SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
CURRENT REPORT
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THEE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2002
Commission File Number 33-82034
INDIANTOWN COGENERATION, L.P.
(Exact name of co-registrant as specified in its charter)
Delaware 52-1722490
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
INDIANTOWN COGENERATION FUNDING CORPORATION
(Exact name of co-registrant as specified in its charter)
Delaware 52-1889595
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
7600 Wisconsin Avenue
(Mailing Address: 7500 Old Georgetown Road, 13th Floor
Bethesda, Maryland 20814-6161)
(Registrants' Address of principal executive offices)
(301)-718-6800
(Registrants' telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [ X ] Yes [ ] No
Indicate by check mark if disclosure of delinquent filer pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2) [ ] Yes [ X ] No
As of March 31, 2003, there were 100 shares of common stock of Indiantown Cogeneration Funding Corporation, $1 par value outstanding.
Indiantown Cogeneration, L.P.
Indiantown Cogeneration Funding Corporation
Table of Contents
PART I Page Number
------ -----------
Item 1 Business....................................................... 1
Item 2 Properties..................................................... 7
Item 3 Legal Proceedings.............................................. 7
Item 4 Submission of Matters to a Vote
of Security Holders............................................ 8
PART II
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Item 5 Market for the Registrant's Common Equity
and Related Security Holder Matters............................ 9
Item 6 Selected Financial Data........................................ 9
Item 7 Management's Discussion and Analysis of
Financial Condition and Results of Operations.................. 10
Item 7A Quantitative and Qualitative Disclosures About
Market Risk.................................................... 21
Item 8 Financial Statements and Supplementary Data................... 22
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure........................ 43
PART III
--------
Item 10 Directors and Executive Officers............................... 44
Item 11 Remuneration of Directors and Officers......................... 45
Item 12 Security Ownership of Certain Beneficial Owners
and Management................................................. 45
Item 13 Certain Relationships and Related Transactions................. 46
Item 14 Controls and Procedures........................................ 46
PART IV
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Item 15 Exhibits, Financial Statement Schedules and
Reports on Form 8-K............................................ 47
Signatures and Certifications.................................. 51
Item 1 BUSINESS
The Partnership
Indiantown Cogeneration, L.P. (the "Partnership") is a special purpose Delaware limited partnership formed on October 4, 1991. The Partnership was formed to develop, construct, own and operate an approximately 330 megawatt (net) pulverized coal-fired cogeneration facility (the "Facility") located on an approximately 240 acre site in southwestern Martin County, Florida. The Facility produces electricity for sale to Florida Power & Light Company ("FPL") and supplies steam to Louis Dreyfus Citrus, Inc. ("LDC"), formerly known as Caulkins Indiantown Citrus Company.
The original general partners were Toyan Enterprises ("Toyan"), a California corporation and a wholly owned special purpose indirect subsidiary of PG&E National Energy Group, Inc. ("NEG, Inc."), and Palm Power Corporation ("Palm"), a Delaware corporation and a special purpose indirect subsidiary of Bechtel Enterprises, Inc. ("Bechtel Enterprises"). The sole limited partner was TIFD III-Y, Inc. ("TIFD"), a special purpose indirect subsidiary of General Electric Capital Corporation ("GECC"). During 1994, the Partnership formed its sole, wholly owned subsidiary, Indiantown Cogeneration Funding Corporation ("ICL Funding"), to act as agent for, and co-issuer with, the Partnership in accordance with the 1994 bond offering of $505,000,000 of First Mortgage Bonds. ICL Funding has no separate operations and has only $100 in assets.
In 1998, Toyan consummated transactions with DCC Project Finance Twelve, Inc. ("PFT"), whereby PFT, through a new partnership (Indiantown Project Investment, L.P. ("IPILP") with Toyan, became a new general partner in the Partnership. Toyan is the sole general partner of IPILP. Prior to the PFT transaction, Toyan converted some of its general partnership interest into a limited partnership interest such that Toyan now directly holds only a limited partnership interest in the Partnership. In addition, Bechtel Generating Company, Inc. ("Bechtel Generating"), sold all of the stock of Palm to a wholly owned indirect subsidiary of Cogentrix Energy, Inc. ("Cogentrix"). Palm holds a 10% general partner interest in the Partnership.
On June 4, 1999, Thaleia, LLC ("Thaleia"), a wholly-owned subsidiary of Palm and indirect wholly-owned subsidiary of Cogentrix, acquired from TIFD a 19.9% limited partner interest in the Partnership. On September 20, 1999, Thaleia acquired another 20.0% limited partnership interest from TIFD and TIFD's membership on the Board of Control. On November 24, 1999, Thaleia purchased TIFD's remaining limited partner interest in the Partnership from TIFD.
The net profits and losses of the Partnership are allocated to Toyan, Palm, IPILP and Thaleia (collectively, the "Partners") based on the following ownership percentages:
Toyan 30.05%
Palm 10.00%
IPILP 19.95%
Thaleia 40.00%
1 The changes in ownership were the subject of notices of self-recertification of Qualifying Facility status filed by the Partnership with the Federal Energy Regulatory Commission on August 21, 1998, November 16, 1998, June 4, 1999, September 21, 1999, and November 24, 1999.
All distributions other than liquidating distributions will be made based on the Partners' percentage interest as shown above, in accordance with the project documents and at such times and in such amounts as the Board of Control of the Partnership determines.
The Partnership is managed by PG&E National Energy Group Company ("NEG"), formerly known as PG&E Generating Company, pursuant to a Management Services Agreement (the "MSA"). The Facility is operated by PG&E Operating Services Company ("PG&E OSC"), formerly known as U.S. Operating Services Company, pursuant to an Operation and Maintenance Agreement (the "O&M Agreement"). NEG and PG&E OSC are general partnerships indirectly wholly owned by NEG, Inc., an indirect wholly owned subsidiary of PG&E Corporation. Refer to Note 7 in the attached Notes to the Financial Statements for discussion of contractual terms.
The Partnership began construction of the Facility in October 1992 and was in the development phase through the commencement of commercial operation. The Facility commenced commercial operation under its power purchase agreement (the "Power Purchase Agreement" or "PPA") with FPL on December 22, 1995. The Facility synchronized with the FPL system on June 30, 1995 and the Partnership sold to FPL electricity produced by the Facility during startup and testing. The Partnership's continued existence is dependent on the ability of the Partnership to maintain successful commercial operation under the Power Purchase Agreement. Management of the Partnership is of the opinion that the assets of the Partnership are realizable at their current carrying value. The Partnership has no assets other than the Facility, the Facility site, contractual arrangements relating to the Facility (the "Project Contracts") and the stock of ICL Funding.
Relationship with PG&E Corporation and NEG, Inc.
In December 2000, and in January and February 2001, PG&E Corporation and NEG, Inc. completed a corporate restructuring of NEG, Inc. that involved the use or creation of limited liability companies ("LLCs") as intermediate owners between a parent company and its subsidiaries. One of these LLCs is PG&E National Energy Group, LLC, which owns 100% of the stock of NEG, Inc.
On April 6, 2001, Pacific Gas and Electric Company (the "Utility"), another subsidiary of PG&E Corporation, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The Utility and PG&E Corporation jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The proposed plan of reorganization does not directly affect NEG, Inc. or any of its subsidiaries. NEG Inc.'s management believes that NEG, Inc. and its direct and indirect subsidiaries as described above, including the Partnership, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.
2
As result of the sustained downturn in the power industry, NEG, Inc. and certain of its consolidated affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade NEG, Inc. and certain of its consolidated affiliates' credit ratings to below investment grade. The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership.
On October 8, 2002, Moody's stated that in conjunction with the downgrade of NEG, Inc. it had placed the Partnership's debt under review for possible downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG, Inc. would not have an effect on the rating of the Partnership's debt at this time. S&P's rating of the Partnership's debt is "BBB-". On November 5, 2002, Moody's issued an opinion update changing the rating outlook of the Partnership's debt to "under review for possible downgrade" from "negative outlook". Moody's rating of the Partnership's debt is "Baa3". On December 12, 2002, Fitch Ratings removed the "Rating Watch Negative" from it's "BBB-" rating on the Partnership's debt for the satisfactory completion of the permanent generator repairs during the 2002 scheduled fall outage. There are no minimum credit rating requirements in the Partnership's financing agreements.
NEG, Inc. and certain affiliates, excluding Toyan and IPILP, are currently in default under various debt agreements and guaranteed equity commitments. NEG, Inc., its subsidiaries and their lenders are engaged in discussions to restructure NEG, Inc.'s debt obligations and such other commitments. The Partnership is not a party to such debt agreements and guaranteed equity commitments or participants in such discussions. NEG, Inc. and its subsidiaries are continuing to review opportunities to abandon, sell, or transfer certain assets, and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise.
If the lenders exercise their default remedies or if the financial commitments are not restructured, NEG, Inc. and the affected affiliates may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code.
NEG, Inc. owns an indirect interest in the Partnership, and through its wholly owned subsidiaries NEG and PG&EOSC manages and operates the Project. The Partnership cannot be certain that an insolvency or bankruptcy involving NEG, Inc. or any of its subsidiaries would not affect NEG Inc.'s ownership arrangement with respect to the Partnership or the ability of NEG and PG&EOSC to manage and operate the Project.
Certain Project Contracts
Power Purchase Agreement
The Facility supplies (i) electric generating capacity and energy to FPL pursuant to the Power Purchase Agreement and (ii) steam to LDC pursuant to a long-term energy services agreement (the "Energy Services Agreement").
Payments from FPL pursuant to the Power Purchase Agreement provided approximately 99.7%, 99.8% and 99.9% of Partnership revenues for 2002, 2001 and 2000, respectively. Under and subject to the terms of the Power Purchase Agreement, FPL is obligated to purchase electric generating capacity made available to it and associated energy from the Facility through December 22, 2025.
3
Payments by FPL consist of capacity payments and energy payments. FPL is required to make capacity payments to the Partnership on a monthly basis for electric generating capacity made available to FPL during the preceding month regardless of the amount of electric energy actually purchased. This basis is known as the Capacity Billing Factor, which measures the overall availability of the Facility, but gives a heavier weighting to on-peak availability. The capacity payments have two components, an un-escalated fixed capacity payment and an escalated fixed operation and maintenance payment, which together are expected by the Partnership to cover all of the Partnership's fixed costs, including debt service. Energy payments are made only for the amount of electric energy actually delivered to FPL. The energy payments to be made by FPL in the next year are not expected to be sufficient to cover the Partnership's variable costs of electric energy production due to a mismatch of how the index that the coal cost component of the energy payment is determined and the price increase of base coal in the amended coal purchase agreement (see below). The energy payments will continue to be insufficient to cover the variable costs of steam production for steam supplied to LDC.
These shortfalls are not expected by the Partnership to have a material adverse effect on its ability to service its debt and fund operations due to the level of capacity payments.
Energy Services Agreement
The Partnership supplies thermal energy to LDC in order for the Facility to meet the operating and efficiency standards under the Public Utility Regulatory Policy Act of 1978, as amended, and the FERC's regulations promulgated thereunder (collectively, "PURPA"). The Facility has been certified as a Qualifying Facility under PURPA. Under PURPA, Qualifying Facilities are exempt from certain provisions of the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), most provisions of the Federal Power Act (the "FPA"), and, except under certain limited circumstances, rate and financial regulation under state law. The Energy Services Agreement with LDC requires LDC to purchase the lesser of (i) 525 million pounds of steam per year or (ii) the minimum quantity of steam per year necessary for the Facility to maintain its status as a Qualifying Facility under PURPA (currently estimated by the Partnership not to exceed 525 million pounds per year).
Coal Purchase and Transportation Agreement
The Partnership has a coal purchase agreement (the "Coal Purchase Agreement") with Lodestar Energy, Inc. ("LEI") pursuant to which Lodestar supplies all of the Facility's coal needs, which are estimated to be 1 million tons of coal per year. The Partnership has no obligation to purchase a minimum quantity of coal under the Coal Purchase Agreement.
During 1997, coal ash produced during operation of the Facility was disposed of pursuant to the Coal Purchase Agreement and back-up disposal arrangements with Chambers Waste Systems, Inc. of Florida ("Chambers"). In 1998, the Partnership entered into agreements with Lodestar and VFL Technology Corporation ("VFL") for ash disposal at alternative sites. These agreements reduced the cost of ash disposal. The Partnership has been informed that LEI, Chambers, and VFL have obtained the permits necessary to receive such coal ash.
4
On April 27, 2001, an order for relief was entered in the Involuntary Petition under Chapter 11 of the United States Bankruptcy Code with respect to LEI and its parent, Lodestar Holdings Inc. ("LHI"), in the U.S. Bankruptcy Court in Lexington, Kentucky. Since that time, LHI and LEI have been operating their business as "debtors in possession." On October 3, 2001, LEI filed a motion with the Bankruptcy Court seeking to reject the Coal Purchase Agreement. The Partnership and LEI agreed to and executed Amendment No. 3 to the Coal Purchase Agreement effective October 16, 2001 (the "Amendment"). The principal change effected in the Coal Purchase Agreement by the Amendment was an increase from $26.632 to $34.00 per ton in the base coal price for coal delivered after October 16, 2001, with a 2% additional increase in the base coal price effective October 16, 2002. The transportation and administrative fees the Partnership is required to pay remain unchanged, but will continue to adjust in accordance with the terms of the Coal Purchase Agreement. The Amendment also includes market price reopener provisions, beginning October 16, 2003.
LEI has failed to perform certain of its obligations under the Coal Purchase Agreement related to ash disposal, and on January 28, 2003, the Partnership delivered a notice of an event of default to LEI. In the event the contract is terminated as a result of such default, by LEI or otherwise, the Partnership has entered into a backup coal supply agreement and alternate ash disposal agreements.
In December 2002, an order by the U.S. Bankruptcy Court was issued authorizing LEI to sell its property at auction, which occurred on January 30, 2003. The Coal Purchase and Transportation Agreement was included in the property auctioned. A bid was made for the property, including the agreement with the Partnership. At a court hearing to certify the auction, the highest bidder rescinded their bid, claiming information was withheld during their due diligence before the auction. Since most of the officers and directors of LEI resigned prior to the court hearing, the judge appointed a trustee for Lodestar who is to advise the court on the next course of action to pursue.
