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.
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.
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.
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.
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.
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
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%
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.
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.
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.
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.
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.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
Part II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder's Matters
Not applicable.
Item 6.
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.
(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.
Item 7.
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.
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.
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.
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,
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.
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.
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.
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.
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.
Item 8.
Item 8. Financial Statements and Supplementary Data
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
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
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
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.
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.
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.
CE GENERATION, LLC AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE YEARS ENDED DECEMBER 31, 1999 (Amounts in Thousands)
The accompanying notes are an integral part of these financial statements.
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
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.
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.
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
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.
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.
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.
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.
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.
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
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.
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.
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
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.
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.
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
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.
The carrying amounts in the table below are included in the consolidated balance sheets under the indicated captions (in thousands):
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.
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
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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.
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.
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
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.
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.
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.
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.
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.
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
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.
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
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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)
The accompanying notes are an integral part of these financial statements.
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:
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.
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.
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.
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):
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.
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.
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
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
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1999 AND 1998 (Amounts in Thousands)
The accompanying notes are an integral part of these financial statements.
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.
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.
SARANAC POWER PARTNERS, L.P. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE YEARS ENDED DECEMBER 31, 1999 (Amounts in Thousands)
The accompanying notes are an integral part of these financial statements.
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.
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.
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.
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.
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
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable
Part III
Item 10.
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.
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.
Item 11.
Item 11. Executive Compensation
CE Generation's directors and executive officers receive no remuneration for serving in such capacities.
Item 12.
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.
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.
PART IV
Item 14.
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
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
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).
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