SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2003

Commission File Number 33-82034

INDIANTOWN COGENERATION, L.P.

INDIANTOWN COGENERATION FUNDING CORPORATION

(Exact name of co-registrant as specified in its charter)

7600 Wisconsin Avenue

(301) 280-6800

SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g) OF THE ACT:
None

Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.   x Yes o 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 registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.x

Indicate by check mark whether the registrants are accelerated filers (as defined in Exchange Act Rule 12b-2)   oYes x No

As of March 30, 2004, there were 100 shares of common stock of Indiantown Cogeneration Funding Corporation, $1 par value outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
None

Indiantown Cogeneration, L.P.
Indiantown Cogeneration Funding Corporation
Table of Contents

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”) under a Power Purchase Agreement (“PPA”). The Facility also supplies steam to Louis Dreyfus Citrus, Inc. (“LDC”), formerly known as Caulkins Indiantown Citrus Company, under an Energy Services Agreement (“ESA”). 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 in the attached Notes to the Financial Statements. ICL Funding has no separate operations and has only $100 in assets.

The original general partners were Toyan Enterprises (“Toyan”), a California corporation and a wholly owned special purpose indirect subsidiary of National Energy & Gas Transmission, Inc. (“NEGT”, formerly known as PG&E National Energy Group, 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”).

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. (together with its subsidiaries, “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.

Cogentrix was acquired by GS Power Holdings LLC (“GSPHLLC”), a subsidiary of The Goldman Sachs Group, Inc. GSPHLLC purchased 100% of the stock of Cogentrix in December 2003.

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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:

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 began construction of the Facility in October 1992 and was in the development phase through the commencement of commercial operation. 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 Facility commenced commercial operation under its PPA with FPL on December 22, 1995. The Partnership’s continued existence is dependent on the ability of the Partnership to maintain successful commercial operation under the PPA. 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 National Energy & Gas Transmission, Inc.

The Partnership is managed by Power Services Company (“PSC”, formerly known as PG&E National Energy Group Company), pursuant to a Management Services Agreement (the “MSA”). The Facility is operated by U.S. Operating Services Company (“OSC”, formerly known as PG&E Operating Services Company), pursuant to an Operation and Maintenance Agreement (the “O&M Agreement”). PSC and OSC are general partnerships indirectly wholly owned by National Energy & Gas Transmission, Inc. (“NEGT”, formerly known as PG&E National Energy Group, Inc.), an indirect subsidiary of PG&E Corporation. Refer to Note 7 in the attached Notes to the Financial Statements for discussion of contractual terms.

On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”).

Neither the Partnership nor any of its NEGT affiliated partners, including Toyan and IPILP, or PSC and OSC, are parties to the filings by NEGT or other affiliates for protection under the NEGT Bankruptcy. The Partnership believes that it will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT and the NEGT Bankruptcy does not result in an event of default under the principal project contracts or the principal financing documents of the facility.

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On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (“POR”). The POR contemplates that NEGT will retain and continue to operate its power generation and pipeline businesses unless they are sold (as described in the POR), separate from PG&E Corporation, and issue new debt securities and common stock. NEGT’s indirect ownership interest in the Partnership is included within its power generation business. Any sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) may affect management’s MSA contract with the Partnership. There can be no certainty that a NEGT Interest Sale will be completed.

On December 30, 2003, Moody’s confirmed the senior secured debt of the Partnership at Ba1 and changed the rating outlook to stable from negative. Moody’s stated that this rating action reflects the project’s improved financial performance during 2003 and the expectations that the debt service coverage ratios for the next several years will remain in the 1.30x to 1.40x range. The rating action also incorporates the Partnership’s improved liquidity profile due to the completion of new letter of credit and working capital facilities during October 2003 and the progress being made to negotiate a new coal price index with the coal supplier.

On July 8, 2003, Standard and Poor’s (“S&P”) issued a press release announcing that it had lowered its corporate credit ratings on two of NEGT’s subsidiaries. S&P stated these ratings actions followed the NEGT Bankruptcy. S&P further stated that the rating on ICL Funding was not affected by the ratings action on NEGT because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEGT. Therefore, S&P concluded that the incentive to consolidate it in a bankruptcy of NEGT was low.

On March 19, 2004 S&P placed its BBB- rating on the debt of ICL Funding on Credit Watch with negative implications. The credit watch reflects the risk of a downgrade if the PPA negotiations with FPL regarding a new energy payment index are not resolved to mitigate the current mismatch between energy revenues and fuel expenses (see “Executive Summary”, included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations below).

Certain Project Contracts

Power Purchase Agreement

The Facility supplies (i) electric generating capacity and energy to FPL pursuant to the PPA and (ii) steam to LDC pursuant to a long-term ESA.