A new Ash Disposal Agreement was executed on February 1, 2003 between the Partnership and VFL Technology Corp. ("VFL") and has a term of four years with an option for an additional two years. The agreement calls for the nominal removal of 1,000 to 1,500 tons of dry fly ash per week, which is approximately 50% of the fly ash produced each week, and allows for the removal of up to 100% of the fly ash produced by the Facility. The disposal fee is $21.85 per ton and is adjusted quarterly beginning on May 1, 2003 in accordance with a Producer Price Index, which includes labor to load trucks, the transportation vehicles, transportation costs and disposal fee. This agreement, combined with other current ash disposal agreements, allows the Partnership to dispose of all of the Partnership's ash without relying on Lodestar. The Partnership has satisfied the applicable conditions precedent set forth in the Partnership's financing documents relating to the entering into of the Ash Disposal Agreement.
The Back-up Coal Agreement was executed on February 5, 2003 between the Partnership and Massey Coal Sales, Inc. ("Massey"). Under the Back-up Coal Agreement, Massey will provide coal under substantially similar terms to the Coal Supply Agreement should the Coal Supply Agreement with Lodestar be terminated. The base coal price is $33.75 per ton and the term can be extended through December 31, 2025. The agreement also includes market price reopener provisions, beginning October 16, 2003. The Partnership has satisfied the applicable conditions precedent set forth in the Partnership's financing documents relating to the entering into of the Back-up Coal Agreement. The Partnership continues to receive coal shipments from LEI.
5
On March 20, 2003, the Partnership and the court appointed trustee negotiated a settlement which effectively terminates the Coal Purchase Agreement as of March 31, 2003. A motion for an order approving the settlement was filed in the U.S. Bankruptcy Court on March 21, 2003. An order approving the settlement must be entered by the Bankruptcy Court no later than April 15, 2003. Closing will occur as reasonably practicable after the entry of an order approving this settlement, but in no event later than April 15, 2003. At closing, (i) the Partnership will make a settlement payment to the court appointed trustee, on behalf of LEI, in the amount of $1.0 million and (ii) general releases in form and substance mutually acceptable shall be exchanged between the Partnership and Lodestar. Once the order approving the settlement is entered, the Back-up Coal Agreement will become effective retroactively to the date of termination of the Coal Purchase Agreement specified in the settlement. Upon the termination of the Coal Purchase Agreement, the Transportation Agreement will revert from Lodestar to the Partnership. This settlement cannot become effective until the applicable conditions under the Partnership's financing documents are satisfied. The Partnership currently anticipates that all applicable conditions under such financing documents will be completed in the near future. The Partnership will continue to receive coal shipments from Lodestar for trains loaded through March 31, 2003. The Facility begins a routine two week scheduled maintenance outage on April 1, 2003.
Lime Purchase Agreement
The Partnership entered into a lime purchase agreement (the "Lime Purchase Agreement") with Chemical Lime Company ("Chemlime"), an Alabama corporation, to supply the lime requirements of the Facility's dry scrubber and sulfur dioxide removal system. The initial term of the Lime Purchase Agreement is 15 years from the commercial operation date. Chemlime is obligated to provide all of the Facility's lime requirements, but the Partnership has no obligation to purchase a minimum quantity of lime. The price of lime was renegotiated in 1999 for a three-year period beginning January 1, 2000. Chemlime notified the Partnership of its intention to cancel the agreement effective in the first quarter of 2002. The price was again renegotiated for a three-year period beginning February 1, 2002.
Competition
Since the Partnership has a long-term contract to sell electric generating capacity and energy from the Facility to FPL, it does not expect competitive forces to have a significant effect on its business. The Partnership expects that the capacity payments under the Power Purchase Agreement, which are not affected by the level of FPL's dispatch of the Facility, will cover all of the Partnership's fixed costs, including debt service.
6
Regulations and Environmental Matters
The Partnership has obtained all material environmental permits and approvals required, as of December 31, 2002, in order to continue commercial operation of the Facility. Certain of these permits and approvals are subject to periodic renewal. Certain additional permits and approvals will be required in the future for the continued operation of the Facility. The Partnership is not aware of any technical circumstances that would prevent the issuance of such permits and approvals or the renewal of currently issued permits. The Partnership timely filed its application for a Title V air permit on May 24, 1996. The permit was issued on October 11, 1999.
On November 10, 2000 the Partnership submitted to the Florida Department of Environmental Protection ("FDEP") an application for modifications to the Site Certificate. The proposed modifications include a requested increase of the groundwater withdrawal, clarification of authority to allow emergency water withdrawals, changes to groundwater monitoring requirements and programs, and changing the address of the Facility. On March 14, 2001 FDEP approved and issued a final order modifying the Conditions of Certification related to South Florida Management District ("SFWMD") authority to authorize withdrawals of ground or surface water and a modification for storage pond elevation changes. On October 9, 2002 FDEP issued an order modifying the Conditions of Certification that added current regulatory references, current Best Management Practice Plans and conformed the conditions to the final Prevention of Significant Deterioration ("PSD") and Title V permits. This order finalized all modifications requested under the November 10, 2000 application by the Partnership.
Employees
The Partnership has no employees and does not anticipate having any employees in the future because, under a management services agreement, NEG acts as the Partnership's representative in all aspects of managing the operation of the Facility as directed by the Partnership's Board of Control. As noted above, PG&E OSC is providing operations and maintenance services for the Partnership.
Item 2 PROPERTIES
The Facility is located in a predominantly industrial area in southwestern Martin County, Florida, on approximately 240 acres of land owned by the Partnership (the "Site"). An additional five acres of property is owned in eastern Okeechobee County, Florida for a water pumping facility associated with the make-up water supply pipeline. Other than the Facility, the Site, and the make-up water pipeline and associated equipment, the Partnership does not own or lease any material properties.
Item 3 LEGAL PROCEEDINGS
None.
7
Item 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the security holders of the Partnership during 2002.
8
PART II
Item 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
RELATED SECURITY HOLDER MATTERS
The Partnership is a Delaware limited partnership wholly owned by Palm, Toyan, Thaleia and IPILP. Beneficial interests in the Partnership are not available to other persons except with the consent of the Partners.
There is no established public market for ICL Funding's common stock. The 100 shares of $1 par common stock are owned by the Partnership. ICL Funding has not paid, and does not intend to pay, dividends on the common stock.
Item 6 SELECTED FINANCIAL DATA
The following selected financial data of the Partnership presented below are derived from the consolidated balance sheet and financial statements information of the Partnership as of and for the years ended December 31, 2002, 2001, 2000, 1999, and 1998. The data should be read in conjunction with Item 7 of this report, "Management's Discussion an Analysis of Financial Condition And Results of Operations", and with the Partnership's consolidated financial statements appearing elsewhere in this report. The financial statements and supplementary data required by this item are presented under Item 8.
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Total Assets $679,494,383 $675,194,455 $680,669,565 $694,852,029 $708,139,691
Long-Term Debt 555,918,013 560,702,525 572,521,507 583,994,031 595,835,699
Total Liabilities 587,232,317 586,320,011 595,689,890 605,686,943 615,827,405
Capital Distributions - 12,400,000 25,400,000 25,970,000 35,680,000
Total Partners' Capital 92,262,066 88,874,444 84,979,675 88,244,550 91,800,530
Property, Plant & Equipment, Net
599,925,139 615,144,286 628,354,758 641,449,055 654,188,458
Operating Revenues 162,687,035 175,432,091 177,790,391 163,270,119 159,183,399
Net Income 3,387,622 16,294,769 22,135,125 22,414,020 21,354,967
9
The following is a summary of the quarterly results of operations (unaudited) for the years ended December 31, 2002 and 2001. Refer to Item 1, Business, for discussion of NEG, Inc. liquidity issues and contractual issues that may effect future results.
Quarter Ended
--------------
March 31 June 30 September 30 December 31 Total
-------- ------- ------------ ----------- -----
(in thousands)
2002
- ----
Operating revenues $42,317 $40,006 $40,431 $39,933 $162,687
Gross profit 17,744 16,402 18,001 14,547 66,694
Net income(loss) 1,869 468 2,456 (1,405) 3,388
2001
- ----
Operating revenues $46,459 $45,220 $45,972 $37,781 $175,432
Gross profit 21,549 21,324 22,389 16,399 81,661
Net income 4,976 5,101 6,067 151 16,295
Item 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Cautionary Statement Regarding Forward Looking Statements
The information in this Annual Report on Form 10-K includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. Use of words like "anticipate," "estimate," "intend," "project," "plan," "expect," "will," "believe," "could," and similar expressions help identify forward-looking statements. These statements are based on current expectations and assumptions which the Partnership believes are reasonable and on information currently available to the Partnership. Actual results could differ materially from those contemplated by the forward-looking statements. Although the Partnership believes that the expectations reflected in the forward-looking statements are reasonable, future results, events, levels of activity, performance or achievements cannot be guaranteed. Although the Partnership is not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:
Operational Risks
The Partnership's future results of operation and financial condition will be affected by the performance of equipment, levels of dispatch, the receipt of certain capacity and other fixed payments, electricity prices, fuel deliveries and prices and the outcome of the order to termination the Coal Purchase Agreement.
10
Actions of Florida Power & Light and Other Counterparties
The Partnership's future results of operations and financial condition may be affected by the extent to which counterparties require additional assurances in the form of letters of credit or cash collateral and the failure of the Partnership to maintain the qualifying facility status, which could cause a default under the Power Purchase Agreement.
Accounting and Risk Management
The Partnership's future results of operation and financial condition may be affected by the effect of new accounting pronouncements, changes in critical accounting policies or estimates, the effectiveness of the Partnership's risk management policies and procedures, the ability of the Partnership's counterparties to satisfy their financial commitments to the Partnership and the impact of counterparties' nonperformance on the Partnership's liquidity position and heightened rating agency criteria and the impact of changes in the Partnership's credit ratings.
Legislative and Regulatory Matters
The Partnership's business may be affected by legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries; heightened regulatory and enforcement agency focus on the energy business with the potential for changes in industry regulations and in the treatment of the Partnership by state and federal agencies; and changes in or application of federal, state, and local laws and regulations to which the Partnership is subject.
Litigation and Environmental Matters
The Partnership's future results of operation and financial condition may be affected by the effect of compliance with existing and future environmental and safety laws, regulations, and policies, the cost of which could be significant, and the outcome of potential future litigation and environmental matters.
Overview
The Partnership owns a cogeneration facility consisting of a single pulverized coal boiler and a single steam turbine generator. The Partnership's overall business plan is to safely produce clean, reliable energy pursuant to the terms of the Power Purchase Agreement and the Energy Services Agreement. Revenues are derived primarily from capacity and bonus payments, measured by the Capacity Billing Factor ("CBF"), and sales of electricity. The facility is dispatched for electric energy by FPL on an economic basis. Each agreement year the facility is entitled to four weeks of outages to perform scheduled maintenance, and each fifth year, a total of ten weeks of outage time to perform major maintenance. Differences in the timing and scope of scheduled and major maintenance can have a significant impact on the revenues and operational costs.
Relationship with PG&E Corporation and NEG, Inc.
11
In December 2000, and in January and February 2001, PG&E Corporation and NEG, Inc. completed a corporate restructuring of NEG, Inc. that involved the use or creation of limited liability companies ("LLCs") as intermediate owners between a parent company and its subsidiaries. One of these LLCs is PG&E National Energy Group, LLC, which owns 100% of the stock of NEG, Inc.
On April 6, 2001, Pacific Gas and Electric Company (the "Utility"), another subsidiary of PG&E Corporation, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The Utility and PG&E Corporation jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The proposed plan of reorganization does not directly affect NEG, Inc. or any of its subsidiaries. NEG Inc.'s management believes that NEG, Inc. and its direct and indirect subsidiaries as described above, including the Partnership, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.
As result of the sustained downturn in the power industry, NEG, Inc. and certain of its consolidated affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade NEG, Inc. and certain of its consolidated affiliates' credit ratings to below investment grade. The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership (see "Credit Ratings" below).
NEG, Inc. and certain affiliates, excluding Toyan and IPILP, are currently in default under various debt agreements and guaranteed equity commitments. NEG, Inc., its subsidiaries and their lenders are engaged in discussions to restructure NEG, Inc.'s debt obligations and such other commitments. The Partnership is not a party to such debt agreements and guaranteed equity commitments or participants in such discussion. NEG, Inc. and its subsidiaries are continuing to review opportunities to abandon, sell, or transfer certain assets, and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise.
If the lenders exercise their default remedies or if the financial commitments are not restructured, NEG, Inc. and the affected affiliates may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code.
NEG, Inc. owns an indirect interest in the Partnership, and through its wholly owned subsidiaries NEG and PG&EOSC manages and operates the Project. The Partnership cannot be certain an insolvency or bankruptcy involving NEG, Inc. or any of its affiliates would not affect the NEG Inc.'s ownership arrangement with respect to the Partnership or the ability of NEG and PG&EOSC to manage and operate the Project.
This Management's Discussion and Analysis of Financial Condition and results of Operations should be read in conjunction with the Partnership's consolidated financial statements and notes to the consolidated financial statements included herein.
12
Results of Operations
During 2002, the Facility produced 2,079,781 MW-hr of energy for sale to FPL compared to 2,276,568 MW-hr in 2001. This decrease was due primarily to a scheduled ten week outage in 2002 as compared to four weeks of scheduled outage time in 2001.
The Facility produced approximately 582 million pounds of steam for sale to LDC in 2002 compared to approximately 658 million pounds in 2001 thereby continuing to exceed the minimum requirements to maintain Qualifying Facility status.
The Facility ended the year with a 365 day rolling average Capacity Billing Factor of 89.95% in 2002 and 97.02% in 2001. The Capacity Billing Factor measures the overall availability of the Facility, but gives a heavier weighting to on-peak availability. Cash flows during 2002 were sufficient to fund all operating expenses and debt repayment obligations.
