to maintain its status as a QF. A natural gas supply and
transportation agreement has been executed with Southwest Gas Corporation,
terminable under certain circumstances by YCA and Southwest Gas Corporation.
Saranac Project. The Saranac Project is a 240 net MW natural gas-fired
cogeneration facility located in Plattsburgh, New York, which began commercial
operation in June 1994. The Saranac Project has entered into a 15-year power
purchase agreement (the "Saranac PPA") with New York State Electric & Gas
("NYSEG"). The Saranac Project is a QF and has entered into 15-year steam
purchase agreements (the "Saranac Steam Purchase Agreements") with
Georgia-Pacific Corporation and Tenneco Packaging, Inc. The Saranac Project has
a 15-year natural gas supply contract (the "Saranac Gas Supply Agreement") with
Shell Canada Limited ("Shell Canada") to supply 100% of the Saranac Project's
fuel requirements. Shell Canada is responsible for production and delivery of
natural gas to the U.S.-Canadian border; the gas is then transported by the
North Country Gas Pipeline Corporation ("NCGP") the remaining 22 miles to the
plant. NCGP is a wholly-owned subsidiary of Saranac Power Partners, L.P. (the
"Saranac Partnership") and the Saranac Partnership also owns the Saranac
Project. NCGP also transports gas for NYSEG and Georgia-Pacific. Each of the
Saranac PPA, the Saranac Steam Purchase Agreements and the Saranac Gas Supply
Agreement contains rates that are fixed for the respective contract terms. The
1999 Saranac PPA rates escalate at a higher percentage than fuel rates. The
Saranac Partnership is indirectly owned by subsidiaries of CE Generation, Tomen
Corporation ("Tomen") and General Electric Capital Corporation ("GECC").
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, the
Saranac Partnership 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 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 required
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 on 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.
<PAGE>
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), the Saranac Partnership and Lockport Energy
Associates, L.P. ("Lockport") concerning the power purchase agreements that
NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that
the PSC and the FERC improperly implemented PURPA in authorizing the pricing
terms that NYSEG, the Saranac Partnership 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 the Saranac Partnership. The Saranac Partnership and
other parties have filed motions to dismiss and oral arguments on those motions
were heard on March 2, 1998 and again on March 3, 1999. The Saranac Partnership
believes that NYSEG's claims are without merit for the same reasons described in
the FERC's orders.
Power Resources Project. The Power Resources Project is a 200 net MW
natural gas-fired cogeneration project located near Big Spring, Texas, which has
a 15-year power purchase agreement (the "Power Resources PPA") with Texas
Utilities Electric Company. The Power Resources Project began commercial
operation in June 1988. The Power Resources Project is a QF and the project
entity, Power Resources Ltd. ("Power Resources"), has entered into a 15-year
steam purchase agreement (the "Power Resources Steam Purchase Agreement") with
Fina Oil and Chemical Company ("Fina"), a subsidiary of Petrofina S.A. of
Belgium. Power Resources has entered into an agreement (the "CE Texas Gas Supply
Agreement") with CE Texas Gas L.P. ("CE Texas Gas") for Power Resources' fuel
requirements through December 2003. In June 1995, CE Texas Gas and Louis Dreyfus
Natural Gas Corp. ("Dreyfus") executed an eight-year natural gas supply
agreement (the "CE Texas Gas-Dreyfus Gas Supply Agreement"), with which CE Texas
Gas will fulfill its supply commitment to the Power Resources Project from
October 1995 to the end of the term of the Power Resources PPA. Each of the
Power Resources PPA, the Power Resources Steam Purchase Agreement and the CE
Texas Gas Supply Agreement contains rates that are fixed for the respective
contract terms. Revenues escalate at a higher rate than fuel costs. The Power
Resources Project is wholly owned by subsidiaries of the Company.
NorCon Project. CE Generation formerly owned an indirect interest in
the NorCon Project, an 80 net MW natural gas-fired cogeneration facility located
in North East, Pennsylvania which began commercial operation in December 1992.
On December 2, 1999 the project entity, NorCon Power Partners, L.P. ("NorCon"),
reached agreement with Niagara Mohawk Power Corporation ("NIMO") to dismiss the
outstanding litigation between NorCon and Niagara. At the same time, NorCon
transferred the NorCon project to GECC 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 GECC. GECC 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.
Projects in Construction
Salton Sea V. Salton Sea Power LLC, an indirect wholly owned subsidiary
of CE Generation, is constructing the Salton Sea V Project. The Salton Sea V
Project is a 49 net MW geothermal power plant which will sell approximately
one-third of its net output to the Zinc Recovery Project. The Zinc Recovery
Project is a project under construction owned by CalEnergy Minerals, LLC
("Minerals LLC"), an indirect wholly-owned subsidiary of MidAmerican, for the
extraction of zinc from solution in the geothermal brine and fluids utilized by
CE Generation's Imperial Valley Projects (the "Zinc Recovery Project"). The
remainder of the Salton Sea V power will be sold through the California Power
Exchange ("PX") or other market transactions. The Salton Sea V Project is being
constructed pursuant to a date certain, fixed price, turnkey engineering,
procurement and construction contract (the "Salton Sea V EPC Contract") by Stone
& Webster Engineering Corporation ("SWEC"). The Salton Sea V Project is
scheduled to commence commercial operation in mid-2000.
<PAGE>
CE Turbo. CE Turbo LLC, an indirect wholly-owned subsidiary of CE
Generation, is constructing the CE Turbo Project. The CE Turbo Project will have
a capacity of 10 net MW. The net output of the CE Turbo Project will be sold to
the Zinc Recovery Project or sold through the PX or other market transactions.
In addition to the CE Turbo Project, the Partnership Projects are constructing
an upgrade to the geothermal brine processing facilities at the Vulcan and Del
Ranch Projects to incorporate the pH Modification Process, which has reduced
operating costs at the Imperial Valley Project. The CE Turbo Project and the
brine facilities construction are being constructed by SWEC pursuant to a date
certain, fixed price, turnkey engineering, procurement and construction contract
(the "Region 2 Upgrade EPC Contract"). The CE Turbo Project is scheduled to
commence initial operations in early to mid 2000 and the brine facilities
construction is scheduled to be completed in early 2000.
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 securities are direct senior obligations of CE Generation, 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.
On March 2, 1999, CE Generation issued securities 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. These
securities were issued in reliance on exemptions from the registration
requirements of the Securities Act. On March 6, 2000, CE Generation exchanged
$400,000,000 principal amount of these securities for $400,000,000 principal
amount of securities which have been registered under the Securities Act. The
form and terms of these new securities are identical in all material respects to
the securities for which they were exchanged except that transfer restrictions
and registration rights applicable to the old securities do not apply to the new
securities.
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.
Collateral for the Securities
The securities are secured by the following collateral: (a) all
available cash flow of the assigning subsidiaries deposited with the depository
bank; (b) 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; (c)
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; (d) a
pledge of all of the capital stock of SECI Holdings Inc.; (e) a grant of a lien
on and security interest in the depository accounts; and a grant of a lien on
and security interest in all of CE Generation's other tangible and intangible
property, to the extent it is possible to grant a lien on the property.
Payment of Interest and Principal
Interest
<PAGE>
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 is 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:
PAYMENT DATE PERCENTAGE OF
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%
<PAGE>
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%
Priority of Payments
All available cash flows received by CE Generation shall be paid into
the Revenue Account maintained by a Depository. Amounts paid into the Revenue
Account shall be distributed in the following order: (a) to pay operating and
administrative costs of CE Generation and it's subsidiaries, excluding those
costs payable to affiliated parties; (b) to pay certain administrative costs of
the agents for the secured parties under the Financing Documents; (c) to pay
principal of, premium (if any) and interest on the Securities and the Debt
Service Reserve Bonds, if any, and interest and certain fees payable to the Debt
Service Reserve LOC provider; (d) to pay principal of Debt Service Reserve LOC
Loans and certain related fees and charges; (e) to replenish any shortfall in
the Debt Payment Account; (f) to replenish any shortfall in the Debt Service
Reserve Account; (g) to pay any remaining amounts to the Distribution Suspense
Account.
Debt Service Reserve Account
A Debt Service Reserve Fund for the benefit of the Security Holders
issued by Credit Suisse First Boston and Lehman Commercial Paper Inc., which has
been funded by a Debt Service Reserve Letter of Credit Provider has been
established under the Depository Agreement. If the amounts available to be drawn
under the Debt Service Reserve Letter of Credit and all other amounts held in
the Debt Service Reserve Account from time to time do not equal the then current
debt service reserve required balance, the Debt Service Reserve Fund shall be
funded from the Revenue Account subject to the funding of requests described
above. 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. Any Debt Service Reserve Letter of Credit must be issued by a
financial institution rated at least "A" by S&P and "A2" by Moody's.
<PAGE>
Optional Redemption
The securities are subject to optional redemption, in whole or in part,
at any time on any business day, at a price equal to the redemption price plus a
premium calculated to "make whole" to comparable U.S. Treasury Securities plus
50 basis points.
Mandatory Redemption--At Par
The securities are subject to mandatory redemption, at par plus accrued
interest to the Redemption Date, (a) upon the occurrence of certain events of
loss, expropriation or title defects related to CE Generation or its
subsidiaries; or (b) if a permitted power contract buy-out occurs unless the
Rating Agencies confirm the then current rating of the securities.
Mandatory Redemption--With Yield Maintenance Premium
The securities are subject to mandatory redemption, at par plus accrued
interest and a yield maintenance premium to the Redemption Date upon certain
project refinancing or project debt refinancing or upon certain asset or equity
interests sales.
Distributions
Distributions may be made only from and to the extent of monies on
deposit in the Distribution Suspense Account, on any funding date on which the
following conditions are satisfied:
(a) the debt payment account and the debt service reserve account are
funded to the then current required levels and the payments described
in the first, second, sixth and seventh priorities of payments
described above are satisfied in full;
(b) no default or event of default under the indenture shall have occurred
and be continuing;
(c) 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 or equal to 1.5 to 1.0;
(d) 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
(e) no material default or 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 Imperial Valley
Projects.
Nature of Recourse on the Securities
The obligation to pay principal of, premium (if any) and interest on
the Securities are obligations solely of CE Generation, secured by the
collateral. Neither MidAmerican nor El Paso Energy, nor any affiliate,
shareholder, member, officer, director or employee of CE Generation 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 the
obligation to make payments on the securities).
Covenants
Principal covenants under the indenture require CE Generation, among other
things, (a) to maintain its existence, (b) comply with applicable laws and
governmental approach, (c) perform required obligations under the financing
documents, (d) maintain the liens on the collateral in favor of the collateral
agent, (f) not to incur any debt except permitted debt and lien upon any of its
properties except permitted liens, and (g) not form any subsidiaries, make
investments, loans or advances or acquisitions, in each case other than as
permitted under the indenture.
<PAGE>
Employees
Employees necessary for the operation of the CE Generation projects are
provided by CalEnergy Operating Corporation ("CEOC") and Falcon Power Operating
Company ("FPOC"), indirect subsidiaries of CE Generation, under operation and
maintenance agreements. As of December 31, 1999, CEOC and FPOC, employed 166 and
75 people full-time, respectively. MidAmerican employees provide administrative
services, including accounting, legal, personnel and cash management under an
administrative services agreement. El Paso employees are expected to provide
power marketing and fuel management services under agreements for power services
and fuel management.
MidAmerican agreed to provide administrative services, including
accounting, legal, human resources and cash management services, to the Company
under an administrative services agreement. MidAmerican is reimbursed for its
actual costs and expenses of providing the services. Other affiliates of El Paso
agreed to provide power marketing and fuel management services to the Company 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. The Company also
entered into an agreement with MidAmerican and El Paso Power to provide El Paso
Power with a right of first refusal for the Company 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 the Company elects 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 the Company's existing
projects.
Item 2. Properties
The Company's most significant physical properties, are its current
interest in operating power facilities, its plants under construction and
related real property interests. The Company also maintains an inventory of
approximately 75,000 acres of geothermal property leases. Certain of the
producing acreage owned by Magma is leased to Mammoth-Pacific as owner and
operator of the Mammoth Plants, and Magma, as lessor, receives royalties from
the revenues earned by such power plants. The Company, as lessee, pays certain
royalties and other fees to the property owners and other royalty interest
holders from the revenue generated by the Imperial Valley Project.
Lessors and royalty holders are generally paid a monthly or annual
rental payment during the term of the lease or mineral interest unless and until
the acreage goes into production, in which case the rental typically stops and
the (generally higher) royalty payments begin. Leases of federal property are
transacted with the Department of Interior, Bureau of Land Management, pursuant
to standard geothermal leases under the Geothermal Steam Act and the regulations
promulgated thereunder (the "Regulations"), and are for a primary term of 10
years, extendible for an additional five years if drilling is commenced within
the primary term and is diligently pursued for two successive five-year periods
upon certain conditions set forth in the Regulations. A secondary term of up to
40 years is available so long as geothermal resources from the property are
being produced or used in commercial quantities. Leases of state lands may vary
in form. Leases of private lands vary considerably, since their terms and
provisions are the product of negotiations with the landowners.