Payments from FPL pursuant to the PPA provided approximately 99.9%, 99.8% and 99.8% of Partnership revenues for 2003, 2002 and 2001, respectively. Under and subject to the terms of the PPA, FPL is obligated to purchase electric generating capacity made available to it and associated energy from the Facility through December 22, 2025.

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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 made by FPL in 2003 were not 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 “Coal Purchase and Transportation Agreement” below). The energy payments will continue to be insufficient to cover the variable costs of steam production for steam supplied to LDC.

The Partnership does not expect these shortfalls 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 Federal Energy Regulatory Commission’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 ESA 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 Qualifying Facility status under PURPA.

Coal Purchase and Transportation Agreement

A Coal Purchase and Sales Agreement (the “Coal Purchase Agreement’) was executed on February 5, 2003 between the Partnership and Massey Coal Sales, Inc. (“Massey”) and became effective on April 1, 2003. Under the Coal Purchase Agreement, which remains in effect until December 31, 2025, the base coal price was $33.75 per ton with a market price reopener provision, which began in October 2003. The Partnership has no obligation to purchase a minimum quantity of coal.

The First Amendment (the “Amendment”) to the Coal Purchase Agreement between Massey and the Partnership was entered into on August 21, 2003, with an effective date of August 1, 2003. The principal change effected in the Coal Purchase Agreement was a decrease from $33.75 to $33.00 per ton in the base coal price with a market price reopener provision beginning the earlier of ninety days after the Partnership successfully negotiates a new fuel index under the PPA or October 1, 2005. Currently, the fuel index used to determine the coal cost component of the monthly energy payment from FPL under the PPA is no longer in effect. Within ninety days after the Partnership successfully negotiates a new fuel index under the

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PPA, the Partnership and Massey will utilize commercially reasonable best efforts to develop a coal price tied to a fuel index agreeable to both parties. The Partnership satisfied the applicable conditions precedent set forth in the financing documents relating to the Amendment.

The Partnership and CSX entered into a Coal Transportation Agreement dated August 6, 2003, under which CSX will deliver coal to the Facility through December 31, 2025 at the system car rate of $23.09 per ton, which is approximately 30% less than the current tariff rates for delivered coal. This system car rate is adjusted quarterly using the same index that adjusts the remaining costs component of the energy payment from FPL. CSX will also transport a minimum of 500 carloads of ash to an acceptable disposal firm on the CSX rail system. An agreement became effective March 15, 2004 between the Partnership, CSX and Allied Services, LLC to transport and dispose of ash through May 31, 2006 at a rate of $25.65 per ton, which will increase by 2% from the rate charged for the prior year. In addition, CSX rebated the Partnership $3.8 million in October 2003, which was the difference between the tariff rates and system car rates for all coal shipments for the period from April 1, 2003 through the effective date of the Coal Transportation Agreement, less $1.1 million in pre-petition and gap debt owed to CSX from LEI. CSX assigned to the Partnership their claim to the $1.1 million due from LEI under the Transportation Agreement. The Partnership satisfied the applicable conditions precedent set forth in the financing documents relating to the Coal Transportation Agreement.

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 PPA, 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.

Regulations and Environmental Matters

The Partnership has obtained all material environmental permits and approvals required, as of December 31, 2003, 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

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such permits and approvals or the renewal of currently issued permits. The Partnership timely filed its application for a Title V air permit on February 23, 2004.

Employees

The Partnership has no employees and does not anticipate having any employees in the future because, under a management services agreement, PSC 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, 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

The Partnership is currently not involved in any legal proceedings.

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 2003.

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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 (in thousands) are derived from the consolidated financial statement information of the Partnership as of and for the years ended December 31, 2003, 2002, 2001, 2000, and 1999. The data should be read in conjunction with Item 7 of this report, “Management’s Discussion and 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.

(1)

If this statement had been adopted on January 1, 2002 the pro forma effects on earnings of the accounting change for prior years would not have been material

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Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

Cautionary Statement Regarding Forward-Looking Statements

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.

The information in this Annual Report on Form 10-K includes forward-looking statements 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 and constitute forward-looking statements under the Private Securities Litigation Reform Act of 1995. 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 fuel prices and any mismatch between the actual energy costs and the energy revenue reimbursement of those costs; unanticipated changes in operating expenses or capital expenditures or other maintenance activities; variations in weather and natural disasters; and the potential impacts of threatened or actual terrorism and war.

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 potential future failure of the Partnership to maintain the qualifying facility status, which failure could cause a default under the PPA.

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.

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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 including changes in corporate governance and securities laws requirements.

Litigation and Environmental Matters

The Partnership’s future results of operation and financial condition may be affected by compliance with existing and future environmental and safety laws, regulations and policies, the cost of which could be significant, and the outcome of any potential future litigation and environmental matters.