Year ended December 31, 2002 Compared to the Year Ended December 31, 2001
For the years ended December 31, 2002 and 2001, the Partnership had total operating revenues of $162.7 million and $175.4 million, respectively. This decrease in 2002 was attributable primarily to decreased energy revenues of $4.0 million and decreased capacity bonus and capacity revenues of $8.6 million. For the years ended December 31, 2002 and 2001, the Facility achieved an average Capacity Billing Factor of 89.39% and 97.02%, respectively. This resulted in earning monthly capacity payments aggregating $113.4 million for the year in 2002 and $113.2 million for the year in 2001. Bonuses aggregated $0.2 million for the year in 2002 and $9.0 million for the year in 2001. The increased revenues from capacity payments are due primarily to the quarterly escalations on the fixed operating and maintenance component of the capacity charge. The decrease in bonus revenues is due to the decrease in the average Capacity Billing Factor relating to decreased availability due to boiler tube leaks and the generator repairs in 2001. The calculation to compute the Capacity Billing Factor (which is the rolling average of the prior 365 days) throughout all of 2002 included the 11 days of unscheduled outage time in 2001 for the generator repairs with 0% availability for those days. The lower energy revenues are due primarily to additional six weeks of scheduled outage time in 2002 allowable under the PPA to perform major maintenance. During 2002 and 2001, the Facility was dispatched by FPL and generated 2,079,781 megawatt-hours and 2,276,568 megawatt-hours, respectively. The monthly average dispatch rate requested by FPL was 89.0% and 85.3% for the twelve months ended December 31, 2002 and 2001, respectively.
Total operating costs were $106.1 million and $105.4 million for the years ended December 31, 2002 and 2001, respectively. This increase was due primarily to an increase of $3.1 million in operating and maintenance costs relating to the generator repairs and auxiliary boiler repairs. Offsetting the increase in operating costs was a decrease in general and administrative expenses of $1.3 million primarily for lower third-party legal costs, a decrease of $0.6 million for loss on disposal of assets, a decrease in fuel and ash costs of $0.3 million and a decrease of $0.2 million in insurance and taxes. For the years ended December 31, 2002 and 2001, the total net non-operating expense was approximately $53.2 million and $53.8 million, respectively. The decrease was primarily due to a $1.0 million reduction in bond interest expense due to principal payments of the Series A-9 First Mortgage Bonds on June 15, 2002 and on December 15, 2002, and a decrease in letter of credit fees of $0.4 million, offset by a decrease in interest income of $0.5 million and an increase in the amortization of deferred financing costs of $0.2 million.
13
Net income was $3.4 million and $16.3 million for the twelve months ended December 31, 2002 and 2001, respectively. This $12.9 million decrease was primarily attributable to a decrease in revenues of $12.7 million and a $2.2 million increase in cost of sales, offset by a decrease in other operating expenses of $1.5 million and a decrease in net interest expense of $0.6 million, as discussed in detail above.
As of December 31, 2002 and 2001, the Partnership had approximately $599.9 million and $615.1 million, respectively, of property, plant and equipment, net of accumulated depreciation. The property, plant and equipment consists primarily of purchased equipment, construction related labor and materials, interest during construction, financing costs, and other costs directly associated with the construction of the Facility. This decrease is due primarily to depreciation of $15.2 million.
Year ended December 31, 2001 Compared to the Year Ended December 31, 2000
For the years ended December 31, 2001 and 2000, the Partnership had total operating revenues of $175.4 million and $177.8 million, respectively. The decrease in 2001 was attributable primarily to decreased energy revenues of $0.8 million and decreased capacity bonus and capacity revenues of $1.8 million, offset by an increase of $0.2 million of steam revenue reconciliation for 2000 recorded in 2001. For the years ending December 31, 2001 and 2000, the Facility achieved an average Capacity Billing Factor of 97.02% and 98.54% respectively. This decrease was primarily attributable to decreased availability due to boiler tube leaks and repairs to the generator in late 2001. This resulted in earning monthly capacity payments aggregating $113.2 million for the year in 2001 and $112.8 million for the year in 2000. Bonuses aggregated $9.0 million for the year in 2001 and $11.2 million for the year in 2000. The increased revenues from capacity are due primarily to the quarterly escalations on the fixed operating and maintenance component of the capacity charge. The decrease in bonus revenues is due to the decrease in the average Capacity Billing Factor relating to decreased availability due to the repairs discussed above. These repairs also caused the reduction in energy revenue in 2001. During 2001 and 2000, the Facility was dispatched by FPL and generated 2,276,568 megawatt-hours and 2,343,677 megawatt-hours, respectively. The monthly average dispatch rate requested by FPL was 85.3% and 87.6% for the twelve months ended December 31, 2001 and 2000, respectively.
Total operating costs were $105.4 million and $102.1 million for the years ended December 31, 2001 and 2000, respectively. This increase was due primarily to an increase of $0.4 million in fuel and ash costs, a result of the renegotiated coal cost per ton with Lodestar, and an increase of $2.3 million in operating and maintenance expenses relating to the generator repairs and the replacement of baghouse bags, an increase for the loss on disposal of assets of $0.5 million incurred for baghouse repairs, and an increase in depreciation of $0.1 million. For the years ended December 31, 2001 and 2000, the total net interest expense was approximately $53.8 million and $54.5 million, respectively. The decrease was primarily due to a $1.2 million reduction in bond interest expense due to installment payments of the Series A-9 First Mortgage Bonds on June 15, 2001 and on December 15, 2001, and a decrease in letter of credit fees of $0.1 million, offset by a decrease in interest income of $0.6 million.
14
Net income was $16.3 million and $22.1 million for the twelve months ended December 31, 2001 and 2000, respectively. This $5.8 million decrease was primarily attributable to the $3.3 million increase in operating costs, the decrease in revenues of $2.4 million, and the effect of a cumulative change in accounting principle for major maintenance of $0.9 million, offset by a decrease in net interest expense of $0.8 million, as discussed in detail above.
As of December 31, 2001 and 2000, the Partnership had approximately $615.1 million and $628.4 million, respectively, of property, plant and equipment, net of accumulated depreciation. The property, plant and equipment consists primarily of purchased equipment, construction related labor and materials, interest during construction, financing costs, and other costs directly associated with the construction of the Facility. This decrease is due primarily to depreciation of $15.2 million, offset by $1.9 million of capital improvements.
Liquidity and Capital Resources
Net cash provided by operating activities in 2002 was $17.8 million as compared to $33.0 million in 2001. Net cash provided by operating activities primarily represents net income, adjusted by non-cash expenses and income, plus the net effect of changes within the Partnership's operating assets and liability accounts. The decrease in net cash from operations in 2002 is primarily related to the reduction in net income of $12.9 million in 2002.
Net cash used in investing activities in 2002 was $15.9 million as compared to $9.6 million in 2001. Net cash flows used in investing activities represent net additions to plant and equipment and increases in investments held by the Trustee. This increase in investments held by Trustee is attributable to the Partnership's requirement to fund certain letter of credit loans, as discussed later in this section.
Net cash used in financing activities in 2002 was $1.9 million as compared to $23.9 million in 2001. Net cash flows used in financing activities in 2002 and 2001 primarily represent payments on First Mortgage Bonds, cash distributions to Partners and the borrowings under the letter of credit agreement. The decrease in cash used in financing activities is attributable to the Partnership's new financing requirements due to the termination of several letters of credit, as discussed below.
Credit Ratings
On October 8, 2002, Moody's stated that in conjunction with the downgrade of NEG, Inc. it had placed the Partnership's debt under review for possible downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG, Inc. would not have an effect on the rating of the Partnership's debt at this time. S&P's rating of the Partnership's debt is "BBB-". On November 5, 2002, Moody's issued an opinion update changing the rating outlook of the Partnership's debt to "under review for possible downgrade" from "negative outlook". Moody's rating of the Partnership's debt is "Baa3". On December 12, 2002, Fitch Ratings removed the "Rating Watch Negative" from it's "BBB-" rating on the Partnership's debt for the satisfactory completion of the permanent generator repairs during the 2002 scheduled fall outage. There are no minimum credit rating requirements in the Partnership's financing agreements.
15
Bonds
On November 22, 1994, the Partnership and ICL Funding issued first mortgage bonds in an aggregate principal amount of $505 million (the "First Mortgage Bonds"). Of this amount, $236.6 million of the First Mortgage Bonds bear an average interest rate of 9.02% and $268.4 million of the First Mortgage Bonds bear an interest rate of 9.77%. Concurrent with the Partnership's issuance of its First Mortgage Bonds, the Martin County Industrial Development Authority issued $113 million of Industrial Development Refunding Revenue Bonds (Series 1994A) which bear an interest rate of 7.875% (the "1994A Tax Exempt Bonds"). A second series of tax exempt bonds (Series 1994B) in the approximate amount of $12 million, which bear an interest rate of 8.05%, were issued by the Martin County Industrial Development Authority on December 20, 1994 (the "1994B Tax Exempt Bonds" and, together with the 1994A Tax Exempt Bonds, the "1994 Tax Exempt Bonds"). The First Mortgage Bonds and the 1994 Tax Exempt Bonds are hereinafter collectively referred to as the "Bonds."
Certain proceeds from the issuance of the First Mortgage Bonds were used to repay $421 million of the Partnership's indebtedness, and financing fees and expenses incurred in connection with the development and construction of the Facility. The balance of the proceeds were deposited in various restricted funds that are being administered by an independent disbursement agent pursuant to trust indentures and a disbursement agreement. Funds administered by such disbursement agent are invested in specified investments. These funds together with other funds available to the Partnership were used: (i) to finance completion of construction, testing, and initial operation of the Facility; (ii) to finance construction interest and construction-related contingencies; and (iii) to provide for initial working capital.
The proceeds of the 1994 Tax Exempt Bonds were used to refund $113 million principal amount of Industrial Development Revenue Bonds (Series 1992A and Series 1992B) previously issued by the Martin County Industrial Development Authority for the benefit of the Partnership, and to fund, in part, a debt service reserve account for the benefit of the holders of its tax-exempt bonds and to complete construction of certain portions of the Facility.
The Partnership's total borrowings from inception through December 2002 were $769 million. The equity loan of $139 million was repaid on December 26, 1995. As of December 31, 2002, the outstanding borrowings included $125 million from the 1994 Tax Exempt Bonds and all of the available First Mortgage Bond proceeds. The First Mortgage Bonds have matured as follows:
Series Aggregate Principal Amount Date Matured and Paid
------ -------------------------- ---------------------
A-1 $4,397,000 June 15, 1996
A-2 4,398,000 December 15, 1996
A-3 4,850,000 June 15, 1997
A-4 4,851,000 December 15, 1997
A-5 5,132,000 June 15, 1998
A-6 5,133,000 December 15, 1998
A-7 4,998,000 June 15, 1999
A-8 4,999,000 December 15, 1999**
16
**As of December 31, 2002, the Partnership has made semi-annual installments totaling $34,134,438 for the A-9 Series, which does not fully mature until December 15, 2010.
The weighted average interest rate paid by the Partnership on its debt for the years ended December 31, 2002 and 2001, was 9.201% and 9.197%, respectively.
Credit Agreements
The Partnership, pursuant to certain of the Project Contracts, is required to post letters of credit which, in the aggregate, will have a face amount of no more than $65 million. These letters of credit had been issued pursuant to a Letter of Credit and Reimbursement Agreement with Credit Suisse/First Boston (formerly known as Credit Suisse), subject to conditions contained in such Letter of Credit and Reimbursement Agreement. The Letter of Credit and Reimbursement Agreement had a term of seven years subject to extension at the discretion of the banks party thereto. In September 2001, Credit Suisse/First Boston notified the Partnership of its intention not to extend the term of these agreements, which expired in the fourth quarter of 2002. These letters of credit were drawn by LDC on November 14, 2002 and by FPL on December 16, 2002 for $10,000,000 and $1,700,000, respectively.
The Partnership entered into a debt service reserve letter of credit and reimbursement agreement, dated as of November 1, 1994, with BNP Paribas (formerly known as Banque Nationale de Paris) pursuant to which a debt service reserve letter of credit in the amount of approximately $60 million was issued. This agreement has a term of five years subject to extension at the discretion of the banks party thereto. Drawings on the debt service reserve letter of credit became available on the Commercial Operation Date of the Facility to pay principal and interest on the First Mortgage Bonds, the 1994 Tax Exempt Bonds and interest on any loans created by drawings on such debt service reserve letter of credit. Cash and other investments held in the debt service reserve account will be drawn on for the Tax Exempt Bonds prior to any drawings on the debt service reserve letter of credit. On January 11, 1999, in accordance with the Partnership's financing documents, the debt service reserve letter of credit was reduced to approximately $30 million, which, together with cash in the debt service reserve account, represents the maximum remaining semi-annual debt service on the First Mortgage Bonds and the 1994 Tax Exempt Bonds. BNP Paribas notified the Partnership on May 18, 2001 of its intention not to extend the term of the agreement, which expires on November 22, 2005. The Partnership has been unable to find an issuer to replace BNP Paribas which meets the credit requirements under the Trust Indenture. Pursuant to the terms of the Disbursement Agreement, available cash flows are required to be deposited on a monthly basis beginning on May 22, 2002 into the Debt Service Reserve Account or the Tax Exempt Debt Service Reserve Account, as the case may be, until the required Debt Service Reserve Account Required Balance is achieved, which is $29,925,906. No distributions are allowed to the partners until such balance is funded. No funds have been deposited as of December 31, 2002 as there have been no available cash flows due to working capital and major maintenance requirements of the facility as determined by the Partnership pursuant to the terms of the Disbursement Agreement. The Partnership expects to begin to make deposits in the second quarter of 2003 and expects to have the required balance fully funded by the end of the first quarter of 2005.
17
Year Ending December 31, 2003
For 2003, the Partnership has identified possible capital improvements of approximately $2.9 million that will enhance the reliability of the facility and, if approved by the Board of Control, will be funded through cash expected to be generated from operations. These improvements include additional upper aquifer wells and rotating vane classifiers for the pulverizers.
In the absence of any major equipment failures, unit overall availability is expected to be comparable to 2002 levels, which averaged approximately 97% for the year. Capacity bonuses are expected to be higher in 2003 since the Capacity Billing Factor is expected to be at or above 97%, which is the maximum capacity bonus potential each month the Partnership can achieve.
The Partnership believes that it will have adequate cash flows from operations to fund future working capital requirements and cover debt repayment obligations in 2003.