Item 3. Legal Proceedings
In addition to the proceedings described in Part 1, "The Projects, CE
Generation Gas Facilities, Saranac Project" above, 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.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
<PAGE>
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder's Matters
Not applicable.
<PAGE>
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands)
The selected data presented below as of December 31, 1999, 1998 and
1997 and for the years ended December 31, 1999, 1998, 1997 and 1996 are derived
from CE Generation's 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 Inc. and subsidiaries and Yuma Cogeneration
Associates, each a wholly-owned subsidiary of CE Generation. The consolidated
financial statements present CE Generation's financial position, results of
operations and cash flows as if CE Generation were a separate legal entity for
all periods presented. The selected data presented below as of December 31, 1996
and 1995 and for the year ended December 31, 1995 are derived from unaudited
consolidated financial statements and reflect all adjustments necessary in the
opinion of our management for a fair presentation of the data.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1999 (4) 1998 1997 1996 (2) 1995 (1)
Statement of Operations Data:
<S> <C> <C> <C> <C> <C>
Sales of electricity and thermal energy $ 295,787 $ 395,560 $ 381,458 $ 281,307 $ 179,393
Total revenue 340,683 436,175 407,138 304,843 217,182
Income before minority interest and
extraordinary item 61,970 93,778 69,996 46,211 29,131
Extraordinary item (3) (17,478) --- --- --- ---
Net income 44,492 93,778 69,996 46,211 25,040
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
1999 1998 1997 1996 (2) 1995 (1)
Balance Sheet Data:
<S> <C> <C> <C> <C> <C>
Total assets $ 1,725,411 $ 1,782,385 $ 1,560,874 $ 1,611,087 $ 1,149,858
Project loans, including current portion 76,261 90,529 103,334 114,571 54,707
Salton Sea notes and bonds, including
current portion 568,980 626,816 448,754 538,982 452,088
Senior Secured Bonds 400,000 --- --- --- ---
Total liabilities 1,333,131 1,245,438 1,096,734 1,156,184 916,433
Net investments and advances
(members' equity at
December 31, 1999) 392,280 536,947 464,140 454,903 233,425
</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 year ended December 31, 1999 reflects the early redemption of
substantially all of the outstanding 9 7/8% Limited Recourse Senior Secured
Notes Due 2003. (4) The decrease in revenue and net income in 1999 was due to
the expiration of the fixed price periods for the Elmore, Del Ranch and Salton
Sea III Projects.
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following is management's discussion and analysis of significant factors
which have affected CE Generation's financial condition and results of
operations during the periods included in the accompanying statements of
operations. The Company's actual results in the future could differ
significantly from the historical results.
Business
MidAmerican 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, FSRI and CEDC, and their
subsidiaries (which own the geothermal and natural gas-fired combined cycle
cogeneration facilities described below), were contributed by MidAmerican to CE
Generation. This restructuring was completed in February 1999.
The consolidated financial statements reflect the consolidated
financial statements of Magma and subsidiaries (excluding wholly-owned
subsidiaries retained by MidAmerican), FSRI and subsidiaries and YCA, each a
wholly-owned subsidiary. The consolidated financial statements present CE
Generation's financial position, results of operations and cash flows as if CE
Generation were a separate legal entity for all periods presented. The basis in
assets and liabilities have been carried over from MidAmerican. All material
intercompany transactions and balances have been eliminated in consolidation.
The following table sets out information concerning CE Generation
projects:
PROJECT FUEL COMMERCIAL CAPACITY LOCATION
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
CE Turbo Geothermal 2000(1) 10 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(1) 49 MW California
Power Resources Gas 1988 200 MW Texas
Yuma Gas 1994 50 MW Arizona
Saranac Gas 1994 240 MW New York
(1) The CE Turbo and Salton Sea V Project are under construction and are
expected to commence commercial operation by the summer of 2000.
On December 2, 1999, the NorCon Project was transferred to GECC and
therefore CE Generation no longer has any interest in the NorCon Project.
The Vulcan Project, Del Ranch Project, Elmore Project, Leathers Project
and CE Turbo Project are referred to as the Partnership Projects. The Salton Sea
I Project, Salton Sea II Project, Salton Sea III Project, Salton Sea IV Project
and Salton Sea V Project 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. The Power Resources Project, Yuma Project, NorCon
Project and Saranac Project are collectively referred to as the Gas Projects.
<PAGE>
Factors Affecting Results of Operations
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 Project, Hoch (Del
Ranch) Project, Elmore Project and Leathers Project plants are based on capacity
amounts of 34, 38, 38 and 38 net megawatts, respectively. The capacity factors
for Salton Sea Unit I Project, Salton Sea Unit II Project, Salton Sea Unit III
Project and Salton Sea Unit IV Project plants are based on capacity amounts of
10, 20, 49.8 and 39.6 net megawatts, respectively. The capacity factors for the
Saranac Project, Power Resources Project, NorCon Project and Yuma Project plants
are based on capacity amounts of 240, 200, 80 and 50 net megawatts,
respectively. Each plant, except the NorCon Project, 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.
Power Purchase Agreements
Imperial Valley Projects. The current Partnership Projects sell all
electricity generated by the respective plants under four long-term SO4
Agreements between the Partnership Projects and Edison. These SO4 Agreements
provide for capacity payments, capacity bonus payments and energy payments.
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 SO4 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 Edison avoids by purchasing energy from the Imperial Valley
Partnership Projects instead of obtaining the energy from other sources.
The scheduled energy price periods of the Partnership Projects'
long-term agreements extended until February 1996, December 1998, December 1998
and December 1999 for each of the Vulcan Project, Del Ranch Project, Elmore
Project and Leathers Project, respectively. The weighted average energy rate for
all of the Partnership Projects' agreements was 6.5 cents per kilowatt-hour in
1999.
Salton Sea Unit I Project sells electricity to 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 5.3 cents per kilowatt-hour
during 1999. As the Salton Sea Unit I PPA is not a SO4 Agreement, the energy
payments do not revert to payments based on the cost that Edison avoids by
purchasing energy from Salton Sea Unit I instead of obtaining the energy from
other sources. The capacity payment is approximately $1.1 million per annum.
Salton Sea Unit II Project and Salton Sea Unit III Project sell
electricity to Edison under 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 standard offer no. 4 agreements. The energy payments for each of
the first ten year periods, which periods expire in April 2000 for Salton Sea II
and expired in February 1999 for Salton Sea III, 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 Edison 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, 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 $3.3 million and $9.7
million, respectively.
<PAGE>
Salton Sea Unit IV Project sells electricity to Edison under a modified
SO4 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 PPA option (20 megawatts)
and to the original Fish Lake PPA (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 Edison is not required to
purchase the 20 megawatts of capacity and energy originally attributable to the
Salton Sea Unit I PPA option after September 30, 2017, the original termination
date of the Salton Sea Unit I PPA.
For the years ended December 31, 1999 and 1998, Edison's average price
paid for energy was 3.1 cents and 3.0 cents per kilowatt-hour, respectively,
which is substantially below the contract energy prices earned for the year
ended December 31, 1999. The Company cannot predict the likely level of energy
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 likely decline significantly
after the expiration of the respective scheduled payment periods. Revenues for
the Del Ranch Project decreased from $57.9 million in the year ended December
31, 1998 to $19.1 million in the year ended December 31, 1999 after the end of
the contract energy price period in December 1998. Revenues for the Elmore
Project decreased from $54.6 million in the year ended December 31, 1998 to
$18.7 million in the year ended December 31, 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 $62.3 million to $18.4 million in the year ended December
31, 1999.
Gas Projects. The Saranac Project sells electricity to NYSEG under the
Saranac PPA, which provides for capacity and energy payments. Capacity payments,
which in 1999 totaled 2.4 cents per kilowatt-hour, 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 7.0 cents per kilowatt-hour in 1999, escalate at
approximately 4.4% annually for the remaining term of the Saranac PPA. The
Saranac PPA expires in June of 2009.
The Power Resources Project sells electricity to Texas Utilities
Electric Company under the Power Resources PPA, which provides for capacity and
energy payments. Capacity payments and energy payments, which in 1999 are $3.2
million per month and 3.7 cents per kilowatt-hour, respectively, escalate at
3.5% annually for the remaining term of the Power Resources PPA. The Power
Resources PPA expires in September 2003.
The Yuma Project sells electricity to SDG&E under Yuma PPA. The energy
is sold at a price based on the cost that SDG&E avoids by purchasing energy from
the Yuma Project instead of obtaining the energy from other sources and the
capacity is sold to SDG&E at a fixed price for the life of the Yuma PPA. The
power is delivered to SDG&E over transmission lines constructed and owned by
APS.
Results of Operations for the Years Ended December 1999, 1998 and 1997
Sales of electricity and steam decreased to $295.8 million in the year
ended December 31, 1999 from $395.6 million in the year ended December 31, 1998,
a 25% decrease. This decrease was primarily a result of the expiration of the
fixed price periods for the Elmore and Del Ranch Projects and for the Salton Sea
Unit III Project. These periods ended in December 1998, December 1998 and
February 1999, respectively.
<PAGE>
Sales of electricity and steam increased to $395.6 million in the year
ended December 31, 1998 from $381.5 million in the year ended December 31, 1997,
a 3.7% increase. This increase was primarily due to an increase in electricity
production and the scheduled rate increases at the Imperial Valley Projects.
The following operating data represents the aggregate capacity and
electricity production of the Imperial Valley Projects:
1999 1998 1997
Overall capacity factor 98.2% 98.2% 99.2%
Megawatt-hours produced 2,300,700 2,299,400 2,323,800
Capacity (net megawatts)(average) 267.4 267.4 267.4
The following operating data represents the aggregate capacity and
electricity production of the Gas Projects:
1999 1998 1997
Overall capacity factor 83.5% 81.6% 84.3%
Megawatt-hours produced 4,258,606 4,072,620 4,211,030
Capacity (net megawatts)(weighted average) 557 570 570
The overall capacity factor of the Gas Projects reflects the effect of
contractual curtailments. The capacity factors adjusted for these contractual
curtailments are 92.5%, 92.2% and 95.7% for 1999, 1998 and 1997, respectively.
The changes in the overall capacity factor in 1999, 1998 and 1997 were due
primarily to major maintenance downtime and lower electricity production at the
Saranac Project due to 1998 winter snow and ice storms which caused transmission
curtailment.
The increase in equity earnings of subsidiaries in 1999 to $22.9
million from $10.7 million in 1998 was primarily due to lower electricity
production at the Saranac Project in 1998 due to severe winter snow and ice
storms which caused transmission curtailments. The decrease in equity earnings
of subsidiaries in 1998 to $10.7 million from $14.5 million in 1997 represents
the negative impact of the January 1998 ice storm at the Saranac Project.
Interest and other income decreased to $22.0 million in the year ended
December 31, 1999 from $29.9 million in the year ended December 31, 1998. This
decrease was primarily due to reduced royalty income at the Imperial Valley
Projects. Interest and other income increased to $29.9 million in the year ended
December 31, 1998 from $11.1 million in the year ended December 31, 1997, a 168%
increase. 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 $6.9 million, 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.
Plant operating expenses decreased in 1999 to $112.8 million from
$114.1 million in 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. Operating expenses
decreased in 1998 to $114.1 million from $120.0 million in 1997, a 4.9%
decrease. The decrease was primarily due to operating efficiencies.
General and administrative expenses decreased to $4.6 million in the
year ended December 31, 1999 from $5.0 million in the year ended December 31,
<PAGE>
1998. General and administrative expenses increased to $5.0 million in the year
ended December 31, 1998 from $4.4 million in the year ended December 31, 1997.
These costs include administrative services provided to CE Generation, including
executive, financial, legal, tax and other corporate functions. The increase in
1998 reflects increased bank service charges relating to increased indebtedness.
Depreciation and amortization decreased to $57.9 million in 1999 from
$96.8 million in 1998. 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. Depreciation and amortization increased to $96.8 million in
1998 from $88.5 million 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 Partnership
Projects. The amortization method was modified 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 fixed price periods
terminated in 1999.
Interest expense, less amounts capitalized, decreased in 1999 to $72.5
million from $74.3 million in 1998, a decrease of 2.4%. Interest expense, less
amounts capitalized, decreased in 1998 to $74.3 million from $80.9 million in
1997, a 8.2% decrease. Lower interest expense resulted from the paydown of the
Salton Sea Funding Corporation and Power Resources Project debt offset by Salton
Sea Funding Corporation's Series F issuance in October 1998 and CE Generation's
issuance of Securities in 1999.
The provision for income taxes decreased to $30.9 million in 1999 from
$52.2 million in 1998 and $43.4 million in 1997. The effective tax rate was
33.3%, 35.8%and 38.3% in 1999, 1998 and 1997, respectively. The changes from
year to year in the effective rate are due primarily to the generation and
utilization of energy tax credits and depletion deductions.
The extraordinary item of $17.5 million in 1999 reflects the premium
paid and deferred finance costs associated with the repayment of its 9 7/8%
Limited Recourse Senior Secured Notes.