Business Description

The Partnership is primarily engaged in the ownership and operation of a non-utility electric generating facility. From its inception and until December 21, 1995, the Partnership was in the development stage and had no operating revenues or expenses. On December 22, 1995 the Facility commenced commercial operation. 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 agreement 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.

Executive Summary

During 2003, the Facility’s operating performance was solid in a challenging business environment which included the Partnership successfully replacing its fuel supply agreement due to the bankruptcy of its previous coal supplier, Lodestar Energy, Inc. (“LEI”). This issue also caused the Partnership to pursue alternate means to dispose of ash, since LEI was disposing approximately 50% of the ash generated from the facility. The Partnership received the maximum amount for its capacity bonus payments from FPL. The electric energy payments in 2003 were not sufficient to cover the Partnership’s variable costs of electric energy production. 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. In addition, the fuel index used to determine the coal cost component of the monthly energy payment under the PPA is no longer in effect. The Partnership generated net income of $13.7 million and cash flows from operations of $32.1 million during 2003. The increase in earnings and cash flows from operations was primarily due to higher capacity bonus revenues and lower operating and maintenance expenses. The successful replacement of certain letters of credit and the working capital facility enabled the Partnership to distribute $20.0 million, the first distribution since June 2001.

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In accordance with the terms of the PPA, the Partnership has scheduled the Facility for four weeks of maintenance outages during 2004, which was for the same duration experienced during 2003. Since the scope and duration of the scheduled maintenance outages for 2004 is comparable to those experienced during 2003, the Partnership expects maintenance expenses to be the same in 2004 as compared to 2003.

The Partnership and FPL have been in discussions to resolve both the energy price and the replacement index issues. The Partnership is including its coal supplier, Massey, in the process to achieve a similar index on both sides of its supply and purchase agreements.

Relationship with NEGT

On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”).

Neither the Partnership nor any of its NEGT affiliated partners, including Toyan and IPILP, or PSC and OSC, are parties to the NEGT Bankruptcy. The Partnership believes that it will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT and the NEGT Bankruptcy does not result in an event of default under the principal project contracts or the principal financing documents of the facility.

On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (“POR”). The POR contemplates that NEGT will retain and continue to operate its power generation and pipeline businesses unless they are sold (as described in the POR), separate from PG&E Corporation, and issue new debt securities and common stock. NEGT’s indirect ownership interest in the Partnership is included within its power generation business. Any sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) may affect management’s MSA contract with the Partnership. There can be no certainty that a NEGT Interest Sale will be completed.

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Results of Operations

The following table sets forth operating revenue and related data for the years ended December 31, 2003 and 2002 (dollars and volumes in millions).

(1) The Average Capacity Billing Factor (“CBF”) measures the overall availability of the Facility, giving a heavier weighting to on-peak availability.

(2) The Average Dispatch Rate is the amount of electric energy produced in a given period expressed as a percentage of the total contract capability amount of potential electric energy production in that time period.

Year ended December 31, 2003 Compared to the Year Ended December 31, 2002

Overall Results

Net income was $13.7 million and $3.4 million for the twelve months ended December 31, 2003 and 2002, respectively. Cash flows during 2003 and 2002 were sufficient to fund all operating expenses and debt repayment obligations.

Operating Revenues

For the years ended December 31, 2003 and 2002, the Partnership had total operating revenues of $182.4 million and $162.7 million, respectively. This increase in 2003 was attributable primarily to increased energy revenues of $8.1 million and increased capacity bonus and capacity revenues of $11.6 million. For the years ended December 31, 2003 and 2002, the Facility achieved an average CBF of 97.88% and 89.95%, respectively. This resulted in earning monthly capacity payments aggregating $113.9 million for 2003 and $113.4 million for 2002. Bonuses aggregated $11.3 million for the year in 2003 and $0.2 million for 2002. 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 increase in bonus revenues

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is due to the increase in the average CBF, which was negatively impacted in 2002 by the decreased availability due to boiler tube leaks and the generator repairs in 2001. The calculation to compute the CBF (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 increase in energy revenues are due primarily to the absence in 2003 of an additional six weeks of scheduled outage time allowed in 2002 under the PPA to perform major maintenance. During 2003 and 2002, the Facility was dispatched by FPL and generated 2,419,994 megawatt-hours and 2,079,781 megawatt-hours, respectively. The monthly average dispatch rate requested by FPL was 90.94% and 88.96% for the twelve months ended December 31, 2003 and 2002, respectively.