Market Risk
Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow. The Partnership categorizes its market risks as interest rate risk and energy commodity price risk. Immediately below are detailed descriptions of the market risks and explanations as to how each of these risks are managed.
Interest Rate Risk
Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. The Partnership's cash and restricted cash are sensitive to changes in interest rates. Interest rate changes would result in a change in interest income due to the difference between the current interest rates on cash and restricted cash and the variable rate that these financial instruments may adjust to in the future. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. A 10% decrease in 2002 interest rates would be immaterial to the Partnership's consolidated financial statements.
The Partnership's Bonds have fixed interest rates. Changes in the current market rates for the Bonds would not result in a change in interest expense due to the fixed coupon rate of the Bonds.
Energy Commodity Price Risk
The Partnership seeks to reduce its exposure to market risk associated with energy commodities such as electric power and coal fuel through the use of long-term purchase and sale contracts. Currently, the energy price paid by FPL for the coal cost component of the energy payment is not matched to the price of base coal in the amended coal purchase agreement. A provision in the Power Purchase Agreement allows FPL and the Partnership to meet and adjust annually the energy payment with the objective of minimizing the difference in the actual energy costs and the energy payments, if the difference is more than 4%.
18
Critical Accounting Policies
The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States involves the use of estimates and assumptions that affect the recorded amount of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain of these estimates and assumptions are considered to be Critical Accounting Policies, due to their complexity, subjectivity, and uncertainty, along with their relevance to the financial performance of the Partnership. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.
Revenues from the sale of electricity are recorded based on output delivered and capacity provided at rates as specified under contract terms in the periods to which they pertain, calculated based upon certain capacity factors and energy and fuel cost estimates.
The Partnership adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities"("SFAS No. 133"), as amended by SFAS Nos. 137 and 138, on January 1, 2001. This standard requires the Partnership to recognize all derivatives, as defined in the statements listed above, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of partners' capital, until the hedged items are recognized in earnings. The Partnership has certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. Since these activities qualify as normal purchase and sale activities, the Partnership has not recorded the value of the related contracts on its balance sheet, as permitted under the standards.
On April 1, 2002, the Partnership implemented two interpretations issued by the FASB's Derivative Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of normal purchase and sales included in SFAS No. 133. DIG Issue C15 changed the definition of normal purchases and sales for certain power contracts. DIG Issue C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Partnership has reviewed these interpretations and has determined that its commodity contracts for the physical delivery of purchase and sale quantities continue to qualify for the normal purchases and sales exception and continue to be recorded on an accrual basis.
On January 1, 2002 the Partnership adopted Statements of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, but retains its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. SFAS No. 144 requires that all long-lived assets to be disposed of by sale be carried at the lower of carrying amount or fair value less cost to sell, and that depreciation cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. The initial adoption of this Standard did not have any impact on the Partnership's Financial Statements.
19
The Partnership reviews the long-lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. If the long-lived assets are determined to be impaired, the Partnership will recognize an impairment loss in accordance with SFAS No. 144. During 2001 and 2002, the Partnership assessed the facility for possible impairment when Lodestar Energy, Inc., ("Lodestar") the Partnership's coal supplier, announced it had filed for bankruptcy and then was authorized to sell its property at auction, respectively. In the opinion of management of the Partnership and based on its impairment analysis, there has been no impairment of the facility and thus no impact on the Partnership's financial condition or results of operations in either 2001 or 2002.
Accounting principles not yet adopted
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The Partnership will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Standard, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations. The Partnership is currently evaluating the impact of applying this Statement. Based on its current evaluation, the Partnership estimates asset retirement obligations to be up to approximately $100,000. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is estimated to be a loss of up to approximately $50,000.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit and disposal activities initiated after December 31, 2002. In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This Interpretation establishes new disclosure requirements for all guarantees, but the measurement criteria are applicable to guarantees issued and modified after December 31, 2002. In January 2003, the FASB Issued Interpretation No. 46, Consolidation of Variable Interest Entities. This Interpretation applies to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. For variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003, application begins in the first fiscal year or interim period beginning after June 15, 2003. The Partnership does not currently believe that any of these three standards/interpretations will have a material impact on its current financial position or operations and the Partnership will continue to monitor and access.
Legal Matters
The Partnership is currently not involved in any legal proceedings.
20
Item 7A Quantatative and Qualitative Disclosures About Market Risk
The table below presents principal, interest and related weighted average interest rates by year of maturity (in thousands).
- ---------------------------- ----------- ----------- ----------- ----------- ----------- --------------- ------------ ------------
DEBT (all fixed rate) 2003 2004 2005 2006 2007 Thereafter Total Fair Value
---- ---- ---- ---- ---- ---------- ----- ----------
Tax Exempt Bonds:
Principal $0.0 $0.0 $0.0 $0.0 $0.0 $125,010 $125,010 $161,524
Interest $9,865 $9,865 $9,865 $9,865 $9,865 $155,953 $205,278
Average Interest Rate 7.89% 7.89% 7.89% 7.89% 7.89% 7.89%
First Mortgage Bonds:
Principal $14,566 $16,785 $16,257 $18,224 $20,944 $345,331 $432,107 $564,929
Interest $41,045 $39,645 $38,102 $36,552 $34,801 $211,230 $401,375
Average Interest Rate 9.58% 9.59% 9.61% 9.62% 9.64% 9.75%
- ---------------------------- ----------- ----------- ----------- ----------- ----------- --------------- ------------ ------------
21
Item 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Financial Statements Page
Reports of Independent Auditors and Independent Public Accountants 23
Consolidated Balance Sheets 24
Consolidated Statements of Operations 26
Consolidated Statements of Changes in Partners' Capital 27
Consolidated Statements of Cash Flows 28
Notes to Consolidated Financial Statements 29
22
Report of Independent Auditors
To the Board of Control of
Indiantown Cogeneration, L.P.:
We have audited the accompanying consolidated balance sheet of Indiantown Cogeneration, L.P. and subsidiary as of December 31, 2002 and the related consolidated statements of operations, changes in partners’ capital and cash flows for the year then ended. 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 audit. The accompanying consolidated balance sheet of Indiantown Cogeneration, L.P. and subsidiary for the year ended December 31, 2001 and the related consolidated statements of operations, changes in partners’ capital and cash flows for each of the two years in the period ended December 31, 2001, were audited by other auditors who have ceased operations and whose report dated January 23, 2002, expressed an unqualified opinion on those statements and included an explanatory paragraph that disclosed the change in the Partnership’s method of accounting for scheduled major overhauls discussed in Note 2 to the financial statements.
We conducted our audit in accordance with auditing standards generally accepted in the United States. 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Indiantown Cogeneration, L.P. and subsidiary at December 31, 2002, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States.
/s/ Ernst & Young LLP
McLean, Virginia
February 24, 2003
23
Report of Independent Public Accountants
To Indiantown Cogeneration, L.P.:
We have audited the accompanying consolidated balance sheets of Indiantown Cogeneration, L.P. (a Delaware limited partnership) and subsidiary (“the Partnership”) as of December 31, 2001 and 2000, and the related consolidated statements of operations, changes in partners’ capital and cash flows for the years then ended. 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 auditing standards generally accepted in the United States. 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, the financial statements referred to above present fairly, in all material respects, the financial position of Indiantown Cogeneration, L.P. and subsidiary as of December 31, 2001 and 2000, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States.
As discussed in Note 2 to the financial statements, the Partnership changed its method of accounting for scheduled major overhauls in 2000.
/S/ ARTHUR ANDERSEN LLP
Vienna, Virginia
January 23, 2002
24
Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Balance Sheets
As of December 31, 2002 and 2001
ASSETS 2002 2001
- ------------------------------------------------------------------------ ------------------ ------------------
CURRENT ASSETS:
Cash and cash equivalents $ 289,738 $ 331,956
Restricted cash 1,700,000 -
Accounts receivable-trade 17,512,867 14,443,374
Inventories 740,981 259,282
Prepaid expenses 927,771 981,571
Deposits 44,000 44,450
Investments held by Trustee, including restricted funds
of $5,568,725 and $2,666,539, respectively 14,913,265 9,572,996
----------------- ------------------
Total current assets 36,128,622 25,633,629
INVESTMENTS HELD BY TRUSTEE,
restricted funds 26,001,000 15,502,121
DEPOSITS 185,069 171,737
PROPERTY, PLANT & EQUIPMENT:
Land 8,582,363 8,582,363
Electric and steam generating facilities 702,090,197 702,175,087
Less - accumulated depreciation (110,747,421) (95,613,164)
------------------ ------------------
Net property, plant & equipment 599,925,139 615,144,286
FUEL RESERVE 3,565,050 4,059,534
DEFERRED FINANCING COSTS, net of accumulated
amortization of $46,497,413 and $45,503,768, respectively 13,689,503 14,683,148
------------------ ------------------
Total assets $ 679,494,383 $ 675,194,455
================== ==================
The accompanying notes are an integral part of these consolidated financial statements.
25
Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Balance Sheets
As of December 31, 2002 and 2001
LIABILITIES AND PARTNERS' CAPITAL 2002 2001
- ------------------------------------------------------------------ ----------------- -----------------
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 9,769,844 $ 10,474,699
Accounts payable and accrued liabilities to related parties
(Note 8) 2,841,984 999,627
Accrued interest 2,321,651 2,324,178
Current portion - First Mortgage Bonds 14,566,087 11,460,407
Current portion of lease payable - railcars 383,131 358,575
Current portion of term loans 1,431,607 -
----------------- -----------------
Total current liabilities 31,314,304 25,617,486
----------------- -----------------
LONG TERM DEBT:
First Mortgage Bonds 417,541,475 432,107,562
Tax Exempt Facility Revenue Bonds 125,010,000 125,010,000
Lease payable - railcars 3,203,957 3,584,963
Term loans 10,162,581 -
----------------- -----------------
Total long term debt 555,918,013 560,702,525
----------------- -----------------
Total liabilities 587,232,317 586,320,011
----------------- -----------------
COMMITMENTS AND CONTINGENCIES (NOTE 7)
PARTNERS' CAPITAL:
General Partners:
Palm Power Corporation 9,226,206 8,887,444
Indiantown Project Investment, L.P. 18,406,281 17,730,450
Limited Partners:
Toyan Enterprises 27,724,753 26,706,773
Thaleia, LLC 36,904,826 35,549,777
----------------- -----------------
Total partners' capital 92,262,066 88,874,444
----------------- -----------------
Total liabilities and partners' capital $ 679,494,383 $ 675,194,455
================= =================
The accompanying notes are an integral part of these consolidated financial statements.
26
Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Statements of Operations
For the Years Ended December 31, 2002, 2001 and 2000
2002 2001 2000
----------------- ------------------ -------------------
----------------- ------------------ -------------------
Operating Revenues:
Electric capacity and capacity bonus $113,561,178 $122,202,351 $124,029,498
Electric energy revenue 48,856,279 52,901,962 53,652,475
Steam 269,578 327,778 108,418
----------------- ---------------- ------------------
Total operating revenues 162,687,035 175,432,091 177,790,391
----------------- ---------------- ------------------
Cost of Sales:
Fuel and ash 56,023,495 56,320,761 55,910,214
Operating and maintenance 24,716,289 21,654,029 19,353,798
Depreciation 15,223,197 15,187,033 15,003,258
Loss on disposal of assets 29,647 609,097 155,780
-------------- ------------- -------------
Total cost of sales 95,992,628 93,770,920 90,423,050
----------- ----------- -------------
Gross Profit 66,694,407 81,661,171 87,367,341
----------- ----------- -----------
Other Operating Expenses:
General and administrative 3,171,241 4,450,258 5,179,313
Insurance and taxes 6,960,282 7,155,260 6,475,006
------------ ------------ ------------
Total other operating expenses 10,131,523 11,605,518 11,654,319
----------- ----------- -----------
Operating Income 56,562,884 70,055,653 75,713,022
----------- ----------- -----------
Non-Operating Income (Expense):
Interest expense (54,421,727) (55,528,078) (56,905,787)
Interest income 1,246,465 1,767,194 2,407,354
--------------- ------------- --------------
Net non-operating expense (53,175,262) (53,760,884) (54,498,433)
-------------- ------------- -------------
Income before cumulative effect of a change in accounting
principle 3,387,622 16,294,769 21,214,589
Cumulative effect of a change in accounting
principle for scheduled major overhaul costs
(Note 2) -- -- 920,536
-------------- ------------- -------------
Net Income $ 3,387,622 $ 16,294,769 $ 22,135,125
============= =============== =============
The accompanying notes are an integral part of these consolidated financial statements.
27
Indiantown Cogeneration, L. P. and Subsidiary
Consolidated Statements of Changes in Partners' Capital
For the Years Ended December 31, 2002, 2001 and 2000
---------------
Toyan Palm Power Total Partners'
Enterprises Corporation IPILP Thaleia, LLC Capital
----------- ----------- -------------- ------------ ---------------
Partners' capital, December 31, 1999 $26,517,489 $8,824,455 $17,604,787 $35,297,819 $88,244,550
=========== =========== =========== =========== =============
Net Income
6,651,60 2,213,512 4,415,957 8,854,05 22,135,125
Capital distributions (7,632,700) (2,540,000) (5,067,300) (10,160,000) (25,400,000)
----------- ----------- ------------- ------------- --------------
Partners' capital, December 31, 2000 $25,536,395 $8,497,967 $16,953,444 $33,991,869 $84,979,675
=========== =========== ============= ============= ==============
Net Income
4,896,57 1,629,477 3,250,806 6,517,908 16,294,769
Capital distributions (3,726,200) (1,240,000) (2,473,800) (4,960,000) (12,400,000)
----------- ----------- ------------- ------------- --------------
Partners' capital, December 31, 2001 $26,706,773 $8,887,444 $17,730,450 $35,549,777 $88,874,444
=========== ========== ============ ============ =============
Net Income 1,017,98 338,762 675,831 1,355,049 3,387,622
------------ ------------ ------------ ------------ -------------
Partners' capital, December 31, 2002 $27,724,753 $9,226,206 $18,406,281 $36,904,826 $92,262,066
=========== ========== =========== ============ =============
The accompanying notes are an integral part of these consolidated financial statements.