Liquidity and Capital Resources
Cash and cash equivalents were $29.1 million at December 31, 1999 as
compared to $25.8 million at December 31, 1998. In addition, restricted cash was
$32.6 million and $128.6 million at December 31, 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 V Project and the CE Turbo Project and the
construction of upgrades to the brine facilities at some of the Imperial Valley
Projects.
Existing cash and cash generated by operating activities are expected
to be sufficient to finance capital expenditures and make scheduled repayment of
debt for the foreseeable future.
On March 2, 1999, CE Generation closed the sale of $400 million
aggregate principal amount of 7.416% Senior notes due December 15, 2018. The
proceeds were used to repay Magma's 9 7/8% note payable to MidAmerican of $200
million and Yuma's note payable to MidAmerican of $47.7 million. 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 CE Generation 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.
<PAGE>
The securities are senior secured debt which rank equally in right of
payment with the other senior secured debt permitted under the indenture for the
securities, share equally in the collateral with the other senior secured debt
permitted under the indenture for the securities, and rank senior to any of the
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 securities are secured by the following collateral:
* all available cash flow of CE Generation subsidiaries that have
assigned their available cash flows to secure the obligation to make payments on
the securities;
* 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;
* 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;
* a pledge of all of the capital stock of SECI Holdings Inc.;
* a grant of a lien on and security interest in the depositary
accounts; and
* 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 million to $18 million. The
maximum annual principal payment obligation during the period is approximately
$36 million in 2018.
Salton Sea Power L.L.C., one of CE Generation's indirect wholly-owned
subsidiaries, is constructing Salton Sea Unit V Project. The Salton Sea Unit V
Project is a 49 net megawatt geothermal power plant which will sell
approximately one-third of its net output to the zinc facility, which was
retained by MidAmerican. The remainder will be sold through the California power
exchange or in other market transactions.
The Salton Sea Unit V Project is being constructed under an
engineering, procurement and construction contract by Stone & Webster
Engineering Corporation. Salton Sea Unit V Project is scheduled to commence
commercial operation in mid-2000. Total project costs of the Salton Sea Unit V
Project are expected to be approximately $119.1 million which is being funded by
$76.3 million of debt from Salton Sea Funding Corporation and $42.8 million from
equity contributions. Salton Sea Power has incurred approximately $85.6 million
of these costs through December 31, 1999.
CE Turbo LLC, one of CE Generation's 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 or in
other market transactions.
The Partnership Projects are upgrading the geothermal brine processing
facilities at the Vulcan and Del Ranch projects with the brine facilities
construction.
The CE Turbo Project and the 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 to mid 2000 and the brine facilities construction is
scheduled to be completed in early-2000. Total project costs for both the CE
Turbo Project and the brine facilities construction are expected to be
approximately $63.7 million which will be funded by $55.6 million of debt from
Salton Sea Funding Corporation and $8.1 million from equity contributions. The
Company has incurred approximately $40.8 million of these costs through December
31, 1999.
<PAGE>
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 Project 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 $140.5 million and associated interest.
On December 2, 1999, MidAmerican's indirect subsidiary, NorCon Power
Partners, L.P., reached agreement with NIMO to dismiss the outstanding
litigation between NorCon and NIMO. At the same time, NorCon transferred the
NorCon Project to GECC 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 GECC. GECC 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 MidAmerican's other subsidiaries owns an
interest in the NorCon Project and the NorCon Project contracts are either 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 twelve months ended December 31,
1999 and our share of NorCon's net assets is less than 1% of the equity
investments at December 31, 1999, the transfer of the NorCon Project to GECC is
not expected to have any significant impact on our results of operations,
financial condition or liquidity.
Inflation
Inflation has not had a significant impact on CE Generation's cost
structure.
Recent Accounting Pronouncements
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 the Company beginning January 1,
2001. The Company has not yet determined the impact of this accounting
pronouncement.
<PAGE>
Pending Accounting Policy Change
The Accounting Standards Executive Committee (AcSEC) of the American
Institute of Certified Public Accountants is considering a project that in part
will address the accounting for major maintenance activities. The project will
address the use of the accrual, deferral and expense methods of accounting for
major maintenance activities. Pending any change in current authoritative
guidance, the Company may change its current method of accounting for major
maintenance, overhaul and well workover costs.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
Certain information included in this report contains forward-looking
statements made pursuant to the Private Securities Litigation Reform Act of 1995
("Reform Act"). Such statements are based on current expectations and involve a
number of known and unknown risks and uncertainties that could cause the actual
results and performance of the Company to differ materially from any expected
future results or performance, expressed or implied, by the forward-looking
statements. In connection with the safe harbor provisions of the Reform Act, the
Company has identified important factors that could cause actual results to
differ materially from such expectations, including development and construction
uncertainty, operating uncertainty, uncertainties relating to doing business
outside of the United States, uncertainties relating to economic and political
conditions and uncertainties regarding the impact of regulations, changes in
government policy, industry deregulation and competition. The Company assumes no
responsibility to update forward-looking information contained herein.
Interest Rate Risk
At December 31, 1999, the Company had fixed-rate long-term debt of
$969.0 million with a fair value of $907.5 million. 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 $60.0 million if interest rates were to increase
by 10% from their levels at December 31, 1999. In general, a decrease in fair
value would impact earnings and cash flows only if the Company were to reacquire
all or a portion of these instruments prior to their maturity.
At December 31, 1999, the Company had floating-rate obligations of
$76.3 million which exposes the Company to the risk of increased interest
expense in the event of increases in short-term interest rates. The Company has
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, 1999, these interest rate swaps had an aggregate notional amount
of $76.3 million, which the Company could terminate at a cost of approximately
$4.1 million. A decrease of 10% in the December 31, 1999 level of interest rates
would increase the cost of terminating the swaps by approximately $0.8 million.
These termination costs would impact the Company's earnings and cash flows only
if all or a portion of the swap instruments were terminated prior to their
expiration.
<PAGE>
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
PAGE
Consolidated Financial Statements of CE Generation, LLC:
Independent Auditors' Report 23
Consolidated Balance Sheets as of December 31, 1999 and 1998 24
Consolidated Statements of Operations for the Three Years Ended
December 31, 1999, 1998 and 1997 25
Consolidated Statement of Members' Equity for the Three Years Ended
December 31, 1999, 1998 and 1997 26
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1999, 1998 and 1997 27
Notes to Consolidated Financial Statements 28
Consolidated Financial Statements of Magma Power Company (included in
accordance with Rule 310):
Independent Auditors' Report 46
Consolidated Balance Sheets as of December 31, 1999 and 1998 47
Consolidated Statements of Operations for the Three Years Ended 48
Consolidated Statements of Stockholder's Equity for the Three Years Ended 49
Consolidated Statements of Cash Flows for the Three Years Ended 50
Notes to Consolidated Financial Statements 51
Consolidated Financial Statements of Falcon Seaboard Resources, Inc.
(included in accordance with Rule 310):
Independent Auditors' Report 62
Consolidated Balance Sheets as of December 31, 1999 and 1998 63
Consolidated Statements of Operations for the Three Years Ended
December 31, 1999, 1998 and 1997 64
Consolidated Statements of Changes in Stockholder's Equity for the
Three Years Ended December 31, 1999, 1998 and 1997 65
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1999, 1998 and 1997 66
Notes to Consolidated Financial Statements 67
<PAGE>
Consolidated Financial Statements of Saranac Power Partners L. P and
Subsidiary (included in accordance with Rule 309):
Independent Auditors' Report 75
Consolidated Balance Sheets as of December 31, 1999 and 1998 76
Consolidated Statements of Operations for the Three Years Ended
December 31, 1999, 1998 and 1997 77
Consolidated Statements of Partners' Capital for the Three Years Ended
December 31, 1999, 1998 and 1997 78
Consolidated Statements of Cash Flows for the Three Years Ended
December 31, 1999, 1998 and 1997 79
Notes to Consolidated Financial Statements 80
<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, 1999 and 1998, and the related consolidated
statements of operations, members equity, and cash flows for each of the three
years in the period ended December 31, 1999. 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, 1999 and 1998 and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1999 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Omaha, Nebraska
January 25, 2000
<PAGE>
CE GENERATION, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(Amounts in Thousands)
1999 1998
ASSETS
Cash and cash equivalents $ 29,120 $ 25,774
Restricted cash 6,776 26,877
Accounts receivable 40,688 67,629
Prepaid expenses 10,461 11,677
Inventory 19,734 15,442
Due from affiliates 3,794 ---
Deferred income taxes 9,256 31,753
Other assets --- 4,629
Total current assets 119,829 183,781
Restricted cash 25,836 101,676
Properties, plants, contracts and equipment, net 1,017,342 893,492
Equity investments 118,637 125,036
Excess of cost over fair value of net assets acquired,
net 285,888 310,700
Note receivable from related party (Note 6) 140,520 140,520
Deferred financing charges and other assets 17,359 27,180
Total assets $ 1,725,411 $ 1,782,385
LIABILITIES AND EQUITY
Liabilities:
Accounts payable and other accrued liabilities $ 41,314 $ 37,940
Current portion of long term debt 51,520 72,104
Total current liabilities 92,834 110,044
Project loan 60,173 76,261
Salton Sea notes and bonds 543,948 568,980
Senior secured bonds 389,600 ---
Notes payable to related party --- 247,681
Deferred income taxes 246,576 240,602
Other long term liabilities --- 1,870
Total liabilities 1,333,131 1,245,438
Commitments and contingencies (Note 9)
Members equity 392,280 536,947
Total liabilities and equity $ 1,725,411 $ 1,782,385
The accompanying notes are an integral part of these financial statements.
<PAGE>
CE GENERATION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
1999 1998 1997
Revenue:
Sales of electricity and steam $ 295,787 $ 395,560 $ 381,458
Equity earnings in subsidiaries 22,861 10,732 14,542
Interest and other income 22,035 29,883 11,138
Total revenues 340,683 436,175 407,138
Cost and Expenses:
Plant operations 112,801 114,092 119,973
General and administrative 4,594 4,963 4,380
Depreciation and amortization 57,869 96,818 88,504
Interest expense 77,515 74,653 80,907
Less interest capitalized (4,978 (347) ---
Total expenses 247,801 290,179 293,764
Income before provision for income taxes
and extraordinary item 92,882 145,996 113,374
Provision for income taxes 30,912 52,218 43,378
Income before extraordinary item 61,970 93,778 69,996
Extraordinary item, net of tax (Note 8) (17,478 --- ---
Net income $ 44,492 $ 93,778 $ 69,996
The accompanying notes are an integral part of these financial statements.
<PAGE>
CE GENERATION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF MEMBERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
BALANCE, January 1, 1997 $ 454,903
Distribution, net of advances (60,759)
Net income 69,996
BALANCE, December 31, 1997 464,140
Distribution, net of advances (20,971)
Net income 93,778
BALANCE, December 31, 1998 536,947
Distribution, net of advances (122,080)
Distribution of non-cash assets to MEHC (67,079)
Net income 44,492
BALANCE, December 31, 1999 $ 392,280
The accompanying notes are an integral part of these financial statements.
<PAGE>
CE GENERATION, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $ 44,492 $ 93,778 $ 69,996
Adjustments to reconcile to cash flows from
operating activities:
Extraordinary item, net of tax 17,478 --- ---
Depreciation and amortization 57,869 96,818 88,504
Provision for deferred income taxes (832) (6,144) 4,280
Distribution from equity investments in excess of
equity earnings 6,399 6,171 9,418
Changes in other items:
Accounts receivable 26,941 (14,557) (2,005)
Inventory (4,292) (3,191) 2,893
Due from affiliates (3,794) --- ---
Accounts payable and other accrued liabilities 1,504 (9,133) 4,837
Other assets 8,632 7,524 4,769
Net cash flows from operating activities 154,397 171,266 182,692
Cash flows from investing activities:
Capital expenditures (183,508) (46,222) (21,676)
Decrease (increase) in restricted cash 75,840 (101,366) 15,120
Net cash flows from investing activities (107,668) (147,588) (6,556)
Cash flows from financing activities:
Repayment of Salton Sea notes and bonds (57,836) (106,938) (90,228)
Proceeds from Salton Sea notes and bonds --- 285,000 ---
Proceeds from Senior Secured bonds 400,000 --- ---
Note receivable from related party --- (140,520) ---
Repayment of note payable to related party (269,300) (131) ---
Repayment of project loans (14,268) (12,805) (11,237)
Deferred charge relating to debt financing --- (4,943) (11,623)
Distributions to MEHC, net of advances (122,080) (20,971) (60,759)
Decrease (increase) in restricted cash 20,101 (20,280) (97)
Net cash flows from financing activities (43,383) (21,588) (173,944)
Net increase in cash and cash equivalents 3,346 2,090 2,192
Cash and cash equivalents at beginning of year 25,774 23,684 21,492
Cash and cash equivalents at end of year $ 29,120 $ 25,774 $ 23,684
Supplemental disclosure:
Interest paid $ 78,944 $ 73,283 $ 72,846
Income taxes paid $ 31,744 $ 58,362 $ 39,098
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
CE GENERATION, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
1. Business
MidAmerican Energy Holdings Company ("MEHC" and the successor in
interest to CalEnergy Company, Inc.) completed a strategic restructuring in
conjunction with its acquisition of MHC Inc. (formerly "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.