Cost of Revenues

Total operating costs were $115.5 million and $106.1 million for the years ended December 31, 2003 and 2002, respectively. Fuel and ash costs increased by $11.6 million due primarily to the absence in 2003 of an additional six weeks of scheduled outage time allowed in 2002 under the PPA to perform major maintenance. General and administrative costs increased by $0.7 million due to the legal and consulting costs associated with the termination of the Coal Purchase Agreement with Lodestar Energy, Inc. Offsetting the increase in operating costs is a decrease of $2.7 million in operating and maintenance costs relating to the generator rewind performed in the 2002 scheduled major outage and a decrease in insurance and taxes of $0.2 million. The total net non-operating expense was approximately $53.2 million for both the years ended December 31, 2003 and 2002.

As of December 31, 2003 and 2002, the Partnership had approximately $584.8 million and $599.9 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, 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 89.95% and 97.02%, respectively. This resulted in earning monthly capacity payments aggregating $113.4 million in 2002 and $113.2 million in 2001. Bonuses aggregated $0.2 million in 2002 and $9.0 million 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

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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.

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.

Liquidity and Capital Resources

Net cash provided by operating activities in 2003 was $32.1 million as compared to $17.8 million in 2002. 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 increase in net cash from operations in 2003 is primarily related to the increase in net income of $10.3 million in 2003, a decrease in inventories and fuel reserves of $1.5 million, a decrease in accounts receivable of $4.5 million and an increase in depreciation, amortization and accretion of $0.8 million. These increases were offset by a decrease in accounts payable and accrued liabilities of $2.6 million.

Net cash provided by investing activities in 2003 was $16.2 million as compared to net cash used in investing activities of $15.9 million in 2002. Net cash flows provided by investing activities represent decreases in investments held by trustee. Net cash flows used in investing activities represent net additions to plant and equipment and increases in investments held by trustee.

Net cash used in financing activities in 2003 was $47.1 million as compared to $1.9 million in 2002. Net cash flows used in financing activities in 2003 and 2002 primarily represent payments on First Mortgage Bonds, cash distributions to Partners, the borrowings and

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repayments of the loans drawn under the previous letter of credit agreement and the borrowings and repayments under the existing revolving credit agreement. The increase in cash used in financing activities is attributable to the Partnership’s replacement of several letters of credit, as discussed below.

Credit Ratings

On December 30, 2003, Moody’s confirmed the senior secured debt of the Partnership at Ba1 and changed the rating outlook to stable from negative. Moody’s stated that this rating action reflects the project’s improved financial performance during 2003 and the expectations that the debt service coverage ratios for the next several years will remain in the 1.30x to 1.40x range. The rating action also incorporates the Partnership’s improved liquidity profile due to the completion of new letter of credit and working capital facilities during October 2003 and the progress being made to negotiate a new coal price index with the coal supplier.

On July 8, 2003, Standard and Poor’s (“S&P”) issued a press release announcing that it had lowered its corporate credit ratings on two of NEGT’s subsidiaries. S&P stated these ratings actions followed the NEGT Bankruptcy. S&P further stated that the rating on ICL Funding was not affected by the ratings action on NEGT because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEGT. Therefore, S&P concluded that the incentive to consolidate it in a bankruptcy of NEGT is low. S&P’s rating of the Partnership’s debt remains at “BBB- with a negative outlook”.

On March 19, 2004 S&P placed its BBB- rating on the debt of ICL Funding on Credit Watch with negative implications. The credit watch reflects the risk of a downgrade if the PPA negotiations with FPL regarding a new energy payment index are not resolved to mitigate the current mismatch between energy revenues and fuel expenses.

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

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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 2003 were $769 million. The equity loan of $139 million was repaid on December 26, 1995. As of December 31, 2003, 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 (in millions):

**As of December 31, 2003, the Partnership has made semi-annual installments totaling $48.7 million 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, 2003 and 2002, was 9.200% and 9.201%, respectively.

Credit Agreements

The Partnership, pursuant to certain of the financing agreements, the PPA and the ESA, was required to post letters of credit, which, in the aggregate, had a face amount of no more than $65 million. Certain of these letters of credit had been issued pursuant to a Letter of Credit and Reimbursement Agreement with Credit Suisse/First Boston. Prior to their expiration, the letters of credit were drawn by LDC on November 14, 2002 and by FPL on December 16, 2002 for $10.0 million and $1.7 million, respectively. The principal amount of the resulting seven year term loans was payable in fourteen semi-annual installments with a prepayment provision of any outstanding loan amount before cash would be available for distribution to the Partners. On July 25, 2003, FPL returned to the Partnership the $1.7 million cash drawn on the letter of credit, since the obligation to maintain this security under the PPA had expired. The $1.7 million was deposited in accordance with the terms of the Disbursement Agreement.