28
Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2002, 2001, and 2000
2002 2001 2000
----------------- --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $3,387,622 $16,294,769 $22,135,125
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of a change in accounting principles -- -- (920,536)
Depreciation and amortization 16,217,265 16,011,589 15,827,822
Loss on disposal of assets 29,647 609,097 155,780
Effect of changes in assets and liabilities:
Increase in accounts receivable-trade (3,069,493) (589,889) (381,500)
Decrease (increase) in inventories and fuel reserve 12,785 (1,279,926) (574,774)
Decrease (increase) in deposits and prepaid expenses 40,917 (193,705) (72,231)
Increase in accounts payable and
accrued liabilities,
including related parties, and accrued interest 1,134,975 2,102,645 1,844,616
----------- ----------- -----------
Net cash provided by operating activities 17,753,718 32,954,580 38,014,302
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property, plant & equipment (34,119) (2,585,658) (2,064,741)
Increase in investments held by Trustee (15,839,148) (6,986,397) (302,934)
------------ ----------- ---------
Net cash used in investing activities (15,873,267) (9,572,055) (2,367,675)
------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in restricted cash (1,700,000) - -
Payment on capital lease obligation - railcars (356,451) (331,628) (308,534)
Borrowings under revolving credit agreement - 3,697,173 12,835,436
Repayments under revolving credit agreement - (3,697,173) (12,835,436)
Borrowings under letter of credit agreement 11,700,000 - -
Repayments under letter of credit agreement (105,811) - -
Payment on First Mortgage Bonds (11,460,407) (11,140,896) (11,533,135)
Capital distributions - (12,400,000) (25,400,000)
------------ ------------ ------------
Net cash used in financing activities (1,922,669) (23,872,524) (37,241,669)
----------- ------------ ------------
CHANGE IN CASH AND CASH EQUIVALENTS (42,218) (489,999) (1,595,042)
Cash and cash equivalents, beginning of year 331,956 821,955 2,416,997
--------------- --------------- -------------
Cash and cash equivalents, end of year $ 289,738 $ 331,956 $ 821,955
=============== =============== ==============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION:
Cash paid for interest $52,077,732 $53,082,539 $54,141,427
=========== =========== ===========
The accompanying notes are an integral part of these consolidated financial statements.
29
Indiantown Cogeneration, L.P. and Subsidiary Notes to Consolidated Financial Statements As of December 31, 2002 and 2001
1. ORGANIZATION AND BUSINESS:
Indiantown Cogeneration, L.P. (the "Partnership") is a special purpose Delaware limited partnership formed on October 4, 1991. The Partnership was formed to develop, construct, and operate an approximately 330 megawatt (net) pulverized coal-fired cogeneration facility (the "Facility") located on an approximately 240 acre site in southwestern Martin County, Florida. The Facility produces electricity for sale to Florida Power & Light Company ("FPL") and supplies steam to Caulkins Indiantown Citrus Co. ("Caulkins") for its plant located near the Facility. In September 2001, Caulkins sold its processing plant to Louis Dreyfus Citrus, Inc. ("LDC").
The original general partners were Toyan Enterprises ("Toyan"), a California corporation and a wholly owned special purpose indirect subsidiary of PG&E National Energy Group, Inc. ("NEG, Inc.") and Palm Power Corporation ("Palm"), a Delaware corporation and a special purpose indirect subsidiary of Bechtel Enterprises, Inc. ("Bechtel Enterprises"). The sole limited partner was TIFD III-Y, Inc. ("TIFD"), a special purpose indirect subsidiary of General Electric Capital Corporation ("GECC"). During 1994, the Partnership formed its sole, wholly owned subsidiary, Indiantown Cogeneration Funding Corporation ("ICL Funding"), to act as agent for, and co-issuer with, the Partnership in accordance with the 1994 bond offering discussed in Note 4. ICL Funding has no separate operations and has only $100 in assets.
In 1998, Toyan consummated transactions with DCC Project Finance Twelve, Inc. ("PFT"), whereby PFT, through a new partnership (Indiantown Project Investment, L.P. ("IPILP")) with Toyan, became a new general partner in the Partnership. Toyan is the sole general partner of IPILP. Prior to the PFT transaction, Toyan converted some of its general partnership interest into a limited partnership interest such that Toyan now directly holds only a limited partnership interest in the Partnership. In addition, Bechtel Generating Company, Inc. ("Bechtel Generating"), sold all of the stock of Palm to a wholly owned indirect subsidiary of Cogentrix Energy, Inc. ("Cogentrix"). Palm holds a 10% general partner interest in the Partnership.
On June 4, 1999, Thaleia, LLC ("Thaleia"), a wholly owned subsidiary of Palm and indirect wholly owned subsidiary of Cogentrix, acquired from TIFD a 19.90% limited partner interest in the Partnership. On September 20, 1999, Thaleia acquired another 20.00% limited partnership interest from TIFD and TIFD's membership on the Board of Control of the Partnership. On November 24, 1999, Thaleia purchased TIFD's remaining limited partnership interest in the Partnership from TIFD.
The net income of the Partnership is allocated to Toyan, Palm, IPILP and Thaleia (collectively, the "Partners") based on the following ownership percentages:
Toyan 30.05%
Palm 10.00%
IPILP 19.95%
Thaleia 40.00%
30
All distributions other than liquidating distributions will be made based on the Partners' percentage interest as shown above, in accordance with the project documents and at such times and in such amounts as the Board of Control of the Partnership determines.
The Partnership is managed by PG&E National Energy Group Company ("NEG"), formerly known as PG&E Generating Company pursuant to a Management Services Agreement (the "MSA"). The Facility is operated by PG&E Operating Services Company ("PG&E OSC"), formerly known as U.S. Operating Services Company, pursuant to an Operation and Maintenance Agreement (the "O&M Agreement"). NEG and PG&E OSC are general partnerships indirectly wholly owned by NEG, Inc., an indirect wholly owned subsidiary of PG&E Corporation (see Note 8).
The Partnership commenced commercial operations on December 22, 1995 (the "Commercial Operation Date").
As a result of the sustained downturn in the electric energy industry, NEG, Inc. and certain of its consolidated affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade NEG, Inc. and certain of its consolidated affiliates' credit ratings to below investment grade. The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership.
On October 8, 2002, Moody's stated that in conjunction with the downgrade of NEG it had placed the Partnership's debt under review for possible downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG would not have an effect on the rating of the Partnership's debt at this time. S&P's rating of the Partnership's debt is "BBB-". On November 5, 2002, Moody's issued an opinion update changing the rating outlook of the Partnership's debt to "under review for possible downgrade" from "negative outlook". Moody's rating of the Partnership's debt is "Baa3".
NEG, Inc. and certain affiliates are currently in default under various debt agreements and guaranteed equity commitments. NEG, Inc., and its lenders are attempting to restructure these commitments. As part of the restructuring, NEG, Inc. and the affected affiliates are exploring various options to reduce their liquidity issues. These options include the abandonment, sale, or transfer of assets, and the reduction of NEG, Inc.'s energy trading operations.
If the lenders exercise their default remedies or if the financial commitments are not restructured, NEG, Inc. and the affected affiliates may be compelled to seek protection under or be forced into a proceeding under Chapter 11 of the U.S. Bankruptcy Code.
NEG, Inc. owns an indirect interest in the Partnership, and through its wholly owned subsidiaries PG&E National Energy Group Company (NEG) and PG&E Operating Services Company (PG&EOSC) provides services to the Partnership. Although the management of NEG, Inc. does not expect a material impact on the Partnership as a result of the matters set for in the prior three paragraphs, the Partnership cannot be certain that the insolvency or bankruptcy involving NEG, Inc. or any of its subsidiaries would not affect the Partnership's operating contracts with any NEG, Inc. subsidiary, any of the Partnership's debt arrangements or the ownership arrangements respecting the Partnership.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect 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 revenue and expenses during the reporting period. Actual results could differ from those estimates.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of the Partnership and ICL Funding. All significant intercompany balances have been eliminated in consolidation.
Cash Equivalents
The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Inventories Inventories are stated at the lower of cost or market using the average cost method. The Partnership determines average cost by summing the weighted average cost of inventory at the beginning of the month plus the weighted average cost of additions during the month to determine the average cost of inventory consumed and the ending inventory balance.
Deposits
Deposits are stated at cost and include amounts required under certain of the Partnership's agreements as described in Note 3.
Investments Held by Trustee
The investments held by the Trustee represent bond and equity proceeds held by a bond Trustee/disbursement agent and are carried at cost, which approximates market value. All funds are invested in either Nations Treasury Fund-Class A or other permitted investments for longer periods. The Partnership also maintains restricted investments covering a portion of the partnership's debt as required by the financing documents. The proceeds include $12,501,000 of restricted tax-exempt debt service reserve required by the financing documents and are classified as a noncurrent asset on the accompanying consolidated balance sheets. A qualifying facility ("QF") reserve of $3,500,000 is also held as a non-current asset (see Note 4).
32
Property, Plant and Equipment
Property, plant and equipment, which consist primarily of the Facility, are recorded at actual cost. The Facility is depreciated on a straight-line basis over 35 years with a residual value on the Facility approximating 25 percent of the gross Facility costs.
Other property, plant and equipment are depreciated on a straight-line basis over the estimated economic or service lives of the respective assets (ranging from five to seven years). Routine maintenance and repairs are charged to expense as incurred.
On January 1, 2002 the Partnership adopted Statements of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, but retains its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. SFAS No. 144 requires that all long-lived assets to be disposed of by sale be carried at the lower of carrying amount or fair value less cost to sell, and that depreciation cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. The initial adoption of this Standard did not have any impact on the Partnership's Financial Statements.
The Partnership reviews the long-lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of the long-lived assets may not be recoverable. If the long-lived assets are determined to be impaired, the Partnership will recognize an impairment loss in accordance with SFAS No. 144. During 2001 and 2002, the Partnership assessed for possible impairment of the facility when Lodestar Energy, Inc., ("Lodestar") the Partnership's coal supplier, announced it had filed for bankruptcy and then was authorized to sell its property at auction, respectively (see Note 5). In the opinion of management of the Partnership and based on its impairment analysis, there has been no impairment of the facility and thus no impact on the Partnership's financial condition or results of operations in either 2001 or 2002. Fuel Reserve
The fuel reserve, carried at cost, represents an approximate twenty-five day supply of coal held for emergency purposes. Since the use of this reserve in an emergency is not expected in the short-term, the related cost is reflected as non-current on the accompanying consolidated balance sheets.
Deferred Financing Costs
Financing costs, consisting primarily of the costs incurred to obtain project financing, are deferred and amortized using the effective interest rate method over the term of the related permanent financing.
33
Scheduled Major Overhauls
In fiscal year 2000, the Securities and Exchange Commission ("SEC") issued a ruling that changed the allowable methods of accounting for scheduled major overhaul to the as incurred method rather than the accrue in advance method which had been used by the Partnership. The SEC's ruling allows companies to recognize the change as a cumulative effect of a change in accounting principle in the year of adoption. As such, the Partnership reflected a cumulative effect of a change in accounting principle in the year of adoption. The Partnership reflected a cumulative effect of a change in accounting principle of $920,536 in the accompanying financial statements. Since no scheduled major overhaul expenses were incurred in 2000, the effect of adopting this new accounting principle was a reduction of operating and maintenance costs of $424,000.
Revenue Recognition
Revenues from the sale of electricity are recorded based on output delivered and capacity provided at rates as specified under contract terms in the periods to which they pertain. No collateral is required on accounts receivable.
Income Taxes
Under current law, no Federal or state income taxes are paid directly by the Partnership. All items of income and expense of the Partnership are allocable to and reportable by the Partners in their respective income tax returns. Accordingly, no provision is made in the accompanying consolidated financial statements for Federal or state income taxes.
Derivative Financial Instruments
The Partnership adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. This standard requires the Partnership to recognize all derivatives, as defined in the statements listed above, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of partners' capital, until the hedged items are recognized in earnings. The Partnership has certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. Since these activities qualify as normal purchase and normal sale activities, the Partnership has not recorded the value of the related contracts on its balance sheet, as permitted under the standards.
On April 1, 2002, the Partnership implemented two interpretations issued by the Financial Accounting Standards Board's (FASB) Derivative Implementation Group (DIG). DIG Issues C15 and C16 clarified the definition of normal purchase and sales included in SFAS No. 133. DIG Issue C15 changed the definition of normal purchases and sales for certain power contracts. DIG Issue C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Partnership has reviewed these interpretations and has determined that its commodity contracts for the physical delivery of purchase and sale quantities continues to qualify for the normal purchases and sales exception and continue to be recorded on an accrual basis.
34
New Accounting Pronouncements But Not Yet Adopted
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. The Partnership will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Standard, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations. The Partnership is currently evaluating the impact of applying this Statement. Based on its current evaluation, the Partnership estimates asset retirement obligations to be up to approximately $100,000. The cumulative effect of a change in accounting principle from unrecognized accretion and depreciation expense is estimated to be a loss of up to approximately $50,000.
In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit and disposal activities initiated after December 31, 2002. In November 2002, the FASB issued Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This Interpretation establishes new disclosure requirements for all guarantees, but the measurement criteria are applicable to guarantees issued and modified after December 31, 2002. In January 2003, the FASB Issued Interpretation No. 46, Consolidation of Variable Interest Entities. This Interpretation applies to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. For variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003, application begins in the first fiscal year or interim period beginning after June 15, 2003. The Partnership does not currently believe that any of these three standards/interpretations will have a material impact on its current financial position or operations.
Reclassifications
Certain prior year amounts have been reclassified to conform with the current year presentation.
3. DEPOSITS:
In 1991, in accordance with the Planned Unit Development Zoning Agreement between the Partnership and Martin County, the Partnership deposited $1,000,000 in trust with the Board of County Commissioners of Martin County (the "PUD Trustee"). Income from this trust will be used solely for projects benefiting the community of Indiantown. On July 23, 2025, the PUD Trustee is required to return the deposit to the Partnership. As of December 31, 2002 and 2001, estimated present values of this deposit of $185,069 and $171,737, respectively, are included in deposits in the accompanying consolidated balance sheets. The remaining balance is included in property, plant and equipment as part of total capitalized construction expenses.