On March 3, 1999, MEHC closed the sale of 50% of its ownership
interests in CE Generation to El Paso CE Generation Holding Company. El Paso is
an affiliate of El Paso Energy Corporation.
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, 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:
PROJECT FUEL COMMERCIAL CAPACITY LOCATION
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
<PAGE>
On December 2, 1999, the NorCon Project was transferred to GECC and
therefore CE Generation no longer has any interest in the NorCon Project.
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.
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 the Salton Sea V Project, 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 million aggregate amount of 7.475% Senior Secured Series F Bonds due
November 30, 2018 (see Note 6).
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
$5.9 million and $6.7 million at December 31, 1999 and 1998, respectively, and
are included in other assets.
Inventories--Inventories consist of spare parts and supplies and are
valued at the lower of cost or market. Cost for large replacement parts is
determined using the specific identification method. For the remaining supplies,
cost is determined using the weighted average cost method.
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 ranged 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 ranged from 7
to 30 years.
<PAGE>
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, 1999 and 1998, the carrying amount of CE Generation's investment in
Saranac differs from its underlying equity in net assets of Saranac by $98.5
million (net of accumulated amortization of $35.1 million) and $108.8 million
(net of accumulated amortization of $24.8 million), 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
$42.6 million and $32.9 million at December 31, 1999 and 1998, respectively.
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 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--CE Generation had historically been included in the
consolidated income tax returns of MEHC. CE Generation's provision for income
taxes was computed on a separate return basis. Beginning March 3, 1999, CE
Generation became a separate consolidated taxpayer. 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, based on discounted cash
flows or various models, whenever evidence exists that the carrying value is not
recoverable.
<PAGE>
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 Valley. 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 periods terminated 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 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 the Company beginning
January 1, 2001. CE Generation has not yet determined the impact of this
accounting pronouncement.
Pending Accounting Policy Change--The Accounting Standards Executive
Committee (AcSEC) of the American Institute of Certified Public Accountants is
considering a project that in part will address the accounting for major
maintenance activities. The project will address the use of the accrual,
deferral and expense methods of accounting for major maintenance activities.
Pending any change in current authoritative guidance, the Company may change its
current method of accounting for major maintenance, overhaul and well workover
costs.
3. Equity Investments
CE Generation indirectly holds noncontrolling general and limited
partnership interests in Saranac Power Partners, L.P. (Saranac) which was formed
to build, own and operate natural gas fired combined cycle cogeneration
facilities. The lenders to the partnership have recourse only against these
facilities and the income and revenues therefrom. In 1999, CE Generation had an
approximate 49% economic interest in Saranac. Effective in January 2000, CE
Generation has an approximate 61% economic interest in the partnership as TPC
Saranac achieved an after tax return of 8.35%. CE Generation will have an
approximate 80% economic interest in the partnership after General Electric
Capital Company achieves an after tax return, as defined in the Partnership
Agreement, of approximately 7.252%.
The following is a summary of aggregated financial information for
Saranac as of and for the year ended December 31, 1999 and 1998 (in thousands):
1999 1998
Assets $ 289,152 $ 300,425
Liabilities 192,524 197,680
Revenues 164,965 138,574
Net income 55,163 38,041
<PAGE>
Saranac has project financing through a 14 year note payable agreement
with a lender with a principal amount outstanding of $181.1 million at December
31, 1999. 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 occurred 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.
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.
There were no undistributed earnings in equity investments at December
31, 1999.
<PAGE>
4. Properties, Plants, Contracts and Equipment
Properties, plants, contracts and equipment comprise the following at
December 31 (in thousands):
1999 1998
Operating facilities:
Power plants $ 716,809 $ 678,710
Wells and resource development 151,996 137,399
Power sales agreements 287,653 287,653
Licenses and equipment 47,905 41,671
Total operating facilities 1,204,363 1,145,433
Less accumulated depreciation and amortization (326,042) (270,244)
Net operating facilities 878,321 875,189
Construction in progress:
Salton Sea Unit V 89,072 9,227
Turbo and Region 2 Brine Facilities Construction 42,612 2,253
Other development 7,337 6,823
Total $ 1,017,342 $ 893,492
Significant Customers and Contracts--All of CE Generation's current
sales of electricity from the Imperial Valley Projects, which comprise
approximately 66% and 74% respectively, of 1999 and 1998 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 $40.7 million and $67.6 million at December 31, 1999 and 1998,
respectively.
Imperial Valley 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 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 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.
<PAGE>
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 Projects SO4
agreements extended until February 1996, December 1998, December 1998 and
December 1999 for each of the Vulcan, Del Ranch, Elmore and Leathers
Partnerships, respectively. The weighted average energy rate for all of the
Partnership Projects' SO4 Agreements was 6.49 cents per kWh in 1999.
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
5.3 cents per kWh during 1999. 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 $1.1 million 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 for Salton Sea II and expired in February 1999 for Salton Sea III,
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 $3.3 million and $9.7 million, 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, 1999 and 1998, Edison's average
Avoided Cost of Energy was 3.1 cents and 3.0 cents per kWh, respectively, which
is substantially below the contract energy prices earned for the year ended
December 31, 1999. CE Generation cannot predict the 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 likely 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 $1.46 per month per kilowatt of service provided for 1999 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.
<PAGE>
The Imperial Valley projects obtain their geothermal resource rights
from Magma Power Company and Magma Land Company I, wholly-owned subsidiaries of
the Company.
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 1999,
1998, and 1997 was approximately 6.2%, 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.
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 $7.5 million in 1998. This change
will not have a significant impact on future periods as the scheduled price
periods terminated in 1999.
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 1999 total 2.4 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 7.0 cents per kWh in 1999, 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 1999 are $3.2 million
per month and 3.7 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 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.
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, 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.
<PAGE>
Saranac purchases natural gas from Coral Energy under a 15-year gas
supply agreement that expires in 2009. The price was $2.89 per MMBtu at December
1999 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 $2.85 per MMBtu in 1999
and escalates 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 $2.24 per MMBtu in 1999 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.
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, 1999, 1998
and 1997, which is included in plant operations in the consolidated statements
of operations, comprise the following (in thousands):
1999 1998 1997
Vulcan $ 423 $ 363 $ 326
Leathers 3,361 2,811 2,694
Elmore 520 2,192 2,213
Del Ranch 856 2,870 2,650
Salton Sea I & II 827 810 1,206
Salton Sea III 1,673 1,637 2,439
Salton Sea IV 2,569 2,645 2,815
Total $ 10,229 $ 13,328 $ 14,343
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 1999, 1998
and 1997 was approximately 6.2%, 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.
5. 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 Subsidiary of CE Generation, will be available to
satisfy the obligations of CE Generation or any of its other 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.
"Subsidiary" means all of CE Generation's direct or indirect subsidiaries (1)
owning direct or indirect interests in the Imperial Valley projects (including
the Salton Sea projects and the Partnership projects other than Magma Power
Company and Salton Sea Power Company), or (2) owning direct interests in the
subsidiaries that own interests in the foregoing projects, the Saranac project
and the Power Resources project.
<PAGE>
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 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 $55.0 million and $110.0 million, 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 notional values of
these financial instruments were $76.3 million and $90.5 million at December 31,
1999 and 1998, 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 $4.1 million and $9.9
million at December 31, 1999 and 1998, 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. Power Resources recorded additional interest expense of $617,000,
$1,176,000 and $1,091,000 for the years ended December 31, 1999, 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 (in thousands):
2000 $ 16,088
2001 18,119
2002 20,312
2003 21,742
Total $ 76,261
<PAGE>
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, 1999.
6. 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 (in thousands):
ISSUED DATE SENIOR FINAL RATE DECEMBER 31,
SECURED MATURITY 1999 1998
SERIES DATE
July 21, 1995 A Notes May 30, 2000 6.69% $ 18,532 $ 48,436
July 21, 1995 B Bonds May 30, 2005 7.37 101,776 106,980
July 21, 1995 C Bonds May 30, 2010 7.84 109,250 109,250
June 20, 1996 D Notes May 30, 2000 7.02 1,500 12,150
June 20, 1996 E Bonds May 30, 2011 8.30 52,922 65,000
October 13, 1998 F Bonds November 30, 2018 7.48 285,000 285,000
$ 568,980 $ 626,816
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 million aggregate amount of 7.475% Senior
Secured Series F Bonds due November 30, 2018. The proceeds of $144.5 million
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 $140.5 million 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 $140.5
million and associated interest.
<PAGE>
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
$67.6 million 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, 2000 and thereafter are as follows:
2000 $ 25,032
2001 23,658
2002 28,572
2003 28,086
2004 30,588
Thereafter 433,044
$ 568,980
CE Generation's ability to obtain distributions from its investment in
the Salton Sea Projects and Partnership Projects is subject to the following
conditions:
* the depositary accounts for the Salton Sea Notes and Bonds must be
fully funded;
* there cannot have occurred and be continuing any default or event of
default under the Salton Sea Notes and Bonds;
* 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;
* there must be sufficient geothermal resources to operate the Salton
Sea projects at their required levels; and
* 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.
7. Senior Secured Bonds
On March 2, 1999, CE Generation issued $400 million of 7.416% Senior
Secured Bonds due 2018. The net proceeds from this financing were used for the
following purposes:
* 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;
* 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;
* to repay approximately $49 million outstanding principal and interest
on a promissory note to MEHC;
* to make payments to MEHC aggregating up to approximately $4 million
in return for MEHC's transfers of certain assets to the Company which related to
MEHC's development costs for Salton Sea Unit V, the CE Turbo project and the
zinc facility; and
* to pay transaction costs and fees associated with the offer and sale
of the old securities.
<PAGE>
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:
* all available cash flow (as defined);
* 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;
* 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;
* a pledge of all of the capital stock of SECI Holding Inc.;
* a grant of a lien on and security interest in the depository
accounts; and
* 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 Senior Secured Bonds 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.
Annual repayments of the Senior Secured Bonds for the years beginning January 1,
2000 and thereafter are as follows (in thousands):
2000 $ 10,400
2001 12,600
2002 20,600
2003 18,000
2004 14,600
Thereafter 323,800
$ 400,000
<PAGE>
8. Notes Payable to Related Party
On July 21, 1995, MEHC issued $200 million 9 7/8% 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 the Notes offering
were provided by MEHC to Magma and Magma issued an intercompany note to MEHC in
the amount of $200 million.
On January 29, 1999, MEHC commenced a cash offer for all 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 of $11.1 million. Proceeds from the issuance of CE Generation's Senior
Secured Bonds were used to repay the outstanding principal and interest on the
note.
Yuma Cogeneration Associates had outstanding a note payable to MEHC
with a principal balance at December 31, 1998 of $47.7 million, and bearing
interest at a fixed rate of 10.25%. Proceeds from the issuance of CE
Generation's Senior Secured Bonds were used to repay the outstanding principal
and interest on the note.
9. Commitments and Contingencies
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, the
Saranac Partnership 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 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 required
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 on July 28, 1995. On October 30,
1996, all parties filed final briefs and the Court of Appeals heard oral
arguments on December 2, 1996. On July 11, 1997, the Court of Appeals dismissed
NYSEG's appeal from FERC's denial of the petition on jurisdictional grounds.
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), the Saranac Partnership and Lockport Energy
Associates, L.P. ("Lockport") concerning the power purchase agreements that
NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that
the PSC and the FERC improperly implemented PURPA in authorizing the pricing
terms that NYSEG, the Saranac Partnership 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 the Saranac Partnership. The Saranac Partnership and
other parties have filed motions to dismiss and oral arguments on those motions
were heard on March 2, 1998 and again on March 3, 1999. The Saranac Partnership
believes that NYSEG's claims are without merit for the same reasons described in
the FERC's orders.
<PAGE>
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. Plaintiffs 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. In September 1999, the plaintiffs settled with Edison for
approximately $3.7 million including accrued interest.
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, 1999, 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 (in thousands):
2000 $ 23,308
2001 23,608
2002 24,285
2003 24,854
Total $ 96,055
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 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%.
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
1999 total 2.4 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 7.0
cents per kWh in 1999, 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.
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.
<PAGE>
Salton Sea Power, L.L.C., one of our indirect wholly-owned
subsidiaries, is constructing Salton Sea Unit V. The Salton Sea Unit V Project
is a 49 net megawatt geothermal power plant which will sell approximately
one-third of its net output to the zinc facility, which was retained by
MidAmerican. The remainder will be sold through the California power exchange or
in other market transactions.
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 $119.1 million which will be funded by $76.3
million of debt from Salton Sea Funding Corporation and $42.8 million 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 or in other market
transactions.
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 to mid 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 $63.7 million
which are being funded by $55.6 million of debt from Salton Sea Funding
Corporation and $8.1 million from equity contributions.