The Partnership entered into a debt service reserve letter of credit and reimbursement agreement, dated as of November 1, 1994, with BNP Paribas. Pursuant to the terms of the Disbursement Agreement, since the debt service reserve letter of credit was to expire on November 22, 2005, available cash flows were required to be deposited on a monthly basis

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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 Maximum Balance was achieved, which is $29.9 million.

On October 10, 2003, the Partnership closed a transaction with Credit Lyonnais New York Branch (“CL”), as agent and arranger, to replace the above referenced letters of credit. The facilities include a Debt Service Reserve Letter of Credit up to $29.9 million, which has a term of seven years; Performance Letters of Credit up to $15.0 million, which have a term of five years; and a Working Capital Revolving Facility up to $10.0 million, which has a term of three years and is presently capped at $3.0 million. The interest rate on loans made on the Working Capital Revolving Credit is the London Interbank Offered Rates (“LIBOR”) plus an applicable margin. The Partnership satisfied the applicable conditions precedent set forth in the financing documents relating to this transaction.

Under the Performance Letters of Credit, the ESA Letter of Credit for $10.0 million was issued in favor of LDC.

Letters of credit previously drawn by LDC on November 14, 2002 and by FPL on December 16, 2002 for $10.0 million and $1.7 million, respectively, and which converted to term loans, were paid in full at closing. Subordinated fees and interest under the MSA and the O&M Agreement totaling $1.2 million and $2.3 million, respectively, were also paid at closing.

The Debt Service Letter of Credit, which was issued for the full $29.9 million, replaces one that was due to expire on November 22, 2005. Deposits previously made by the Partnership into the Debt Service Reserve Account totaling $12.0 million as of September 30, 2003 were returned to the Revenue Account as a result of the replacement Debt Service Reserve Letter of Credit and were used for the payment of the subordinated fees and interest and the repayment of the letter of credit term loans.

Upon execution of the relevant amendments and/or additional contracts with the fuel supplier and with FPL reflecting new indices and fuel supply arrangements, a Coverage Test will be conducted to determine the projected average annual Senior Debt Service Coverage Ratio through 2015. If the Coverage Test results in the average of less than 1.30x, distributable cash will be deposited into an escrow account for the benefit of the letter of credit lenders to collateralize the letters of credit. The cash will be held in escrow until (i) the achievement of a Senior Debt Service Coverage Ratio of 1.35x in one semi-annual interest payment period and (ii) an annual average Senior Debt Service Coverage ratio through 2015 of at least 1.35x is projected.

Expectations for Year Ending December 31, 2004

For 2004, the Partnership has identified possible capital improvements of approximately $2.4 million that will enhance the reliability of the facility and, if approved by the Board of Control (see Item 10), will be funded through cash expected to be generated from operations that would otherwise be distributed to the partners. These improvements include additional upper aquifer wells, water system upgrades and distributed controls system modifications.

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In the absence of any major equipment failures, unit overall availability is expected to be comparable to 2003 levels, which averaged approximately 97% for the year. Capacity bonuses are expected to be at a comparable level in 2004 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 2004.

Contractual Payment Obligations

The Partnership has entered into various agreements that result in contractual payment obligations in future years. These contracts include financing arrangements for the Bonds, leases, and contracts for management services and operating and maintenance services. The following table summarizes cash payments that the Partnership is committed to make under existing terms of contracts to which the Partnership is a party as of December 31, 2003. This table does not include contingencies. For the capital lease and services agreements, actual cash payments will be based upon contract terms with provisions for escalation and will likely differ, perhaps materially from amounts presented below.

(1)

Reflect payment obligations under a railcar lease agreement with General Electric Railcar Services Corporation.

(2)

Reflect payment obligations for administration, fronting and commitment fees for the Debt Service Reserve Letter of Credit, the Performance Letters of Credit and the Revolving Credit.

(3)

Reflect payment obligations for the base fee pursuant to the MSA and the O&M Agreement.

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Commitments

All off-balance sheet arrangements of the Partnership are discussed in the Certain Project Contracts section in Item 1, Business, and in the Critical Accounting Policy section in Item 7, Management Discussion and Analysis. The Partnership has commitments related to purchase and sales agreements as described in Item 1, Business. The Partnership also has financial letters of credit as discussed above.

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 both 2003 and 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 PPA 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%. FPL completed its audit of the 2002 documentation provided by the Partnership of actual energy costs and determined that the difference is more than 4%. In addition, the fuel index used to determine the coal cost component of the monthly energy payment under the PPA is no longer in effect due to an interruption of Central Appalachian coal deliveries to the St. John’s River Power Park (“SJRPP”). Beginning July 1, 2003 the coal cost component of the monthly energy payment that FPL has reimbursed to the Partnership has escalated according to the index in the SJRPP long term domestic Appalachian coal contract which had been in effect until the interruption in deliveries. The Partnership and FPL, within one year, shall agree upon a comparable replacement index. The Partnership and FPL have been in discussions to resolve both the energy price and the replacement index issues.