35
4. BONDS AND NOTES PAYABLE:
First Mortgage Bonds
In November 22, 1994, the Partnership and ICL Funding jointly issued $505,000,000 of First Mortgage Bonds (the "First Mortgage Bonds") in a public issuance registered with the SEC. Proceeds from the issuance were used to repay outstanding balances of $273,513,000 on a prior construction loan and to complete the project. The First Mortgage Bonds are secured by a lien on and security interest in substantially all of the assets of the Partnership. The First Mortgage Bonds were issued in 10 separate series with fixed interest rates ranging from 7.38% to 9.77% and with maturities ranging from 1996 to 2020. The weighted average interest rate was approximately 9.57% during 2002 and 2001. Interest is payable semi-annually on June 15 and December 15 of each year. Interest expense related to the First Mortgage Bonds was $42,131,432, $43,176,476, and $44,275,872, in 2002, 2001, and 2000 respectively.
Tax Exempt Facility Revenue Bonds
The proceeds from the issuance of $113,000,000 of Series 1992A and 1992B Industrial Development Revenue Bonds (the "1992 Bonds") through the Martin County Industrial Development Authority (the "MCIDA") were invested in an investment portfolio with Fidelity Investments Institutional Services Company. On November 22, 1994, the Partnership refunded the 1992 Bonds with proceeds from the issuance of $113,000,000 Series 1994A and of $12,010,000 Series 1994B Tax Exempt Facility Refunding Revenue Bonds which were issued on December 20, 1994 (the Series 1994A Bonds and the Series 1994B Bonds, collectively, the "1994 Tax Exempt Bonds").
The 1994 Tax Exempt Bonds were issued by the MCIDA pursuant to an Amended and Restated Indenture of Trust between the MCIDA and NationsBank of Florida, N.A. (succeeded by The Bank of New York Trust Company of Florida, N.A.) as trustee (the "Trustee"). Proceeds from the 1994 Tax Exempt Bonds were loaned to the Partnership pursuant to the MCIDA Amended and Restated Authority Loan Agreement dated as of November 1, 1994 (the "Authority Loan"). The Authority Loan is secured by a lien on and a security interest in substantially all of the assets of the Partnership. The 1994 Tax Exempt Bonds, which mature December 15, 2025, carry fixed interest rates of 7.875 % and 8.05% for Series 1994A and 1994B, respectively. Total interest paid related to the 1994 Tax Exempt Bonds was $9,865,555 for each of the years ended December 31, 2002, 2001, and 2000. The Tax Exempt Bonds and the First Mortgage Bonds are equal in seniority.
Future minimum payments related to outstanding First Mortgage Bonds and 1994 Tax Exempt Bonds as of December 31, 2002 are as follows:
2003 $ 14,566,087
2004 16,785,152
2005 16,257,206
2006 18,224,203
2007 20,944,428
Thereafter 470,340,486
Total $557,117,562
============
36
Revolving Credit Agreement
In November 2001, the Revolving Credit Agreement was terminated. The Revolving Credit Agreement provided for the availability of funds for the working capital requirements of the Facility. It had a term of seven years from November 1, 1994. The interest rate was based upon various short-term indices chosen at the Partnership's option and was determined separately for each draw. The weighted average interest rates for the borrowings were approximately 5.52% and 7.98% during 2001 and 2000, respectively. The credit facility included commitment fees, to be paid quarterly, of 0.375 percent on the unborrowed portion. The face amount of the original working capital letter of credit was increased in November 1994 from $10 million to $15 million. Under the original and new working capital credit facilities, the Partnership paid $53,170 and $52,919 in commitment fees in 2001 and 2000, respectively. All borrowings made under this agreement were repaid in the year borrowed. The Partnership incurred interest expense of $17,148 and $84,574 in 2001 and 2000, respectively, related to the Revolving Credit Agreement.
FPL Termination Fee Letter of Credit
On or before the Commercial Operation Date, the Partnership was required to provide FPL with a letter of credit equal to the total termination fee as defined in the Power Purchase Agreement ("PPA") in each year not to exceed $50,000,000. Pursuant to the terms of the Letter of Credit and Reimbursement Agreement, the Partnership obtained a commitment for the issuance of this letter of credit. At the Commercial Operation Date, this letter of credit replaced the completion letter of credit. The initial amount of $13,000,000 was issued for the first year of operations and increased to $40,000,000 in January 1999 and then to $50,000,000 in January 2000. On June 1, 2002 the letter of credit was reduced to $3,100,000 and on November 1, 2002 it was further reduced to $1,700,000 pursuant to the PPA.
In September 2001, Credit Suisse/First Boston notified the Partnership of its intention not to extend the term of this letter of credit, which expired on December 22, 2002. On the expiration date, FPL drew on the direct pay letter of credit for the full amount of $1,700,000, which converted the letter of credit to a term loan. The funds are owned by the Partnership but held by FPL and are included in restricted cash on the consolidated balance sheets. The principal amount of this seven year term loan is payable in fourteen semi-annual installments of $157,645 with a prepayment provision of any outstanding loan amount before cash would be available for distribution to the Partners. No interest or principal payments were made in 2002. Commitment fees of $513,573, $697,049, and $689,092 were paid on this letter of credit in 2002, 2001, and 2000, respectively.
FPL QF Letter of Credit
Within 60 days after the Commercial Operation Date, the Partnership was required to provide a letter of credit for use in the event of a loss of Qualifying Facility ("QF") status under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). The initial amount was $500,000 increasing by $500,000 per agreement year to a maximum of $5,000,000. Pursuant to the terms of the Letter of Credit and Reimbursement Agreement, the Partnership obtained a commitment for the issuance of this letter of credit. The amount will be used by the Partnership as necessary to maintain or reinstate the facility's qualifying facility status. The Partnership may, in lieu of a letter of credit, make regular cash deposits to a dedicated account in amounts of $500,000 per agreement year to a maximum of $5,000,000. In February 1996, the Partnership established a QF account with the Trustee. The balance in this account as of December 31, 2002 and 2001, was $3,500,000 and $3,000,000, respectively, and is included in noncurrent assets as investments held by trustee, restricted funds, on the accompanying consolidated balance sheets.
37Steam Host Letter of Credit
At financial closing in October 1992, the Partnership provided LDC a letter of credit in the amount of $10,000,000 pursuant to the Energy Services Agreement (see Note 6). This letter of credit was terminated in 1994 and a new one was issued with essentially the same terms. In the event of a default under the Energy Services Agreement (see Note 6), the Partnership is required to pay liquidated damages in the amount of $10,000,000. Failure by the Partnership to pay the damages within 30 days allows the steam host to draw on the letter of credit for the amount of damages suffered by LDC.
In September 2001, Credit Suisse/First Boston notified the Partnership of its intention not to extend the term of this letter of credit, which expired on November 22, 2002. This letter of credit, which was drawn by LDC on November 14, 2002 and is held in an escrow account, is included in noncurrent assets as investments held by trustee, restricted funds, on the accompanying consolidated balance sheet. Repayment of this seven year term loan is payable in fourteen semi-annual installments of $970,900 with a prepayment provision of any outstanding loan amount before cash would be available for distribution to the Partners. Payments for interest of $34,236 and principal of $105,811 were made in December 2002. Commitment fees of $132,917, $139,409 and $137,818 were paid relating to this letter of credit in 2002, 2001, and 2000, respectively.
Debt Service Reserve Letter of Credit
On November 22, 1994, the Partnership also entered into a debt service reserve letter of credit and reimbursement agreement with BNP Paribas (formerly known as Banque Nationale de Paris) pursuant to which a debt service reserve letter of credit in the amount of approximately $60,000,000 was issued. Such agreement has a rolling term of five years subject to extension at the discretion of the banks named in the agreement. Drawings on the debt service reserve letter of credit are available to pay principal and interest on the First Mortgage Bonds, the 1994 Tax-Exempt Bonds and interest on any loans created by drawings on such debt service reserve letter of credit. Cash and other investments held in the debt service reserve account will be drawn on prior to any drawings on the debt service reserve letter of credit. On January 11, 1999, pursuant to the Disbursement Agreement, which outlines the order of priority that project funds held by the trustee are to be disbursed, the Debt Service Reserve Letter of Credit was reduced to $29,925,906.
BNP Paribas notified the Partnership on May 18, 2001 of its intention not to extend the term of the agreement, which expires on November 22, 2005. The Partnership has been unable to find an issuer to replace BNP Paribas which meets the credit requirements under the Indenture. Pursuant to the terms of the Disbursement Agreement, available cash flows are required to be deposited on a monthly basis beginning on May 22, 2002 into a debt service reserve account or a tax exempt debt service reserve account, as the case may be, until the required balance in the debt service reserve account is achieved, which is $29,858,906 per the Disbursement Agreement. No distributions are allowed to the partners until such balance is funded. No funds have been deposited as of December 31, 2002. Commitment fees of $409,611, $409,611, and $410,733 were paid on this letter of credit in 2002, 2001, and 2000, respectively.
38
Financial Covenants
�� In connection with the various agreements discussed above, certain financial covenants must be met and reported on a quarterly and/or annual basis as required by debtors.
5. PURCHASE AGREEMENTS:
Coal Purchase and Transportation Agreement
The Partnership entered into a 30-year purchase contract with Lodestar (formerly known as Costain Coal, Inc.), commencing from the first day of the calendar month following the Commercial Operation Date, for the purchase of the Facility's annual coal requirements at a price defined in the agreement, as well as for the disposal of ash residue. The Partnership has no obligation to purchase a minimum quantity of coal under this agreement.
On June 8, 1998, the Partnership entered into a three-year agreement with Lodestar, which established an arrangement for the Partnership's disposal of ash at alternative locations. The Partnership also entered a three-year agreement, with similar terms, with VFL Technology Corporation for the disposal of ash, which expired in 2002.
Lodestar Energy, Inc. and its parent Lodestar Holding, Inc. filed for voluntary Chapter 11 bankruptcy on April 26, 2001. On October 16, 2001 the Partnership and Lodestar agreed to and executed Amendment No. 3 to the Coal Purchase Agreement. The principal change effected in the Agreement by Amendment No. 3 is an increase from $26.632 to $34.00 per ton in the base coal price with a 2% additional increase in the base price effective October 16, 2002. The Amendment also includes market price reopener provisions, beginning October 16, 2003, and a revision to Section 10.2 of the Agreement whereby the Partnership shall provide to Lodestar for disposal no less than fifty (50) percent and no more than seventy-five (75) percent of the Ash Residue produced annually at the Facility.
In December 2002, an order by the U.S. Bankruptcy Court was issued authorizing Lodestar to sell its property at auction, which occurred on January 30, 2003. The Coal Purchase and Transportation Agreement was included in the property auctioned. A bid was made for the property, including the agreement with the Partnership. At a court hearing to certify the auction, the highest bidder rescinded their bid, claiming information was withheld during their due diligence before the auction. Since most of the officers and directors of Lodestar resigned prior to the court hearing, the judge appointed a trustee for Lodestar who will advise the court on the next course of action to pursue. The Partnership continues to receive coal shipments from Lodestar.
39
On January 28, 2003, the Partnership provided written notice to Lodestar that Lodestar had failed to comply with certain of its obligations under the Coal Supply Agreement as it pertains to ash disposal and that unless remedied, such failure of Lodestar would mature into an event of default under the Coal Supply Agreement and allow the Partnership to terminate the Coal Supply Agreement and seek to enforce the remedies available to the Partnership under the Coal Supply Agreement and applicable law. Lodestar has indicated to the Partnership that Lodestar believes that it is in compliance with its obligations under the Coal Supply Agreement. The Partnership currently anticipates that if the Coal Supply Agreement with Lodestar is terminated for the reasons set forth in the Partnership's notice to Lodestar or otherwise, such termination will not in and of itself have a material and adverse effect on the Partnership as other sources of coal supply and ash disposal are available to the Partnership. The Partnership has executed a back-up coal supply agreement (the "Back-up Coal Agreement") and an alternative ash disposal agreement (the "Ash Disposal Agreement") with other companies. This agreement, when effective, combined with other current ash disposal agreements will allow the Partnership to dispose of all of the Partnership's ash without relying on Lodestar. The Back-up Coal Agreement and Ash Disposal Agreement cannot become effective until the applicable conditions under the Partnership's financing documents are satisfied. The Partnership currently anticipates that all applicable conditions under such financing documents will be completed in the near future and in any case, in advance of any potential termination of the Coal Supply Agreement.
The Back-up Coal Agreement was executed on February 5, 2003 between the Partnership and Massey Coal Sales, Inc. ("Massey"). Under the Back-up Coal Agreement, Massey will provide coal under substantially similar terms to the Coal Supply Agreement should Lodestar be unable to perform under the Coal Supply Agreement or the Coal Supply Agreement with Lodestar is otherwise terminated. The base coal price is $33.75 per ton and the term is through December 31, 2025. The agreement also includes market price reopener provisions, beginning October 16, 2003.
The Ash Disposal Agreement was executed on February 1, 2003 between the Partnership and VFL Technology Corp. ("VFL") and has a term of four years with an option for an additional two years. The agreement calls for the nominal removal of 1,000 to 1,500 tons of dry fly ash per week, which is approximately 50% of the fly ash produced each week, and allows for the removal of up to 100% of the fly ash produced at Indiantown. The disposal fee is $21.85 per ton and is adjusted quarterly beginning on May 1, 2003 in accordance with a Producer Price Index, which includes labor to load trucks, the transportation vehicles, transportation costs and disposal fee.
Lime Purchase Agreement
On May 1, 1992, the Partnership entered into a lime purchase agreement with Chemical Lime Company of Alabama, Inc. ("Chemlime") for supply of the Facility's lime requirements for the Facility's dry scrubber sulfur dioxide removal system. The Partnership has no obligation to purchase a minimum quantity of lime under the agreement. The initial term of the agreement is 15 years from the Commercial Operation Date and may be extended for a successive 5-year period. Either party may cancel the agreement after January 1, 2000, upon proper notice. The price of lime was renegotiated in 1999 for a three-year period beginning January 1, 2000. By mutual agreement, the contract was renegotiated on October 30, 2001, for the period February 1, 2002 through February 1, 2004. The base price was $56.25 per ton to be annually adjusted per an agreed-upon formula.