10. Income Taxes
Provision for income tax is comprised of the following at December 31
(in thousands):
1999 1998 1997
Current:
State $ 6,841 $ 11,099 $ 8,451
Federal 24,903 47,263 30,647
31,744 58,362 39,098
Deferred:
State (3,915) (836) 1,057
Federal 3,083 (5,308) 3,223
(832) (6,144) 4,280
Total $ 30,912 $ 52,218 $ 43,378
<PAGE>
A reconciliation of the federal statutory tax rate to the effective tax
rate applicable to income before provision for income taxes follows:
1999 1998 1997
Federal statutory rate 35.0% 35.0% 35.0%
Percentage depletion in excess of cost depletion (6.0) (4.4) (4.6)
Investment and energy tax credits (1.4) (2.5) (0.9)
Goodwill amortization 3.7 3.1 3.6
State taxes, net of federal benefit 2.0 4.6 5.2
Effective tax rate 33.3% 35.8% 38.3%
Deferred tax liabilities (assets) are comprised of the following at December 31
(in thousands):
1999 1998
Liabilities:
Depreciation and amortization, net $ 246,232 $ 240,602
Other 2,224 ---
248,456 240,602
Assets:
Accruals not currently deductible for tax purposes (9,356) (3,218)
General business tax credits --- (8,891)
Alternative minimum tax credits --- (16,333)
Other (1,780) (3,311)
Net deferred taxes (11,136) (31,753)
237,320 208,849
Less current portion (deferred tax asset) (9,256) (31,753)
Long-term deferred tax liability $ 246,576 $ 240,602
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.
<PAGE>
The carrying amounts in the table below are included in the
consolidated balance sheets under the indicated captions (in thousands):
<TABLE>
<CAPTION>
1999 1998
CARRYING ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE FAIR
VALUE VALUE
Financial Assets:
<S> <C> <C> <C> <C>
Note receivable from related party $ 140,520 $ 128,815 $ 140,520 $ 140,942
Financial Liabilities:
Project loan 76,261 76,261 90,529 90,529
Salton Sea notes and bonds 560,880 540,659 626,816 646,397
Notes payable to related party --- --- 247,681 265,581
Interest rate swap --- 4,082 --- 9,904
Senior secured bonds 400,000 366,800 --- ---
</TABLE>
12. 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. 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 $2.7 million, $3.0 million and $3.0 million for each of 1999,
1998, and 1997, and are included in General and Administrative expenses.
<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 CE Generation
LLC), as of December 31, 1999 and 1998 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, 1999. 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, 1999 and 1998 and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
January 25, 2000
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CE Generation LLC)
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 1999 AND 1998
(Dollars in Thousands Except Per Share Amounts)
<TABLE>
<CAPTION>
1999 1998
ASSETS
<S> <C> <C>
Cash and cash equivalents $ 3,372 $ 54,661
Restricted cash --- 25,147
Accounts receivable 29,878 90,395
Due from related parties 3,726 ---
Prepaid expenses 9,916 21,677
Inventory and other assets 15,593 18,801
Deferred income taxes 8,421 ---
Total current assets 70,906 210,681
Restricted cash 24,512 215,696
Properties, plants, contracts and equipment, net 837,174 1,212,322
Excess of cost over fair value of net assets acquired, net 201,303 283,552
Note receivable from related party 140,520 ---
Deferred charges and other assets 11,912 36,808
Total assets $ 1,286,327 $ 1,959,059
LIABILITIES AND STOCKHOLDER'S EQUITY
Liabilities:
Accounts payable and accrued liabilities $ 29,373 $ 45,418
Current portion of long-term debt 25,032 80,396
Due to related parties --- 43,673
Deferred income taxes--current --- 1,221
Total current liabilities 54,405 170,708
Malitbog loans --- 131,246
Salton Sea notes and bonds 543,948 568,980
Note payable to related party --- 200,000
Deferred income taxes 162,035 245,558
Other long-term liabilities --- 930
Total liabilities 760,388 1,317,422
Deferred income --- 32,147
Commitments and contingencies (Note 9)
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 24,313 107,864
Total stockholder's equity 525,939 609,490
Total liabilities and stockholder's equity $ 1,286,327 $ 1,959,059
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Dollars In Thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Revenue:
<S> <C> <C> <C>
Sales of electricity and steam $ 201,454 $ 370,470 $ 328,248
Royalty income 2,240 2,284 3,489
Interest and other income 13,556 28,072 3,978
Total revenues 217,250 400,826 335,715
Cost and Expenses:
Plant operations 61,158 70,624 72,196
General and administration 2,185 1,820 1,380
Depreciation and amortization 43,590 105,876 89,134
Interest expense 44,807 76,850 72,386
Less interest capitalized (6,804) (20,934) (20,549)
Total expenses 144,936 234,236 214,547
Income before provision for income taxes 72,314 166,590 121,168
Provision for income taxes 24,138 61,191 45,361
Income before extraordinary items 48,176 105,399 75,807
Extraordinary item, net of tax (Note 6) (17,478) --- ---
Net income $ 30,698 $ 105,399 $ 75,807
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Dollars in Thousands)
<TABLE>
<CAPTION>
OUTSTANDING COMMON ADDITIONAL RETAINED
COMMON STOCK PAID-IN EARNINGS TOTAL
SHARES CAPITAL
<S> <C> <C> <C> <C> <C>
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
Distribution --- --- --- (72,915) (72,915)
Contribution --- --- --- 298,818 298,818
Distribution of equity interest in
excluded subsidiaries to MidAmerican --- --- --- (340,152) (340,152)
Net income --- --- --- 30,698 30,698
BALANCE, December 31, 1999 100 $ --- $ 501,626 $ 24,313 $ 525,939
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Dollars in Thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $ 30,698 $ 105,399 $ 75,807
Adjustments to reconcile to net cash flows
from operating activities:
Depreciation and amortization 43,590 105,876 89,134
Provision for deferred income taxes (7,427) 18,533 17,277
Extraordinary item, net of tax 17,478 --- ---
Changes in other items:
Accounts receivable 26,026 (32,984) (12,445)
Inventory and other assets 13,177 (2,555) 4,709
Accounts payable and other accrued liabilities (25,132) 33,326 (19,508)
Net cash flows from operating activities 98,410 227,595 154,974
Cash flows from investing activities:
Capital expenditures (129,098) (102,842) (50,907)
Cash distributed in spin-off (677) --- ---
Decrease (increase) in restricted cash 104,674 (215,696) 14,044
Net cash flows from investing activities (25,101) (318,538) (36,863)
Cash flows from financing activities:
Due from parent (71,046) 124,597 (12,230)
Proceeds from debt offerings --- 285,000 ---
Repayment of Salton Sea notes and bonds (57,836) (106,938) (90,228)
Repayment of note payable (221,619) --- ---
Repayment of project loans --- (22,851) ---
Proceeds from construction and other loans --- --- 38,776
Distribution to parent (72,915) (170,000) ---
Contribution from parent 298,818 --- ---
Deferred charge relating to debt financing --- (4,943) (11,623)
Decrease (increase) in restricted cash --- 26,688 (42,184)
Net cash flows from financing activities (124,598) 131,553 (117,489)
Net increase (decrease) in cash and cash equivalents (51,289) 40,610 622
Cash and cash equivalents at beginning of year 54,661 14,051 13,429
Cash and cash equivalents at end of year $ 3,372 $ 54,661 $ 14,051
Supplemental disclosure:
Interest paid (net of amounts capitalized) $ 45,949 $ 54,048 $ 50,802
Income taxes paid $ 31,565 $ 42,658 $ 28,084
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
MAGMA POWER COMPANY AND SUBSIDIARIES
(A wholly-owned subsidiary of CE Generation LLC)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
1. Business
Magma Power Company (the "Company" or "Magma"), a wholly-owned
subsidiary of CE Generation LLC 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. 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.
Prior to February 8, 1999, the Company was wholly-owned by MidAmerican
Energy Holdings Company ("MEHC"). On February 8, 1999, MEHC 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
to CE Generation. On March 3, 1999, MEHC closed the sale of 50% of its ownership
interests in CE Generation to an affiliate of El Paso Energy Corporation.
2. Summary of Significant Accounting Policies
The consolidated financial statements include the accounts of the
Company and its wholly-owned subsidiaries. All material intercompany
transactions and balances have been eliminated in consolidation. Management
believes the financial statements reflect all material costs associated with the
Company's operations.
The consolidated financial statements reflect the acquisition by MEHC
and the resulting push down to the Company of the accounting as a purchase
business combination.
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 million aggregate
amount of 7.475% Senior Secured Series F Bonds due November 30, 2018 (see Note
6).
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.
<PAGE>
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 $5.9
million and $6.7 million at December 31, 1999 and 1998, respectively, and are
included in other assets.
Inventories--Inventories consist of spare parts and supplies and are
valued at the lower of cost or market. Cost for large replacement parts is
determined using the specific identification method. For the remaining supplies,
cost is determined using the weighted average cost method.
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 includes power sales agreements, which 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.
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 $27.9
million and $30.2 million at December 31, 1999 and 1998, 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 had historically been included in the
consolidated income tax returns of MEHC and as of March 3, 1999 is included in
the consolidated income tax return of CE Generation. 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.
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, based on discounted cash
flow or various models, whenever evidence exists that the carrying value is not
recoverable.
<PAGE>
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.
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 the Company beginning
January 1, 2001. The Company has not yet determined the impact of this
accounting pronouncement.
Pending Accounting Policy Change--The Accounting Standards Executive
Committee (AcSEC) of the American Institute of Certified Public Accountants is
considering a project that in part will address the accounting for major
maintenance activities. The project will address the use of the accrual,
deferral and expense methods of accounting for major maintenance activities.
Pending any change in current authoritative guidance, the Company may change its
current method of accounting for overhaul and well workover costs.
3. Dispositions
Subsequent to the contribution by MEHC to CE Generation of its interest
in the Company, the Company and CE Generation transferred its interests in
Visayas Geothermal Power Company and Minerals LLC (the "Excluded Subsidiaries")
to MEHC. This transfer was recorded as a distribution of the Excluded
Subsidiaries' net assets as follows (in thousands):
Visayas Minerals Other Total
Cash $ 234 $ --- $ 443 $ 677
Restricted cash 11,303 100,355 --- 111,658
Accounts receivable 22,352 10,253 12,139 44,744
Prepaid expenses 6,844 --- 5,215 12,059
Plant & equip. net 183,460 256,568 42,543 482,571
Goodwill --- 72,244 --- 72,244
Deferred financing 11,945 2,684 --- 14,629
Liabilities (3,780) --- (235,988) (239,768)
Due to related parties (5,112) (1,508) 142,286 135,666
Project financing (153,808) (140,520) --- (294,328)
Total $ 73,438 $ 300,076 $ (33,362) $ 340,152
<PAGE>
During the year ended December 31, 1999, 1998 and 1997, the Excluded
Subsidiaries revenues and net income included in Magma's income statement were
$7.3 million, $80.9 million and $42.3 million, respectively, and $2.4 million,
$17.0 million and $14.4 million, respectively.
4. Properties, Plants, Contracts and Equipment
Properties, plants, contracts and equipment comprise the following at
December 31 (in thousands):
1999 1998
Operating facilities:
Power plants $ 518,082 $ 768,155
Wells and resource development 151,996 137,399
Power sales agreements 264,371 264,371
Licenses and equipment 46,290 46,290
Total operating facilities 980,739 1,216,215
Less accumulated depreciation and amortization (282,586) (284,664)
Net operating facilities 698,153 931,551
Mineral reserves --- 240,114
Construction in progress:
Zinc Plant --- 22,351
Salton Sea Unit V 89,072 9,227
Turbo and Region 2 Brine Facilities 42,612 2,256
Other development 7,337 6,823
Total $ 837,174 $ 1,212,322
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:
PROJECT COMMERCIAL CAPACITY
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 (est.) 49 MW
CE Turbo 2000 (est.) 10 MW
Significant Customers and Contracts--All of the Company's sales of
electricity from the Imperial Valley Project, which comprise approximately 97%
and 74% of 1999 and 1998 electricity and steam revenues, respectively, 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, the Company could
incur an accounting loss equal to the entire receivable balance of $29.9 million
and $90.4 million at December 31, 1999 and 1998, respectively.
<PAGE>
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 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, 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, December 1998 and
December 1999 for each of the Vulcan, Del Ranch, Elmore and Leathers
Partnerships, respectively. The weighted average energy rate for all of the
Partnership Projects' SO4 agreements was 6.49 cents per kWh in 1999.
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
5.3 cents per kWh during 1999. 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 $1.1 million 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 for Salton Sea II and expired in February 1999 for Salton Sea III,
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 $3.3 million and $9.7 million, respectively.
<PAGE>
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, 1999 and 1998, Edison's average
Avoided Cost of Energy was 3.1 cents and 3.0 cents per kWh, respectively, which
is substantially below the contract energy prices earned for the year ended
December 31, 1999. 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 will likely
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 $1.46 per month per kilowatt of service provided for 1999 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, a wholly-owned subsidiary of
the Company.
Royalties--Royalty expense for the years ended December 31, 1999, 1998
and 1997, which is included in plant operations in the consolidated statements
of operations, comprise the following (in thousands):
1999 1998 1997
Vulcan $ 423 $ 363 $ 326
Leathers 3,361 2,811 2,694
Elmore 520 2,192 2,213
Del Ranch 856 2,870 2,650
Salton Sea I & II 827 810 1,206
Salton Sea III 1,673 1,637 2,439
Salton Sea IV 2,569 2,645 2,815
Total $ 10,229 $ 13,328 $ 14,343
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.