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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 amounts 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.

All derivatives are assessed to evaluate whether they are to be recognized 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. Currently, the Partnership’s only derivative contracts are 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.

Recently Issued Accounting Pronouncements

On January 1, 2003, the Partnership adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. The statement requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of 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 long-lived asset.

The key inputs in the asset retirement obligation calculation performed by the Partnership are the determination of the various retirement scenarios and the probability of when or if those scenarios will occur. The estimation made by the Partnership upon adoption of SFAS No. 143 represents the Partnership’s best estimate of scenarios and related probabilities at that date. Upon implementation of this statement, the Partnership recorded approximately $44,000 in property, plant and equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, approximately $9,000 of accumulated depreciation through December 31, 2002 and an asset retirement obligation of approximately $84,000. The cumulative effect of the change in accounting principle as a result of adopting this statement was a loss of approximately $49,000.

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Legal Matters

The Partnership is currently not involved in any legal proceedings.

Item 7A Quantitative and Qualitative Disclosures About Market Risk

The Partnership is exposed to market risk from energy commodity prices and interest rates, which could affect its future results of operations and financial condition. The Partnership manages its exposure to these risks through its regular operating and financing activities. (See “Market Risk”, included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations above.).

The table below presents principal, interest and related weighted average interest rates by year of maturity (in thousands).

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Item 8 Financial Statements and Supplementary Data

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Report of Independent Auditors

To the Board of Control of
Indiantown Cogeneration, L.P.:

We have audited the accompanying consolidated balance sheets of Indiantown Cogeneration, L.P. and subsidiary as of December 31, 2003 and 2002 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 audit. The accompanying consolidated statements of operations, changes in partners’ capital and cash flows for the year 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.

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 2003 and 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, 2003 and 2002, and the consolidated 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 in the consolidated financial statements, the Partnership changed the manner in which it accounts for asset retirement obligations, upon adoption of Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations.

/s/ Ernst & Young LLP

McLean, Virginia
February 26, 2004
Except for Note 10, as to which the date is
March 19, 2004

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This is a copy of the report previously issued by Arthur Andersen LLP and has not been reissued by Arthur Andersen LLP.

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

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Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Balance Sheets
As of December 31, 2003 and 2002
(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Balance Sheets
As of December 31, 2003 and 2002
(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Statements of Operations
For the Years Ended December 31, 2003, 2002 and 2001
(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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Indiantown Cogeneration, L. P. and Subsidiary
Consolidated Statements of Changes in Partners’ Capital
For the Years Ended December 31, 2003, 2002 and 2001
(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2003, 2002, and 2001
(in thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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Indiantown Cogeneration, L.P. and Subsidiary
Notes to Consolidated Financial Statements
December 31, 2003, 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”) under a Power Purchase Agreement (“PPA”). The Facility also supplies steam to Louis Dreyfus Citrus, Inc. (“LDC”), successor to Caulkins Indiantown Citrus Co., under an Energy Services Agreement. The Partnership commenced commercial operations on December 22, 1995 (the “Commercial Operation Date”). 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.

The original general partners were Toyan Enterprises (“Toyan”), a California corporation and a wholly owned special purpose indirect subsidiary of National Energy & Gas Transmission, Inc. (“NEGT”, formerly known as PG&E National Energy Group, 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”).

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. (together with its subsidiaries, “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.

Cogentrix was acquired by GS Power Holdings LLC (“GSPHLLC”), a subsidiary of The Goldman Sachs Group, Inc. GSPHLLC purchased 100% of the stock of Cogentrix in December 2003.

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The net income of the Partnership is allocated to Toyan, Palm, IPILP and Thaleia (collectively, the “Partners”) based on the following ownership percentages:

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 Power Services Company (“PSC”, formerly known as PG&E National Energy Group Company), pursuant to a Management Services Agreement (the “MSA”). The Facility is operated by U.S. Operating Services Company (“OSC”, formerly known as PG&E Operating Services Company), pursuant to an Operation and Maintenance Agreement (the “O&M Agreement”). PSC and OSC are general partnerships indirectly wholly owned by National Energy and Gas Transmission, Inc. (“NEGT”, formerly known as PG&E National Energy Group, Inc.). NEGT is an indirect subsidiary of PG&E Corporation (see Note 7).

On July 8, 2003, NEGT and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEGT Bankruptcy”) in the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”).

Neither the Partnership nor any of its NEGT affiliated partners, including Toyan and IPILP, or PSC and OSC, are parties to the NEGT Bankruptcy. The Partnership believes that it will not be substantively consolidated with NEGT in any bankruptcy proceeding involving NEGT and the NEGT Bankruptcy does not result in an event of default under the principal project contracts or the principal financing documents of the facility.