Railcar Lease Agreement
The Partnership entered into a 15 year Car Leasing Agreement with GE Capital Railcar Services Corporation to furnish and lease 72 pressure differential hopper railcars to the Partnership for the transportation of fly ash and lime. The cars were delivered starting in April 1995, at which time the lease was recorded as a capital lease. The leased assets of $5,753,375 and accumulated depreciation of $2,935,139 and $2,551,580, respectively, are included in property, plant and equipment as of December 31, 2002 and 2001. Amortization expense related to the leased assets is included in depreciation expense. Payments of $629,856, including principal and interest, were made in 2002, 2001, and 2000.
40
Future minimum payments related to the Car Leasing Agreement as of December 31, 2002 are as follows:
2003 $629,856
2004 629,856
2005 629,856
2006 629,856
2007 629,856
Thereafter 1,485,055
---------
Total minimum lease payments 4,634,335
Interest portion of lease payable (1,047,247)
-----------
Present value of future
minimum lease payments 3,587,088
Current portion (383,131)
-----------
Long-term portion $3,203,957
===========
6. SALES AND SERVICES AGREEMENTS:
Power Purchase Agreement
On May 21, 1990, the Partnership entered into a Power Purchase Agreement ("PPA") with FPL for sales of the Facility's electric output. As amended, the agreement is effective for a 30-year period, commencing with the Commercial Operation Date. The pricing structure provides for both capacity and energy payments.
Capacity payments remain relatively stable because the amounts do not vary with dispatch. Price increases are contractually provided. Capacity payments include a bonus or penalty payment if actual capacity is in excess of or below specified levels of available capacity. Energy payments are derived from a contractual formula defined in the agreement based on the actual cost of domestic coal at another FPL plant, St. Johns River Power Park.
Energy Services Agreement
On September 30, 1992, the Partnership entered into an energy services agreement with Caulkins Indiantown Citrus Company ("Caulkins"). In September 2001, Caulkins sold its processing plant to Louis Dreyfus Citrus, Inc. ("LDC"). Commencing on the Commercial Operation Date and continuing throughout the 15-year term of the agreement, LDC is required to purchase the lesser of 525 million pounds of steam per year or the minimum quantity of steam per year necessary for the Facility to maintain its status as a Qualifying Facility under PURPA. The Facility declared Commercial Operation with LDC on March 1, 1996.
41
7. RELATED PARTY TRANSACTIONS:
Management Services Agreement
The Partnership has a Management Services Agreement with NEG, for the day-to-day management and administration of the Partnership's business relating to the Facility. The agreement commenced on September 30, 1992 and will continue through August 31, 2026. Compensation to NEG under the agreement includes an annual base fee of $650,000 (adjusted annually and is subordinate to debt service and certain other costs), wages and benefits for employees performing work on behalf of the Partnership and other costs directly related to the Partnership. Base fees of $578,468 were subordinated in 2002 pursuant to the Disbursement Agreement. Payments of $3,122,371, $4,167,428, and $4,324,042, in 2002, 2001, and 2000 were made to NEG, respectively. As of December 31, 2002 and 2001, the Partnership owed NEG $774,260 and $315,730, respectively, which are included in accounts payable and accrued liabilities in the accompanying consolidated balance sheets.
Operations and Maintenance Agreement
The Partnership has an Operation and Maintenance Agreement with PG&E OSC, for the operations and maintenance of the Facility for a period of 30 years (starting September 30, 1992). Thereafter, the agreement will be automatically renewed for periods of 5 years until terminated by either party with 12 months notice. If targeted plant performance is not reached on a monthly basis, PG&E OSC will pay liquidated damages to the Partnership. Compensation to PG&E OSC under the agreement includes an annual base fee of which a portion is subordinate to debt service and certain other costs, certain earned fees and bonuses based on the Facility's performance and reimbursement for certain costs including payroll, supplies, spare parts, equipment, certain taxes, licensing fees, insurance and indirect costs expressed as a percentage of payroll and personnel costs. The fees are adjusted quarterly by a measure of inflation as defined in the agreement. Base fees of $1,038,136 and earned fees of $343,421 were subordinated in 2002 pursuant to the Disbursement Agreement. Payments of $7,106,438, $9,326,634, and $9,921,638 were made to PG&E OSC in 2002, 2001, and 2000, respectively. As of December 31, 2002 and 2001, the Partnership owed PG&E OSC $2,067,724 and $683,897, respectively, which is included in accounts payable and accrued liabilities in the accompanying consolidated balance sheets.
Distribution to Partners
There were no distributions made to the Partners in 2002. Distributions totaling $12,400,000 and $25,400,000 were made to the Partners in 2001 and 2000, respectively.
42
8. FAIR VALUE OF FINANCIAL INSTRUMENTS
-----------------------------------
The following table presents the carrying amounts and estimated fair values of certain of the
Partnership's financial instruments as of December 31, 2002 and 2001.
December 31, 2002
- ------------------------------------------------------------------------------------------------------
Financial Liabilities Carrying Amount Fair Value
--------------------- --------------- ----------
Tax Exempt Bonds $125,010,000 $161,523,856
First Mortgage Bonds $432,107,562 $564,928,712
December 31, 2001
- ------------------------------------------------------------------------------------------------------
Financial Liabilities Carrying Amount Fair Value
--------------------- --------------- ----------
Tax Exempt Bonds $125,010,000 $130,409,212
First Mortgage Bonds $443,567,970 $447,410,766
For the Tax Exempt Bonds and First Mortgage Bonds, the fair values of the Partnership's bonds payable are based on the current market interest rates to estimate market values for the Tax Exempt Bonds and the First Mortgage Bonds.
The carrying amounts of the Partnership's cash and cash equivalents, accounts receivable, deposits, prepaid expenses, investments held by trustee, accounts payable and accrued liabilities and accrued interest approximate fair value, due to their short-term nature.
9. FOURTH QUARTER ADJUSTMENTS (UNAUDITED)
In the three-months ended December 31, 2002, the Partnership recorded additional electric energy revenue of $1,514,174 for additional 2002 payment estimated to be due from FPL in conjunction with the annual fuel audit conducted in the fourth quarter and performed under the PPA. The Partnership also recorded additional electric energy revenue of $1,218,890 for additional payments due from FPL related to the reconciliation of the quarterly unit energy costs calculations in 2002 under the PPA.
Item 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
43
PART III
Item 10 DIRECTORS AND EXECUTIVE OFFICERS
Indiantown Cogeneration, L.P. Board of Control
The following table sets forth the names, ages and positions of the members
of the Board of Control of the Partnership. Members of the Board of Control are
selected from time to time by, and serve at the pleasure of, the Partners of the
Partnership.
Name Age Position
---- --- --------
Scot A. Garner................. 33 Palm Representative and
Thaleia Representative
Thomas F. Schwartz ............ 41 Palm Representative and
Thaleia Representative
P. Chrisman Iribe.............. 52 IPILP Representative
Sanford L. Hartman............. 49 IPILP Representative
Scot A. Garner is Vice President - Asset Management for Cogentrix Energy, Inc. and has been with Cogentrix since 1999. Prior to joining Cogentrix Energy, Inc., Mr. Garner spent two years as a financial analyst at an electric and gas utility company. Mr. Garner holds a B.S. degree in mathematical economics and an M.B.A. from Wake Forest University.
Thomas F. Schwartz is Senior Vice President and Chief Financial Officer of Cogentrix Energy, Inc. He is responsible for the areas of corporate finance and tax planning. Mr. Schwartz joined Cogentrix Energy, Inc. in 1991, and has held various positions in accounting and finance. Prior to joining Cogentrix Energy, Inc., Mr. Schwartz was Audit Manager with Arthur Andersen, LLP. Mr. Schwartz holds a B.A. degree in accounting from the University of North Carolina - Charlotte.
P. Chrisman Iribe has been Executive Vice President of NEG, Inc. since December 2002. Prior to that he was President and Chief Operating Officer, Eastern Region since July 2000. He has also served as Senior Vice President of PG&E Corporation since December 16, 1998. Mr. Iribe previously served as President and Chief Operating Officer of PG&E Generating Company, one of NEG, Inc. subsidiaries, from November 1998 to January 2000. From September 1997 to November 1998, Mr. Iribe served as Executive Vice President and Chief Executive Officer of PG&E Generating Company (formerly known as U.S. Generating Company). Mr. Iribe held various other executive positions within U.S. Generating Company from 1989 to September 1997. Prior to Mr. Iribe's joining U.S. Generating Company in 1989, he was senior vice president for planning, state relations and public affairs at ANR Pipeline Company, a natural gas pipeline company. Mr. Iribe holds a B.A. degree in Economics from George Washington University.
Sanford L. Hartman has been Vice President and Chief Counsel of NEG, Inc. since December 2002. From March of 1999 until December 2002, Mr. Hartman was Vice President and General Counsel of PG&E Generating, now a subsidiary of NEG, Inc. From March 1999 until December 2002, he was NEG, Inc.'s Vice President and Associate General Counsel. Mr. Hartman has been employed by NEG, Inc. and its predecessors and subsidiaries since 1990. Prior to joining NEG, Inc., Hartman was counsel to Long Lake Energy Corporation, an independent power producer with headquarters in New York City and was an attorney with Bishop, Cook, Purcell & Reynolds, a Washington, D.C., law firm. Mr. Hartman has a BA in Political Science from Drew University and a JD from Temple University.
44
ICL Funding Corporation Board of Directors
The following table sets forth the names, ages and positions of the directors and executive officers of ICL Funding. Directors are elected annually and each elected director holds office until a successor is elected. Officers are elected from time to time by vote of the Board of Directors.
Name Age Position
----- ------ ---------
P. Chrisman Iribe 52 Director, President
Sanford L. Hartman 49 Director
Thomas E. Legro 51 Vice President, Controller and
Chief Accounting Officer
Item 11 REMUNERATION OF DIRECTORS AND OFFICERS
No cash compensation or non-cash compensation was paid in any prior year or is currently proposed to be paid in the current calendar year by ICL Funding or the Partnership to any of the officers and directors listed above. Accordingly, the Summary Compensation Table and other tables required under Item 402 of the Securities and Exchange Commission's Regulation S-K have been omitted, as presentation of such tables would not be meaningful.
Management services for the Partnership are being performed by NEG on a cost-plus basis in addition to the payment of a base fee. Operation and maintenance services for the Partnership will be performed by PG&E OSC on a cost-plus basis. In addition to a base fee, PG&E OSC may earn certain additional fees and bonuses based on specified performance criteria.
Item 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
Partnership interests in the Partnership, as of December 31, 2002, are held as follows:
Toyan 30.05% L.P.
IPILP 19.95% G.P.
Palm 10.00% G.P.
Thaleia 40.00% L.P.
All of the outstanding shares of common stock of ICL Funding are owned by the Partnership.
45
Item 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Partnership has several material contracts with affiliated entities. These contracts, which include the Construction Contract, the Management Services Agreement and the Operations and Maintenance Agreement, are described elsewhere in this report, most notably in Note 7 to the Partnership's consolidated financial statements.
Item 14 CONTROLS AND PROCEDURES
Based on an evaluation of the Partnership's disclosure controls and procedures conducted on February 6, 2003, the principal executive officer and principal financial officer of Indiantown Cogeneration, L.P. and Indiantown Cogeneration Funding Corporation have concluded that such controls and procedures effectively ensure that information required to be disclosed by the Partnership in reports the Partnership files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the SEC's rules and forms.
There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
46
PART IV
Item 15 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
----------------------------------------------------------------
a) Documents filed as of this Report Page
----
(1) Consolidated financial statements:
Report of Independent Auditors.......................... 23
Consolidated Balance Sheets as of
December 31, 2002 and 2001 ............................ 25
Consolidated Statements of Operations for the years
ended December 31, 2002, 2001 and 2000................. 27
Consolidated Statements of Changes
in Partners' Capital for the years ended
December 31, 2002, 2001 and 2000...................... 28
Consolidated Statements of Cash Flows for the
years ended December 31, 2002, 2001 and 2000.......... 29
Notes to Consolidated Financial
Statements............................................