<PAGE>
The Salton Sea Project's weighted average royalty expense in 1999, 1998
and 1997 was approximately 6.2%, 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. 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 for their
own project or subsidiary debt. It should not be assumed that any asset of any
subsidiary of the Company 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 direct or indirect
interests in the Imperial Valley projects (other than Salton Sea Power Company)
or (2) owning interests in the Malitbog Project.
The Salton Sea Funding Corporation, a wholly owned subsidiary of the
Company, (the "Funding Corporation") debt securities are as follows (in
thousands):
SENIOR FINAL RATE DECEMBER 31,
SECURED MATURITY
SERIES DATE 1999 1998
July 21, 1995 A Notes May 30, 2000 6.69% $ 18,532 $ 48,436
July 21, 1995 B Bonds May 30, 2005 7.37 101,776 106,980
July 21, 1995 C Bonds May 30, 2010 7.84 109,250 109,250
June 20, 1996 D Notes May 30, 2000 7.02 1,500 12,150
June 20, 1996 E Bonds May 30, 2011 8.30 52,922 65,000
October 13, 1998 F Bonds November 30, 2018 7.475 285,000 285,000
$ 568,980 $ 626,816
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 has guaranteed 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 $140.5
million and associated interest.
<PAGE>
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
$67.6 million 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, 2000 and thereafter are as follows (in thousands):
2000 $ 25,032
2001 23,658
2002 28,572
2003 28,086
2004 30,588
Thereafter 433,044
$ 568,980
The Company's ability to obtain distributions from its investment in
the Salton Sea Projects and Partnership Projects is subject to the following
conditions:
* the depository accounts for the Salton Sea Notes and Bonds
must be fully funded;
* there cannot have occurred any default or event of default
under the Salton Sea Notes and Bonds;
* 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;
* there must be sufficient geothermal resources to operate the
Salton Sea projects at their required levels; and
* 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.
6. Related Party Transactions
On July 21, 1995, MEHC issued $200 million of 9 7/8% 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.
On January 29, 1999, MEHC commenced a cash offer for all 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 a extraordinary loss of approximately $17.5 million, net
of tax of $11.1 million.
<PAGE>
7. Income Taxes
Provision for income tax is comprised of the following at December 31
(in thousands):
1999 1998 1997
Current:
State $ 4,492 $ 13,443 $ 7,488
Federal 27,073 29,215 20,596
31,565 42,658 28,084
Deferred:
State 1,041 237 1,342
Federal (8,468) 15,748 15,207
Foreign --- 2,548 728
(7,427) 18,533 17,277
Total $ 24,138 $ 61,191 $ 45,361
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:
1999 1998 1997
Federal statutory rate 35.0% 35.0% 35.0%
Percentage depletion in excess of cost depletion (7.7) (3.8) (4.3)
Investment and energy tax credits (1.8) (1.3) (0.8)
State taxes, net of federal tax effect 5.0 4.8 4.7
Goodwill amortization 2.9 1.6 2.2
Tax effect of foreign income --- 0.5 0.6
33.4% 36.7% 37.4%
Deferred tax liabilities (assets) are comprised of the following at December 31
(in thousands):
1999 1998
Depreciation and amortization, net $ 163,937 $ 251,859
Unremitted foreign earnings --- 21,464
Other 116 91
164,053 273,414
Accruals not currently deductible for
tax purposes (8,529) (13,171)
Tax credits --- (7,023)
Other (1,910) (6,441)
(10,439) (26,635)
Net deferred taxes $ 153,614 $ 246,779
8. Fair Value of Financial Instruments
<PAGE>
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 Company is
unable to estimate a fair value for the Malitbog loan as there are no quoted
market prices available.
The carrying amounts in the table below are included in the
consolidated balance sheets under the indicated captions (in thousands).
1999 1998
CARRYING ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE FAIR
VALUE VALUE
Financial assets:
Note receivable from
related party $ 140,520 $ 128,815 $ - $ -
Financial liabilities:
Salton Sea notes and bonds 568,980 540,659 626,816 646,397
Note payable to related party --- --- 200,000 217,900
9. 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., an indirect wholly-owned subsidiary, is
constructing Salton Sea Unit V. The Salton Sea Unit V Project is a 49 net
megawatt geothermal power plant which will sell approximately one-third of its
net output to the zinc facility, which was retained by MEHC. 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 $119.1 million which is being funded by $76.3
million of debt from Salton Sea Funding Corporation and $42.8 million from
equity contributions.
CE Turbo LLC, an indirect wholly-owned subsidiary, 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 to mid 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 $63.7 million
which is being funded by $55.6 million of debt from Salton Sea Funding
Corporation and $8.1 million from equity contributions.
<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. (a wholly owned subsidiary of CE Generation, LLC) and
subsidiaries as of December 31, 1999 and 1998, and the related consolidated
statements of operations, changes in stockholder's equity and cash flows for
each of the three years in the period ended December 31, 1999. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
January 25, 2000
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A Wholly-Owned Subsidiary of CE Generation LLC)
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(Dollars in thousands except per share amounts)
<TABLE>
<CAPTION>
1999 1998
ASSETS
<S> <C> <C>
Cash and cash equivalents $ 11,525 $ 11,844
Restricted cash 6,776 5,917
Accounts receivable 6,278 7,100
Inventory and other assets 4,405 3,932
Deferred income taxes 1,333 2,188
Total current assets 30,317 30,981
Properties, plant, and contracts:
Land 358 358
Cogeneration facility 164,647 163,389
Furniture, fixtures and equipment 1,614 1,602
166,619 165,349
Accumulated depreciation and amortization (35,627) (25,046)
Properties, plants and contracts, net 130,992 140,303
Restricted cash 1,324 1,307
Excess of cost over fair value of net assets acquired, net 84,585 88,429
Investments in partnerships 118,637 125,036
Deferred charges and other assets 5,447 2,573
Total assets $ 371,302 $ 388,629
LIABILITIES AND STOCKHOLDER'S EQUITY
Liabilities:
Accounts payable $ 13 $ 366
Accrued liabilities 8,588 6,435
Current portion of long-term debt 16,088 14,268
Amounts due to affiliates, net 39,318 28,696
Total current liabilities 64,007 49,765
Deferred income taxes 79,763 79,183
Project financing debt 60,173 76,261
Other long-term liabilities --- 940
Total liabilities 203,943 206,149
Commitments and contingencies (Notes 4 and 5)
Stockholder's Equity:
Common stock, $.01 par value; 1,000,000 shares authorized,
1,192 shares issued and outstanding --- ---
Additional paid in capital 167,359 182,480
Retained earnings --- ---
Total stockholder's equity 167,359 182,480
Total liabilities and stockholder's equity $ 371,302 $ 388,629
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A Wholly-Owned Subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Dollars in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Revenues:
<S> <C> <C> <C>
Sales of electricity and steam $ 78,367 $ 80,375 $ 77,405
Equity earnings of partnerships 22,861 10,732 14,542
Interest and other income 4,314 3,694 4,325
Total revenues 105,542 94,801 96,272
Costs and Expenses:
Plant operations 36,872 37,765 39,388
Depreciation and amortization 15,158 17,033 15,841
Interest expense 9,729 11,854 12,995
Total costs and expenses 61,759 66,652 68,224
Income before income tax expense 43,783 28,149 28,048
Income tax expense 17,257 12,273 11,698
Net income $ 26,526 $ 15,876 $ 16,350
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A Wholly-Owned Subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Dollars in thousands)
<TABLE>
<CAPTION>
Common Stock Additional Retained
Paid-in Earnings Total
Shares Amount Capital
<S> <C> <C> <C> <C> <C>
BALANCE, January 1, 1997 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
Distribution --- --- (15,121) (26,526) (41,647)
Net income --- --- --- 26,526 26,526
BALANCE, December 31, 1999 1,192 $ --- $ 167,359 $ --- $ 167,359
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
(A Wholly-Owned Subsidiary of CE Generation LLC)
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE YEARS ENDED
DECEMBER 31, 1999
(Dollars in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $ 26,526 $ 15,876 $ 16,350
Adjustments to reconcile to cash flows from
operating activities:
Depreciation 11,314 13,211 13,149
Amortization of excess of cost over fair value
of net assets acquired 3,844 3,822 2,692
Provision for deferred income taxes (3,683) (14,246) (3,157)
Distribution from equity investments in excess
of equity earnings 6,399 6,171 9,418
Changes in other items:
Accounts receivable 822 766 (1,339)
Deferred charges and other assets (4,080) (1,000) (1,601)
Accounts payable and accrued liabilities 860 (4,720) 3,135
Net cash flows from operating activities 42,002 19,880 38,647
Cash flows from investing activities:
Capital expenditures (1,270) (212) (409)
Decrease (increase) in restricted cash (17) (997) 1,076
Net cash flows from investing activities (1,287) (1,209) 667
Cash flows from financing activities:
Repayments of debt (14,268) (12,805) (11,237)
Distribution to parent (44,648) (82,000) ---
Amounts due to/from affiliates 18,741 77,358 (26,708)
Decrease (increase) in restricted cash (859) 680 (97)
Net cash flows from financing activities (41,034) (16,767) (38,042)
Net increase (decrease) in cash and cash equivalents (319) 1,904 1,272
Cash and cash equivalents, beginning of year 11,844 9,940 8,668
Cash and cash equivalents, end of year $ 11,525 $ 11,844 $ 9,940
Supplemental disclosure:
Interest paid $ 9,582 $ 11,707 $ 12,995
Income taxes paid $ 6,543 $ 6,982 $ 1,237
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
FALCON SEABOARD RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
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"). On February 8, 1999, MidAmerican Energy
Holdings Company, the parent of FSRI ("MEHC") created a new subsidiary, CE
Generation L.L.C. ("CE Generation") and subsequently transferred its interest in
FSRI and other power generation assets to CE Generation. On March 3, 1999, MEHC
sold 50% of its interest in CE Generation to an affiliate of El Paso Energy
Corporation.
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 held general and limited partnership
interests in a 79.9 megawatt cogeneration facility which began operations in
December 1992. On December 2, 1999, Norcon transferred its interest in the
Norcon Project to General Electric Capital Corporation. 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, Ltd., 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. 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.
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.
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.
Inventories--Inventories consist of spare parts and supplies and are
valued at the lower of cost or market. Cost for large replacement parts is
determined using the specific identification method. For the remaining supplies,
cost is determined using the weighted average cost method.
Property, Plants, Contracts and Depreciation--Property, plants and
contracts are stated at the cost pushed down from MEHC 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:
<PAGE>
Furniture, fixtures and equipment 5 to 30 years
Cogeneration facility 6 to 30 years
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, based on discounted cash
flows or various models, whenever evidence exists that the carrying value is not
recoverable.
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, 1999 and 1998, accumulated
amortization of the excess of cost over fair value was $14.1 million and $10.2
million, respectively.
Investments--The Company's investments in Saranac and Norcon (see Note
3) 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, 1999 and 1998, the carrying amount of the Company's investment in
Saranac differs from its underlying equity in net assets of Saranac by $98.5
million (net of accumulated amortization of $35.1 million) and $108.8 million
(net of accumulated amortization of $24.8 million), 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 based on the Company's long-term scheduled major maintenance plans for
the Power Resources cogeneration facility and is included in accrued
liabilities. Other maintenance and repairs are charged to expense as incurred.
Income Taxes--The Company had historically been included in the
consolidated income tax returns of MEHC and as of March 3, 1999 is included in
the consolidated income tax return of CE Generation. The 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 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 Power
Resources term loan were capitalized and are being amortized using the straight
line method over the period the term loan is outstanding.
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.
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.
<PAGE>
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 the
Company beginning January 1, 2001. The Company is in the process of evaluating
the impact of this accounting pronouncement.
Pending Accounting Policy Change--The Accounting Standards Executive
Committee (AcSEC) of the American Institute of Certified Public Accountants is
considering a project that in part will address the accounting for major
maintenance activities. The project will address the use of the accrual,
deferral and expense methods of accounting for major maintenance activities.
Pending any change in current authoritative guidance, the Company may change its
current method of accounting for major maintenance costs.
3. Investment in Partnerships
The Company indirectly holds noncontrolling general and limited
partnership interests in Saranac Power Partners, L.P. ("Saranac"), which was
formed to build, own and operate a natural gas fired combined cycle cogeneration
facility. The lenders to the partnership have recourse only against these
facilities and the income and revenues therefrom. In 1999, the Company had an
approximate 49% economic interest in Saranac. Effective in January 2000, the
Company has an approximate 61% economic interest in the partnership as TPC
Saranac achieved an after tax return of 8.35%. The Company will have an
approximate 80% economic interest in the partnership after General Electric
Capital Company achieves an after tax return, as defined in the Partnership
Agreement, of approximately 7.252%.
The following is a summary of aggregated financial information for
Saranac as of and for the year ended December 31, 1999 and 1998 (in thousands):
1999 1998
Assets $ 289,152 $ 300,425
Liabilities 192,524 197,680
Revenue 164,965 138,574
Net income 55,163 38,041
Saranac has project financing through a 14 year note payable agreement
with a lender with a principal amount outstanding of $181.1 million at December
31, 1999. 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 occurred 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.