On February 26, 2004, NEGT filed with the Bankruptcy Court its Third Amended Plan of Reorganization and the related Disclosure Statement (“POR”). The POR contemplates that NEGT will retain and continue to operate its power generation and pipeline businesses unless they are sold (as described in the POR), separate from PG&E Corporation, and issue new debt securities and common stock. NEGT’s indirect ownership interest in the Partnership is included within its power generation business. Any sale by NEGT of its interest in the Partnership (a “NEGT Interest Sale”) may affect management’s MSA contract with the Partnership. There can be no certainty that a NEGT Interest Sale will be completed.

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On December 30, 2003, Moody’s confirmed the senior secured debt of the Partnership at Ba1 and changed the rating outlook to stable from negative. Moody’s stated that this rating action reflects the project’s improved financial performance during 2003 and the expectations that the debt service coverage ratios for the next several years will remain in the 1.30x to 1.40x range. The rating action also incorporates the Partnership’s improved liquidity profile due to the completion of new letter of credit and working capital facilities during October 2003 and the progress being made to negotiate a new coal price index with the coal supplier.

On July 8, 2003, Standard and Poor’s (“S&P”) issued a press release announcing that it had lowered its corporate credit ratings on two of NEGT’s subsidiaries. S&P stated these ratings actions follow the NEGT Bankruptcy. S&P further stated that the rating on ICL Funding was not affected by the ratings action on NEGT because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEGT. Therefore, S&P concluded that the incentive to consolidate it in a bankruptcy of NEGT is low. S&P’s rating of the Partnership’s debt remains at “BBB- with a negative outlook”.

On March 19, 2004 S&P placed its BBB- rating on the debt of ICL Funding on Credit Watch with negative implications. The credit watch reflects the risk of a downgrade if the PPA negotiations with FPL regarding a new energy payment index are not resolved to mitigate the current mismatch between energy revenues and fuel expenses.

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

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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

Investments held by trustee represent bond and equity funds 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 funds include $12.5 million 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 $4.0 million is also held as a non-current asset (see Note 4).

The Partnership maintains restricted investments covering a portion of debt principal and interest payable, as required by the financing documents. These investments are classified as current investments held by trustee in the accompanying consolidated balance sheets.

Concentration of Credit Risk

Credit risk is the risk of loss the Partnership would incur if counterparties fail to perform their contractual obligations (accounts receivable). The Partnership’s credit risk is primarily concentrated with FPL, which provides more than 99% of the Partnership revenues and 100% of accounts receivable as of December 31, 2003 and is considered to be of investment grade.

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 three to ten years). Routine maintenance and repairs are charged to expense as incurred.

The Partnership reviews its 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 based on the difference between the asset’s estimated fair value and its carrying value.

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Fuel Reserve

The fuel reserve, carried at cost, represents an approximate fourteen day supply of coal held for emergency purposes. As 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 financing.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities for 2003 include property taxes of $5.6 million, a balance due to CSX Transportation of $1.1 million, a balance due to Massey Coal Sales, Inc. (“Massey”) of $0.8 million and employee incentive bonuses of $0.8 million. Accounts payable and accrued liabilities for 2002 include property taxes of $5.3 million and a balance due to Lodestar Energy, Inc. of $1.9 million.

Scheduled Major Overhauls

The Partnership’s depreciation is based on the plant being considered as a single property unit. Certain components within the plant will require replacement or overhaul several times within the estimated life of the plant. Costs associated with scheduled major overhauls are recorded as an expense in the period incurred.

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

Derivatives are recorded 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,

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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 relevant accounting standards.

Asset Retirement Obligations

On January 1, 2003, the Partnership adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. The statement requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of 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 long-lived asset.

Upon implementation of this statement, the Partnership recorded approximately $44,000 in property, plant and equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, approximately $9,000 of accumulated depreciation through December 31, 2002 and an asset retirement obligation of approximately $84,000. The cumulative effect of the change in accounting principle as a result of adopting this statement was a loss of approximately $49,000.

If this statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the year ended December 31, 2002 would not have been material.

Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”). FIN 46, as subsequently revised in December 2003 (“FIN 46R”), is an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements (“ARB 51”), and supersedes Emerging Issues Task Force (EITF) Issues No. 90-15 and 96-21, which prescribe accounting for lease arrangements with nonsubstantive lessors. This Interpretation clarifies the application of ARB 51 to certain entities, defined as variable interest entities (“VIE’s”), in which equity investors do not have a controlling financial interest or do not have sufficient equity at risk for the entity to finance it activities without additional subordinated financial support. FIN 46R requires that a VIE is to be consolidated by a company if that company is subject to a majority of the risk of loss from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns, or both.