(2) Consolidated Financial Statement
Schedules........................................ None
b) Reports on Form 8-K:
The Partnership filed a Report on Form 8-K on March 3, 2003 announcing the
execution of a back-up coal supply agreement and an alternate ash disposal
agreement.
c) Exhibits:
Exhibit
No. Description
--- -----------
3.1 Certificate of Incorporation of Indiantown Cogeneration Funding Corporation.*
3.2 By-laws of Indiantown Cogeneration Funding Corporation.*
3.3 Certificate of Limited Partnership of Indiantown Cogeneration, L.P.*
3.4 Amended and Restated Limited Partnership Agreement of Indiantown Cogeneration, L.P., among
Palm Power Corporation, Toyan Enterprises and TIFD III-Y Inc.*
3.5 Form of First Amendment to Amended and Restated Limited Partnership Agreement of Indiantown
Cogeneration, L.P.*
47
3.6 Dana Amendment to Amended and Restated Limited Partnership Agreement of Indiantown Cogeneration,
L.P.*****
3.7 Cogentrix Amendment to Amended and Restated Limited Partnership Agreement of Indiantown
Cogeneration, L.P.*****
3.8 Third Amendment to Amended and Restated Limited Partnership Agreement of Indiantown Cogeneration,
L.P.*****
4.1 Trust Indenture, dated as of November 1, 1994, among Indiantown Cogeneration Funding Corporation,
Indiantown Cogeneration, L.P., and NationsBank of Florida, N.A., as Trustee, and First Supplemental
Indenture thereto.**
4.2 Amended and Restated Mortgage, Assignment of Leases, Rents, Issues and Profits and Security
Agreement and Fixture Filing among Indiantown Cogeneration, L.P., as Mortgagor, and Bankers Trust
Company as Mortgagee, and NationsBank of Florida, N.A., as Disbursement Agent and, as when and to
the extent set forth therein, as Mortgagee with respect to the Accounts, dated as of November 1,
1994.**
4.3 Assignment and Security Agreement between Indiantown Cogeneration, L.P., as Debtor, and Bankers
Trust Company as Secured Party, and NationsBank of Florida, N.A., as Disbursement Agent and, as
when, and to the extent set forth therein, a Secured Party with respect to the Accounts, dated as of
November 1, 1994.**
10.1.1 Amended and Restated Indenture of Trust between Martin County Industrial Development Authority, as
Issuer, and NationsBank of Florida, N.A., as Trustee, dated as of November 1, 1994.**
10.1.2 Amended and Restated Authority Loan Agreement by and between Martin County Industrial Development
Authority and Indiantown Cogeneration, L.P., dated as of November 1, 1994.**
10.1.3 Letter of Credit and Reimbursement Agreement among Indiantown Cogeneration, L.P., as Borrower, and
the Banks Named Therein, and Credit Suisse, as Agent, dated as of November 1, 1994.**
10.1.4 Disbursement Agreement, dated as of November 1, 1994, among Indiantown Cogeneration, L.P.,
Indiantown Cogeneration Funding Corporation, NationsBank of Florida, N.A., as Tax-Exempt Trustee,
NationsBank of Florida, N.A., as Trustee, Credit Suisse, as Letter of Credit Provider, Credit
Suisse, as Working Capital Provider, Banque Nationale de Paris, as Debt Service Reserve Letter of
Credit Provider, Bankers Trust Company, as Collateral Agent, Martin County Industrial Development
Authority, and NationsBank of Florida, N.A., as Disbursement Agent.**
10.1.5 Revolving Credit Agreement among Indiantown Cogeneration, L.P., as Borrower, and the Banks Named
Therein, and Credit Suisse, as Agent, dated as of November 1, 1994.**
48
10.1.6 Collateral Agency and Intercreditor Agreement, dated as of November 1, 1994, among NationsBank of
Florida, N.A., as Trustee under the Trust Indenture, dated as of November 1, 1994, NationsBank of
Florida, N.A., as Tax-Exempt Trustee under the Tax Exempt Indenture, dated as of November 1, 1994,
Credit Suisse, as letter of Credit Provider, Credit Suisse, as Working Capital Provider, Banque
Nationale de Paris, as Debt Service Reserve Letter of Credit Provider, Indiantown Cogeneration,
L.P., Indiantown Cogeneration Funding Corporation, Martin County Industrial Development Authority,
NationsBank of Florida, N.A., as Disbursement Agent under the Disbursement Agreement dated as of
November 1, 1994, and Bankers Trust Company, as Collateral Agent.**
10.1.7 Amended and Restated Equity Loan Agreement dated as of November 1, 1994, between Indiantown
Cogeneration, L.P., as the Borrower, and TIFD III-Y Inc., as the Equity Lender.**
10.1.8 Equity Contribution Agreement, dated as of November 1, 1994, between TIFD III-Y Inc. and NationsBank
of Florida, N.A., as Disbursement Agent.**
10.1.9 GE Capital Guaranty Agreement, dated as of November 1, 1994, between General Electric Capital
Corporation, as Guarantor, and NationsBank of Florida, N.A., as Disbursement Agent.**
10.1.11 Debt Service Reserve Letter of Credit and Reimbursement Agreement among Indiantown Cogeneration,
L.P., as Borrower, and the Banks Named Therein, and Banque Nationale de Paris, as Agent, dated as of
November 1, 1994.**
10.2.18 Amendment No. 2 to Coal Purchase Agreement, dated as of April 19, 1995.***
10.2.19 Fourth Amendment to Energy Services Agreement, dated as of January 30, 1996.****
10.2.20 Third Amendment to the Agreement for the Purchase of Firm Capacity and Energy, dated as of May 17,
2001.******
10.2.21 Third Amendment to Coal Purchase Agreement, dated as of November 2, 2001.*******
10.2.22 Dry Scrubber Ash Service Agreement, dated as of February 1, 2003.
10.2.23 Back-up Coal Purchase and Sale Agreement, dated as of February 5, 2003.
21 Subsidiaries of Registrant*
99 Copy of Registrants' press release dated January 3, 1996.****
99.1 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350 dated March 31, 2003
99.2 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350 dated March 31, 2003
49
99.3 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350 dated March 31, 2003
99.4 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350 dated March 31, 2003
______________________________
* Incorporated by reference from the Registrant Statement on Form S-1, as
amended, file no. 33-82034 filed by the Registrants with the SEC in July 1994.
** Incorporated by reference from the quarterly report on Form 10-Q, file no.
33-82034 filed by the Registrants with the SEC in December 1994.
*** Incorporated by reference from the quarterly report on Form 10-Q, file no.
33-82034 filed by the Registrants with the SEC in May 1995. **** Incorporated by
reference from the current report on Form 8-K, file no. 33-82034 filed by the
Registrants with the SEC in January 1996.
***** Incorporated by reference from the quarterly report on Form 10-Q file no.
33-82034 filed by the Registrants with the SEC in August 1999. ******
Incorporated by reference from the current report on Form 8-K file no. 33-82034
filed by the Registrants with the SEC in January 2001.
******* Incorporated by reference from the current report on Form 8-K file no.
33-82034 filed by the Registrants with the SEC in November 2001.
50
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the co-registrant has duly caused this Form 10-K to be signed on its behalf by
the undersigned, thereunto duly authorized, in the city of Bethesda, state of
Maryland, on March 31, 2003.
INDIANTOWN COGENERATION, L.P.
Date: March 31, 2003 /s/ Thomas E. Legro
-----------------------------------
Name: Thomas E. Legro
Title: Vice President, Controller and
Principal Accounting Officer
Pursuant to the requirements of the Securities Act of 1933, this Form
10-K has been signed by the following persons in the capacities and on the dates
indicated.
Signature Title Date
- --------- ----- ----
/s/ P. Chrisman Iribe Member of Board of Control, March 31, 2003
- ---------------------- President and Secretary
P. Chrisman Iribe
/s/ Thomas E. Legro Vice President, Controller March 31, 2003
- ------------------- and Principal Accounting
Thomas E. Legro Officer
/s/ Scot A. Garner Member of Board of Control March 31, 2003
- ----------------------
Scot A. Garner
/s/ Thomas F. Schwartz Member of Board of Control March 31, 2003
- ----------------------
Thomas F. Schwartz
/s/ Sanford L. Hartman Member of Board of Control March 31, 2003
- ---------------------- and Senior Vice President
Sanford L. Hartman
51
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the co-registrant has duly caused this Form 10-K to be signed on its behalf by
the undersigned, thereunto duly authorized, in the city of Bethesda, state of
Maryland, on March 31, 2003.
INDIANTOWN COGENERATION
FUNDING CORPORATION
Date: March 31, 2003 /s/ Thomas E. Legro
-----------------------------------
Name: Thomas E. Legro
Title: Vice President, Controller and Chief
Accounting Officer
Pursuant to the requirements of the Securities Act of 1933, this Form
10-K has been signed by the following persons in the capacities and on the dates
indicated.
Signature Title Date
- --------- ----- ----
/s/ P. Chrisman Iribe Director and President March 31, 2003
- ----------------------
P. Chrisman Iribe
/s/ Thomas E. Legro Vice President, Controller March 31, 2003
- ---------------------- and Chief Accounting Officer
Thomas E. Legro
52
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this annual report on Form 10-K of Indiantown Cogeneration,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003
/s/ P. CHRISMAN IRIBE
----------------------
P. Chrisman Iribe
President
Indiantown Cogeneration, L.P.
53
CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, Thomas E. Legro, certify that:
1. I have reviewed this annual report on Form 10-K of Indiantown Cogeneration,
L.P.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003
/s/ THOMAS E. LEGRO
-------------------------------------
Thomas E. Legro
Vice President, Controller and Principal Accounting
Officer
Indiantown Cogeneration, L.P.
54
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this annual report on Form 10-K of Indiantown Cogeneration
Funding Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003
/s/ P. CHRISMAN IRIBE
---------------------------------
P. Chrisman Iribe
President
Indiantown Cogeneration Funding Corporation
55
CERTIFICATION OF THOMAS E. LEGRO, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES - OXLEY ACT OF 2002
I, Thomas E. Legro, certify that:
1. I have reviewed this annual report on Form 10-K of Indiantown Cogeneration
Funding Corporation;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 31, 2003
/s/ THOMAS E. LEGRO
--------------------------------
Thomas E. Legro
Vice President, Controller and Chief Accounting
Officer
Indiantown Cogeneration Funding Corporation
56
EXHIBIT INDEX
Exhibit No. Description
- --- -----------
3.1 Certificate of Incorporation of Indiantown Cogeneration Funding
Corporation.*
3.2 By-laws of Indiantown Cogeneration Funding Corporation.*
3.3 Certificate of Limited Partnership of Indiantown Cogeneration, L.P.*
3.4 Amended and Restated Limited Partnership Agreement of Indiantown
Cogeneration, L.P., among Palm Power Corporation, Toyan Enterprises
and TIFD III-Y Inc.*
3.5 Form of First Amendment to Amended and Restated Limited Partnership
Agreement of Indiantown Cogeneration, L.P.*
3.9 Dana Amendment to Amended and Restated Limited Partnership Agreement
of Indiantown Cogeneration, L.P.*****
3.10 Cogentrix Amendment to Amended and Restated Limited Partnership
Agreement of Indiantown Cogeneration, L.P.*****
3.11 Third Amendment to Amended and Restated Limited Partnership Agreement
of Indiantown Cogeneration, L.P.*****
4.1 Trust Indenture, dated as of November 1, 1994, among Indiantown
Cogeneration Funding Corporation, Indiantown Cogeneration, L.P., and
NationsBank of Florida, N.A., as Trustee, and First Supplemental
Indenture thereto.**
4.2 Amended and Restated Mortgage, Assignment of Leases, Rents, Issues and
Profits and Security Agreement and Fixture Filing among Indiantown
Cogeneration, L.P., as Mortgagor, and Bankers Trust Company as
Mortgagee, and NationsBank of Florida, N.A., as Disbursement Agent
and, as when and to the extent set forth therein, as Mortgagee with
respect to the Accounts, dated as of November 1, 1994.**
4.3 Assignment and Security Agreement between Indiantown Cogeneration,
L.P., as Debtor, and Bankers Trust Company as Secured Party, and
NationsBank of Florida, N.A., as Disbursement Agent and, as when, and
to the extent set forth therein, a Secured Party with respect to the
Accounts, dated as of November 1, 1994.**
10.1.1 Amended and Restated Indenture of Trust between Martin County
Industrial Development Authority, as Issuer, and NationsBank of
Florida, N.A., as Trustee, dated as of November 1, 1994.**
10.1.2 Amended and Restated Authority Loan Agreement by and between Martin
County Industrial Development Authority and Indiantown Cogeneration,
L.P., dated as of November 1, 1994.**
57
10.1.3 Letter of Credit and Reimbursement Agreement among Indiantown
Cogeneration, L.P., as Borrower, and the Banks Named Therein, and
Credit Suisse, as Agent, dated as of November 1, 1994.**
10.1.4 Disbursement Agreement, dated as of November 1, 1994, among Indiantown
Cogeneration, L.P., Indiantown Cogeneration Funding Corporation,
NationsBank of Florida, N.A., as Tax-Exempt Trustee, NationsBank of
Florida, N.A., as Trustee, Credit Suisse, as Letter of Credit
Provider, Credit Suisse, as Working Capital Provider, Banque Nationale
de Paris, as Debt Service Reserve Letter of Credit Provider, Bankers
Trust Company, as Collateral Agent, Martin County Industrial
Development Authority, and NationsBank of Florida, N.A., as
Disbursement Agent.**
10.1.5 Revolving Credit Agreement among Indiantown Cogeneration, L.P., as
Borrower, and the Banks Named Therein, and Credit Suisse, as Agent,
dated as of November 1, 1994.**
10.1.6 Collateral Agency and Intercreditor Agreement, dated as of November 1,
1994, among NationsBank of Florida, N.A., as Trustee under the Trust
Indenture, dated as of November 1, 1994, NationsBank of Florida, N.A.,
as Tax-Exempt Trustee under the Tax Exempt Indenture, dated as of
November 1, 1994, Credit Suisse, as letter of Credit Provider, Credit
Suisse, as Working Capital Provider, Banque Nationale de Paris, as
Debt Service Reserve Letter of Credit Provider, Indiantown
Cogeneration, L.P., Indiantown Cogeneration Funding Corporation,
Martin County Industrial Development Authority, NationsBank of
Florida, N.A., as Disbursement Agent under the Disbursement Agreement
dated as of November 1, 1994, and Bankers Trust Company, as Collateral
Agent.**
10.1.7 Amended and Restated Equity Loan Agreement dated as of November 1,
1994, between Indiantown Cogeneration, L.P., as the Borrower, and TIFD
III-Y Inc., as the Equity Lender.**
10.1.8 Equity Contribution Agreement, dated as of November 1, 1994, between
TIFD III-Y Inc. and NationsBank of Florida, N.A., as Disbursement
Agent.**
10.1.9 GE Capital Guaranty Agreement, dated as of November 1, 1994, between
General Electric Capital Corporation, as Guarantor, and NationsBank of
Florida, N.A., as Disbursement Agent.**
10.1.11 Debt Service Reserve Letter of Credit and Reimbursement Agreement
among Indiantown Cogeneration, L.P., as Borrower, and the Banks Named
Therein, and Banque Nationale de Paris, as Agent, dated as of November
1, 1994.**
10.2.18 Amendment No. 2 to Coal Purchase Agreement, dated as of April 19,
1995.***
10.2.19 Fourth Amendment to Energy Services Agreement, dated as of January 30,
1996.****
10.2.20 Third Amendment to the Agreement for the Purchase of Firm Capacity and
Energy, dated as of May 17, 2001.******
58
10.2.21 Third Amendment to Coal Purchase Agreement, dated as of November 2,
2001.*******
10.2.22 Dry Scrubber Ash Service Agreement, dated as of February 1, 2003.
10.2.23 Back-up Coal Purchase and Sale Agreement, dated as of February 5,
2003.
21 Subsidiaries of Registrant*
99 Copy of Registrants' press release dated January 3, 1996.****
99.1 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350
dated March 31, 2003
99.2 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350
dated March 31, 2003
99.3 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section 1350
dated March 31, 2003
99.4 Certification of Thomas E. Legro pursuant to 18 U.S.C. Section 1350
dated March 31, 2003