<PAGE>
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 GE Capital 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 GE Capital. GE 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.
There were no undistributed earnings in equity investments at December
31, 1999.
4. Project Financing Debt
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 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 million and $110 million, 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 $76.3 million and $90.5 million at December 31,
1999 and 1998, 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 $4.1 million and $9.9
million at December 31, 1999 and 1998, 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, became 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. Power Resources recorded additional interest expense of $617,000 and
$1,177,000 for the years ended December 31, 1999 and 1998, respectively, related
to amounts owed under the Compensation Agreement.
<PAGE>
Scheduled maturities of project financing debt for the year ending
December 31 are as follows (in thousands):
2000 $ 16,088
2001 18,119
2002 20,312
2003 21,742
Total $ 76,261
Under Power Resources' term loan agreement, certain covenants and debt
service coverage ratios must be met before cash distributions can be made to
FSOC. Power Resources was in compliance with these requirements at December
31,1999.
5. Commitments and Contingencies
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, the
Saranac Partnership 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 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 required
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 on 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.
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), the Saranac Partnership and Lockport Energy
Associates, L.P. ("Lockport") concerning the power purchase agreements that
NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that
the PSC and the FERC improperly implemented PURPA in authorizing the pricing
terms that NYSEG, the Saranac Partnership 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 the Saranac Partnership. The Saranac Partnership and
other parties have filed motions to dismiss and oral arguments on those motions
were heard on March 2, 1998 and again on March 3, 1999. The Saranac Partnership
believes that NYSEG's claims are without merit for the same reasons described in
the FERC's orders.
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, 1999, 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 (in thousands):
<PAGE>
2000 $ 23,308
2001 23,608
2002 24,285
2003 24,854
Total $ 96,055
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.
All of Power Resources' sales of electricity and steam are made to two
customers under long-term contracts which expire in 2003.
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 1999 are $3.2 million
per month and 3.7 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 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.
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 $5.8 million and $7.0 million at December 31, 1999 and 1998, respectively.
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%.
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
1999 total 2.4 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 7.0
cents per kWh in 1999, 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.
<PAGE>
6. Income Taxes
The components of income tax expense (benefit) for the year ended
December 31, 1999, 1998 and 1997 are as follows (in thousands):
1999 1998 1997
Current $ 20,940 $ 26,519 $ 14,855
Deferred (3,683) (14,246) (3,157)
Total income tax expense $ 17,257 $ 12,273 $ 11,698
At December 31, 1999 and 1998, temporary differences result primarily
from accruals, alternative minimum tax credit carryforwards and depreciation. At
December 31, 1999, and 1998, the Company had deferred tax assets and liabilities
as shown below (in thousands):
1999 1998
Deferred tax asset $ (1,333) $ (2,188)
Deferred tax liability 79,763 79,183
Net deferred tax liability $ 78,430 $ 76,995
7. Related Party Transactions
Amounts due from affiliates at December 31, 1999 and 1998, primarily
represent balances with CE Generation for cash management purposes. The due to
affiliates balance at December 31, 1998 includes $3.0 million in unpaid
distributions to CE Generation.
FPOC has contracted with Saranac to provide operations and maintenance
("O&M") services to the cogeneration facility and pipeline. The Saranac O&M
agreement for the cogeneration facility expires January 1, 2009, and July 1,
2010. 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.
The due from and due to affiliate balances in the Company's financial
statements are the result of CE Generation's central cash management policy. CE
Generation'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 CE Generation and
FSRI.
8. 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.
<PAGE>
The carrying amounts in the table below are included in the
consolidated balance sheets under the indicated captions (in thousands):
1999 1998
CARRYING ESTIMATED CARRYING ESTIMATED
VALUE FAIR VALUE FAIR
VALUE VALUE
Financial Liabilities:
Project loan $ 76,261 $ 76,261 $ 90,529 $ 90,529
Interest rate swap --- 4,082 --- 9,904
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Saranac Power Partners, L.P.
We have audited the accompanying consolidated balance sheets of Saranac Power
Partners, L.P. and subsidiary, as of December 31, 1999 and 1998, and the related
consolidated statements of operations, partners' capital and cash flows for each
of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Partnership's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits 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 Saranac Power Partners, L.P. and
subsidiary at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Omaha, Nebraska
January 25, 2000
<PAGE>
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(Amounts in Thousands)
<TABLE>
<CAPTION>
1999 1998
ASSETS
<S> <C> <C>
Cash and cash equivalents $ 2,559 $ 1,169
Restricted cash 6,969 7,037
Accounts receivable 15,099 15,759
Inventory 5,319 5,853
Prepaid expenses 1,139 1,139
Total current assets 31,085 30,957
Property and equipment:
Land 858 858
Cogeneration facility 300,226 300,133
Pipeline 18,638 18,621
Furniture, fixtures and equipment 1,298 1,101
Total 321,020 320,713
Accumulated depreciation (70,430) (57,728)
Property and equipment, net 250,590 262,985
Restricted cash 7,478 6,483
Total assets $ 289,153 $ 300,425
LIABILITIES AND PARTNERS' CAPITAL
Liabilities:
Accounts payable $ 8 $ 156
Accrued liabilities 6,845 7,817
Amounts due to affiliates, net 2,234 40
Current portion of long term debt 11,050 8,185
Total current liabilities 20,137 16,198
Other long term liabilities 2,340 385
Notes payable 170,047 181,097
Total liabilities 192,524 197,680
Commitments and contingencies (Notes 3, 4, 5 and 6)
Partners' capital 96,629 102,745
Total liabilities and partners' capital $ 289,153 $ 300,425
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
1999 1998 1997
Revenues:
Sales of electricity $ 160,825 $ 135,046 $ 143,600
Sales of steam 2,853 2,433 2,166
Transportation revenue 244 220 283
Interest income 1,043 874 904
Total revenues 164,965 138,573 146,953
Costs and expenses:
Fuel 63,254 54,970 57,053
Operations and maintenance 17,758 16,106 16,807
Depreciation 12,702 12,923 12,887
Interest expense 16,088 16,534 16,800
Total costs and expenses 109,802 100,533 103,547
Net income $ 55,163 $ 38,040 $ 43,406
The accompanying notes are an integral part of these financial statements.
<PAGE>
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY
STATEMENTS OF PARTNERS' CAPITAL
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
TOTAL
Balance at January 1, 1997 $ 112,036
Distributions (50,572)
Net Income 43,406
Balance at December 31, 1997 104,870
Distributions (40,165)
Net Income 38,040
Balance at December 31, 1998 102,745
Distributions (61,279)
Net income 55,163
Balance at December 31, 1999 $ 96,629
The accompanying notes are an integral part of these financial statements.
<PAGE>
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
(Amounts in Thousands)
<TABLE>
<CAPTION>
1999 1998 1997
Cash flows from operating activities:
<S> <C> <C> <C>
Net income $ 55,163 $ 38,040 $ 43,406
Adjustments to reconcile to net cash flow
from operating activities:
Depreciation 12,702 12,923 12,887
Changes in other items:
Accounts receivable 660 (1,822) (491)
Inventory 534 1,057 (2,690)
Prepaid expenses - (26) 33
Accounts payable and accrued liabilities 835 (2,989) 2,318
Net cash flows from operating activities 69,894 47,183 55,463
Cash flows from investing activities:
Capital expenditures (307) (802) (92)
Decrease (increase) in restricted cash (995) (70) 759
Net cash flows from investing activities (1,302) (872) 667
Cash flows from financing activities:
Repayment of note payable (8,174) (6,139) (4,911)
Distributions to partners (61,279) (40,165) (50,572)
Decrease (increase) in restricted cash 68 (814) (300)
Amounts due to affiliates, net 2,183 (447) 238
Net cash flows from financing activities (67,202) (47,565) (55,545)
Net increase (decrease) in cash and
cash equivalents 1,390 (1,254) 585
Cash and cash equivalents, beginning of year 1,169 2,423 1,837
Cash and cash equivalents, end of year $ 2,559 $ 1,169 $ 2,422
Supplemental disclosures:
Cash paid for interest $ 16,156 $ 16,179 $ 16,635
</TABLE>
The accompanying notes are an integral part of these financial statements.
<PAGE>
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999
1. BUSINESS
Saranac Power Partners, L.P. (the "Partnership") was formed on May 11,
1992 to construct, own and operate a natural gas-fired cogeneration facility in
Plattsburgh, New York (the "Facility") and to construct, own and operate a gas
pipeline (the "Pipeline") to transport fuel to the Facility through a wholly
owned subsidiary of the Partnership, North Country Gas Pipeline Corporation
("North Country"). The Partnership and North Country began commercial operations
on June 21, 1994 and January 1, 1994, respectively.
The Partnership consists of one general partner, Saranac Energy
Company, Inc. ("SECI"), an indirect wholly owned subsidiary of Falcon Seaboard
Resources, Inc. ("FSRI"), and four limited partners: General Electric Capital
Corporation ("GECC"), SECI, TPC Saranac Partner One, Inc. ("TP1") and TPC
Saranac Partner Two, Inc. ("TP2"); both TP1 and TP2 are wholly owned
subsidiaries of Tomen Power Corporation ("Tomen").
Net income and distributions from the Partnership are allocated to the
various partners based on allocation percentages that vary throughout the life
of the Partnership, as specified in the Partnership Agreement. These allocation
percentages will differ from the stated ownership percentages until certain
returns, as defined in the Partnership Agreement, are achieved.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation - The accompanying consolidated financial
statements include the operations and accounts of the Partnership and North
Country. All significant intercompany transactions and balances have been
eliminated in consolidation.
Revenue Recognition - Revenues are recognized for output delivered or
services provided at rates specified in the related contracts.
Cash Equivalents - Cash equivalents represent short-term, highly liquid
investments with original maturities of less than three months. Restricted cash
is not considered a cash equivalent.
Restricted Cash - Restricted cash represents amounts for major
maintenance expenditures, the debt protection reserve account and remaining
amounts which were to be used for the completion of the Facility. Excess funds
remaining in the completion account will be paid to FSRI as additional
development fees. 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.
Inventory - Inventory, consisting primarily of replacement parts, is
valued on an average cost basis and stated at the lower of cost or market value.
Property, Equipment and Depreciation - Property and equipment are
stated at cost. Depreciation expense is computed using the straight line method
of accounting over the following useful lives:
Cogeneration facility 25 years
Pipeline 30 years
Furniture, fixtures and equipment 5 years
The Partnership reviews long-lived assets for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. An impairment loss would be recognized based on
discounted cash flows or various models, whenever evidence exists that the
carrying value is not recoverable.
<PAGE>
Income Taxes - There is no provision for income taxes since those taxes are
the responsibility of the partners.
Allocation of Income to Partners - Income before depreciation is
allocated in the same proportion as cash distributions. Depreciation is
allocated in accordance with stated percentages in the Partnership Agreement
based on relative capital contributions.
Maintenance and Repair Reserve - A maintenance and repair reserve is
recorded based on the Facility's long-term, scheduled major maintenance plans
for the cogeneration facility and is included in accrued liabilities. Other
maintenance and repairs are charged to expense as incurred.
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 Partnership utilizes swap agreements to
manage market risks and reduce its exposure 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
Partnership'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. 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 the Partnership beginning January 1, 2001. The Partnership is in
the process of evaluating the impact of this accounting pronouncement.
Pending Accounting Policy Change - The Accounting Standards Executive
Committee (AcSEC) of the American Institute of Certified Public Accountants is
considering a project that in part will address the accounting for major
maintenance activities. The project will address the use of the accrual,
deferral and expense methods of accounting for major maintenance activities.
Pending any change in current authoritative guidance, the Partnership may change
its current method of accounting for major maintenance costs.
3. SIGNIFICANT CONTRACTS
Sales of electricity and steam are made under long-term contracts to
two customers. The steam contract includes stipulated volumes and prices over a
15-year term expiring in October 2009.
The contract for the sale of electricity (the "Contract") covers a
15-year term from the date of commercial operation and provides for the sale of
the Facility's estimated annual electric energy production of 1,971,000 megawatt
hours to a New York state utility (the "Utility"). The Contract specified two
pricing periods during its term. The first period, which began on the date of
commencement of commercial operation and ended December 31, 1995, had a fixed
price per kilowatt-hour for electricity delivered. To the extent the Facility
delivered proportionately more electricity during non-peak periods than peak
periods, that excess electricity is priced at the Utility's tariff short-run
avoided cost. The second pricing period, which began January 1, 1996 and ends 15
years after the commencement of commercial operation, has a price based upon a
discount to the Utility's 1988 estimate of long-run avoided costs.
<PAGE>
During 1994, the Partnership and the Utility amended the Contract to
grant, among other things, the Utility the right to reduce the output of the
Facility by up to 200,000 megawatt-hours per year. In return, among other
things, the Utility is required to compensate the Partnership for its fixed
costs during those periods of reduced production. The Utility reduced the output
of the Facility by approximately 113,000, 122,000 and 157,000 Megawatt hours in
1999, 1998 and 1997, respectively.
The Contract requires payment by the Partnership in certain events of
termination by either party of the excess of amounts paid for electricity and
the Utility's 1988 estimate of avoided cost. At December 31, 1999, actual
payments received for electricity to date plus projected 2000 payments were less
than the Utility's 1988 estimate of avoided costs.
The Facility is a qualifying facility under the Public Utility
Regulatory Policy Act of 1978 ("PURPA") and its contract for the sale of
electricity is subject to the 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 a 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.
The Partnership has contracted to purchase natural gas for its
cogeneration facility for delivery through North Country's pipeline 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%. Minimum
expected payments under the contract are as follows (in thousands):
2000 $ 56,491
2001 58,592
2002 60,935
2003 63,373
2004 66,088
Thereafter 344,090
Total $ 649,569
North Country has also contracted to transport gas through its pipeline
to the Utility and the steam purchaser discussed above for a period of 15 years.
4. NOTE PAYABLE
In October 1994, the Partnership signed a 14-year note payable
agreement with a lender for an initial principal amount of $204.6 million. Under
the terms of the note payable agreement, interest rate alternatives include an
option to use a Eurodollar rate or the lender's base rate. Each option includes
an interest margin in addition to the applicable rate selected. The selected
interest rate plus interest margin at December 31, 1999, 1998 and 1997 was
6.5088%, 6.1875% and 6.5625%, respectively.
Effective October 7, 1994, the Partnership entered into an interest
rate swap agreement with the lender as a means of hedging floating interest rate
exposure related to its 14-year note payable. The swap agreement was an initial
notional amount of $204.6 million and effectively fixes the interest rate at
8.185%, which will increase to 8.31% in October 2001 and 8.56% in October 2005.
During 1999, 1998 and 1997, the Partnership paid $3.6 million, $3.0 million and
$2.9 million, respectively, related to this agreement which was included in
interest expense. The Partnership is exposed to credit loss in the event of
nonperformance by the lender under the interest rate swap agreement. However,
the Partnership does not anticipate nonperformance by the lender. The estimated
cost to terminate the interest rate swap agreements, based on termination values
obtained from the lender, was $4.5 million, $17.5 million and $12.3 million at
December 31, 1999, 1998 and 1997, respectively.
<PAGE>
Maturities of the note payable at December 31, 1999 are as follows (in
thousands):
2000 $ 11,050
2001 13,096
2002 15,552
2003 18,826
2004 22,100
Thereafter 100,484
Total $ 181,108
The note agreements are collateralized by all of the Partnership's
assets. The Partnership is restricted by the terms of the note payable agreement
from making distributions or withdrawing any capital accounts without the
consent of the lender. Under the terms of the note payable agreement,
distributions may be made to the partners in accordance with the terms of the
Partnership Agreement. The note payable agreement also requires the Partnership
to maintain certain covenants. The Partnership was in compliance with these
requirements at December 31, 1999.
The Partnership has issued an irrevocable letter of credit to its gas
supplier in the amount of $13 million. The Partnership has approximately $7.5
million available in additional unissued letters of credit. Annual fees related
to these letters of credit are calculated as 1.75% of the issued balance and
0.5% of the unissued balance.
5. COMMITMENTS AND CONTINGENCIES
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, the
Saranac Partnership 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 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 required
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 on 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.
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), the Saranac Partnership and Lockport Energy
Associates, L.P. ("Lockport") concerning the power purchase agreements that
NYSEG entered into with Saranac Partners and Lockport. NYSEG's suit asserts that
the PSC and the FERC improperly implemented PURPA in authorizing the pricing
terms that NYSEG, the Saranac Partnership 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 the Saranac Partnership. The Saranac Partnership and
other parties have filed motions to dismiss and oral arguments on those motions
were heard on March 2, 1998 and again on March 3, 1999. The Saranac Partnership
believes that NYSEG's claims are without merit for the same reasons described in
the FERC's orders.
<PAGE>
6. RELATED PARTIES
The Partnership has contracted with an affiliated company to provide
operating and maintenance services (the "O&M Contract") for a 16-year period
expiring in June 2010. This O&M Contract provides for a management fee of
$137,500 per month which is adjusted annually, based on a published U.S.
government index. The affiliate is also reimbursed for any direct costs
incurred. During 1999, 1998 and 1997, the Partnership incurred costs of $1.6
million, $1.7 million and $2.7 million, respectively, related to this agreement.
Additionally, the O&M Contract provides for certain performance bonuses
or penalties. During 1999, 1998 and 1997, the affiliate earned approximately
$851, $0 and $815, respectively as performance bonuses.
7. 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 Partnership could realize in a current transaction.
The note payable 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 (in thousands):
1999 1998
Estimated Estimated
Carrying Fair Carrying Fair
Value Value Value Value
Financial Liabilities:
Note Payable 181,108 181,108 189,282 189,282
Interest Rate Swap --- 4,487 --- 17,506
<PAGE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
Not applicable
<PAGE>
Part III
Item 10. Directors and Executive Officers
EXECUTIVE OFFICER POSITION
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
Joseph M. Lillo Vice President and Controller
Patrick J. Goodman Director
Larry Kellerman Director
John L. Harrison Director
Steven M. Pike Director
ROBERT S. SILBERMAN, 43, President and Chief Operating Officer of CE
Generation 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, 37, Vice President and Treasurer of MidAmerican, CE
Generation 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, 42, Vice President and General Counsel of
CalEnergy Generation, CE Generation 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 CE
Generation and Director of Operations for El Paso Energy International. Mr.
Johnston joined El Paso Energy in 1997 and was assigned to the CE Generation
management team at its 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.
<PAGE>
JOSEPH M. LILLO, 30, Vice President and Controller of CE Generation and
each assigning subsidiary. Mr. Lillo joined MidAmerican in November 1996, and
served as manager of Financial Reporting and was promoted to Controller/IPP in
March 1998. Mr. Lillo was promoted to Vice President and Controller in July
1999. Prior to joining MidAmerican, Mr. Lillo was a senior associate with
Coopers & Lybrand LLP.
PATRICK J. GOODMAN, 33, Senior Vice President and Chief Financial
Officer of MidAmerican and a director of CE Generation 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. Mr. Goodman was promoted to Chief Financial Officer in April 1999.
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.
LARRY KELLERMAN, 44, President of El Paso Power Services Company and a
director of CE Generation. 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 CE Generation. 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 CE Generation. 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.
The directors and executive officers do not receive any compensation
for serving in these positions.
<PAGE>
Item 11. Executive Compensation
CE Generation's directors and executive officers receive no remuneration
for serving in such capacities.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Fifty percent of CE Generation's interests are owned by MidAmerican and the
other 50% are owned by El Paso Power. There is no public trading market for CE
Generation's membership interests. None of the directors or executive officers
beneficially own any of the equity interests. MidAmerican's common stock is not
publicly traded. 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.
Item 13. Certain Relationships and Related Transactions
Relationship with MidAmerican and El Paso Energy Corporation
CE Generation is 50% owned by MidAmerican and 50% owned by El Paso Power.
CE Generation's 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. CE Generation 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 CE Generation's
interests, MidAmerican entered into an administrative services agreement with CE
Generation and El Paso Power entered into a power marketing services agreement
and a fuel management services agreement with CE Generation. MidAmerican and El
Paso Power are reimbursed 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.
<PAGE>
PART IV
Item 14. Exhibits, Financial Statements Schedule and Reports on Form 8-K
(a) Financial Statements and Schedules
(i) Financial Statements
Financial Statements are included in Part II of this Form 10-K
(ii) Financial Statement Schedules
Financial Statement Schedules are not included because they are
not required or the information required is included in Part II of
this Form 10-K.
(b) Reports on Form 8-K
Not applicable.
(c) Exhibits
The exhibits listed on the accompanying Exhibit Index are filed as part
of this Annual Report.
(d) Financial statements required by Regulations S-X, which are excluded
from the Annual Report by Rule 14a-3(b).
Not Applicable
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized, in the City of Omaha, State
of Nebraska, on this 6th day of April, 2000.
CE Generation LLC
/s/ Robert S. Silberman*
By: Robert S. Silberman
Director, President and Chief Operating Officer
* By: /s/ Douglas L. Anderson
Douglas L. Anderson
Attorney-in-Fact
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Date
/s/ Robert S. Silberman* April 6, 2000
Director, President and
Chief Operating Officer
(Principal Executive Officer)
/s/ Douglas L. Anderson* April 6, 2000
Director
/s/ Richard P. Johnston* April 6, 2000
Vice President and
Commercial Officer
/s/ Joseph M. Lillo* April 6, 2000
Vice President and Controller
(Principal Accounting Officer)
/s/ Patrick J. Goodman* April 6, 2000
Director
/s/ Larry Kellerman* April 6, 2000
Director
/s/ John L. Harrison* April 6, 2000
Director
/s/ Steven M. Pike* April 6, 2000
Director
* By: /s/ Douglas L. Anderson
Attorney-in-Fact
<PAGE>
EXHIBIT INDEX
3.1 Certificate of Formation of CE Generation, LLC
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4).
3.2 Limited Liability Company Operating Agreement
of CE Generation, LLC (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4).
4.1 Indenture, dated as of March 2, 1999, by and between CE
Generation, LLC and Chase Manhattan Bank and Trust Company,
National Association (incorporated by reference to Exhibit 4.1
to the Company's Registration Statement on Form S-4).
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 (incorporated by
reference to Exhibit 4.2 to the Company's Registration
Statement on Form S-4).
4.3 Purchase Agreement, dated February 24, 1999, by and among CE
Generation, LLC, Credit Suisse First Boston Corporation and
Lehman Brothers, Inc. (incorporated by reference to Exhibit
4.3 to the Company's Registration Statement on Form S-4).
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. (incorporated by
reference to Exhibit 4.4 to the Company's Registration
Statement on Form S-4).
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 (incorporated by reference to Exhibit
4.5 to the Company's Registration Statement on Form S-4).
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
(incorporated by reference to Exhibit 4.6 to the Company's
Registration Statement on Form S-4).
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 (incorporated by reference to
Exhibit 4.7 to the Company's Registration Statement on Form
S-4).
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 (incorporated by
reference to Exhibit 4.8 to the Company's Registration
Statement on Form S-4).
<PAGE>
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
(incorporated by reference to Exhibit 4.9 to the Company's
Registration Statement on Form S-4).
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
(incorporated by reference to Exhibit 4.10 to the Company's
Registration Statement on Form S-4).
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 (incorporated by reference to Exhibit 4.11 to
the Company's Registration Statement on Form S-4).
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 (incorporated by reference to
Exhibit 4.12 to the Company's Registration Statement on Form
S-4).
24.0 Power of Attorney
27.0 Financial Data Schedule
Exhibit 24
POWER OF ATTORNEY
The undersigned, a member of the Board of Directors and/or as Officer
of CE GENERATION, LLC, a corporation registered in the State of Delaware (the
"Company"), hereby constitutes and appoints Steven A. McArthur and Douglas L.
Anderson and each of them, as his/her true and lawful attorney-in-fact and
agent, with full power of substitution and resubstitution, for and in his/her
stead, in any and all capacities, to sign on his/her behalf the Company's Form
10-K Annual Report for the fiscal year ending December 31, 1999 and to execute
any amendments thereto and to file the same, with all exhibits thereto, and all
other documents in connection therewith, with the United States Securities and
Exchange Commission and applicable stock exchanges, with the full power and
authority to do and perform each and every act and thing necessary or advisable
to all intents and purposes as he might or could do in person, hereby ratifying
and confirming all that said attorney-in-fact and agent or his/her substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
Dated as of March 30, 2000
/s/ Robert S. Silberman /s/ Joseph M. Lillo
Robert S. Silberman Joseph M. Lillo
/s/ Patrick J. Goodman /s/ Larry Kellerman
Patrick J. Goodman Larry Kellerman
/s/ Richard P. Johnston /s/ Steven M. Pike
Richard P. Johnston Steven M. Pike
/s/ John L. Harrison
John L. Harrison
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> USD
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-1-1999
<PERIOD-END> DEC-31-1999
<EXCHANGE-RATE> 1
<CASH> 35,896
<SECURITIES> 0
<RECEIVABLES> 40,688
<ALLOWANCES> 0
<INVENTORY> 19,734
<CURRENT-ASSETS> 119,829
<PP&E> 1,343,384
<DEPRECIATION> (326,042)
<TOTAL-ASSETS> 1,725,411
<CURRENT-LIABILITIES> 92,834
<BONDS> 1,045,241
0
0
<COMMON> 0
<OTHER-SE> 392,280
<TOTAL-LIABILITY-AND-EQUITY> 1,725,411
<SALES> 0
<TOTAL-REVENUES> 340,683
<CGS> 0
<TOTAL-COSTS> 112,801
<OTHER-EXPENSES> 62,463
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 72,537
<INCOME-PRETAX> 92,882
<INCOME-TAX> 30,912
<INCOME-CONTINUING> 61,970
<DISCONTINUED> 0
<EXTRAORDINARY> (17,478)
<CHANGES> 44,492
<NET-INCOME> 0
<EPS-BASIC> 0
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</TABLE>