The consolidation requirements of FIN No. 46 apply immediately to VIE’s created after January 31, 2003. There were no new VIE’s created by the Partnership between February 1, 2003 and December 31, 2003. The consolidation requirements related to entities or arrangements existing before February 1, 2003 were originally effective July 1, 2003. However, due to implementation issues,

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the FASB deferred implementation until fourth quarter 2003. On December 24, 2003, the FASB issued FIN 46R, which deferred the effective date for most VIE’s or potential VIE’s until March 31, 2004, but required that the standard be adopted for certain entities commonly referred to as special purpose entities (“SPE’s”) on December 31, 2003.

No arrangements with SPE’s currently exist, and the Partnership has not identified any arrangements with other potential VIE’s. The Partnership will continue to evaluate other arrangements for potential FIN 46R application effective March 31, 2004. The Partnership does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

3. DEPOSITS:

In 1991, in accordance with the Planned Unit Development Zoning Agreement between the Partnership and Martin County, the Partnership deposited $1.0 million 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, 2003 and 2002, estimated present values of this deposit of $0.2 million 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.

4. BONDS AND NOTES PAYABLE:

The Senior Debt of the Partnership ranks on parity with each other and is senior in right of payment to all Subordinated Debt. Total deferred financing costs of $2.3 million were incurred as a result of replacing a working capital facility and certain letters of credit described below.

First Mortgage Bonds

On November 22, 1994, the Partnership and ICL Funding jointly issued $505.0 million of First Mortgage Bonds (the “First Mortgage Bonds”) in a public issuance registered with the Securities and Exchange Commission. Proceeds from the issuance were used to repay outstanding balances of $273.5 million 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 9.59% and 9.57% during 2003 and 2002, respectively. Interest is payable semi-annually on June 15 and December 15 of each year. Interest expense related to the First Mortgage Bonds was $41.0 million, $42.1 million, and $43.2 million, in 2003, 2002, and 2001 respectively.

Tax Exempt Facility Revenue Bonds

The proceeds from the issuance of $113.0 million of Series 1992A and 1992B Industrial Development Revenue Bonds (the “1992 Bonds”) through the Martin County Industrial

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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 $113.0 million Series 1994A and of $12.0 million 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 $9.9 million for each of the years ended December 31, 2003, 2002, and 2001. 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, 2003 are as follows (dollars in millions):

Revolving Credit Agreement

On October 10, 2003, the Partnership closed a transaction with Credit Lyonnais New York Branch (“CL”), as agent and arranger, to enter into a Revolving Credit Agreement up to $10.0 million, which has a term of three years and was capped at $3.0 million as of December 31, 2003. The credit facility includes commitment fees, to be paid quarterly, of 0.50% on the unborrowed portion. The interest rate on loans made on the Revolving Credit Agreement is the London Interbank Offered Rates (“LIBOR”) plus an applicable margin.

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 $50.0 million. 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

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credit. The initial amount of $13.0 million was issued for the first year of operations and increased to $40.0 million in January 1999 and then to $50.0 million in January 2000. On June 1, 2002 the letter of credit was reduced to $3.1 million and on November 1, 2002 it was further reduced to $1.7 million pursuant to the PPA. Commitment fees of $0.5 million and $0.7 million were paid on this letter of credit in 2002 and 2001, respectively.

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 December 16, 2002, FPL drew on the direct pay letter of credit for the full amount of $1.7 million, which converted the letter of credit to a term loan. The funds were owned by the Partnership but held by FPL and were included in restricted cash on the consolidated balance sheet as of December 31, 2002. During 2003 the obligation to maintain the letter of credit under the PPA expired. Also during 2003, the restriction on the cash was released and the term loan was paid in full.

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 $0.5 million increasing by $0.5 million per agreement year to a maximum of $5.0 million. 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 $0.5 million per agreement year to a maximum of $5.0 million. In February 1996, the Partnership established a QF account with the Trustee. The balance in this account as of December 31, 2003 and 2002, was $4.0 million and $3.5 million, respectively, and is included in noncurrent assets as investments held by trustee, restricted funds, on the accompanying consolidated balance sheets.

Steam Host Letter of Credit

The Partnership is required to maintain a $10.0 million letter of credit to protect LDC in the event of a default under the Energy Services Agreement (see Note 6). Commitment fees of $0.1 million were paid relating to this letter of credit in both 2002 and 2001.

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 was drawn by LDC on November 14, 2002. Funds were held in an escrow account for the benefit of LDC and were included in noncurrent assets as investments held by trustee, restricted funds, on the accompanying consolidated balance sheet as of December 31, 2002. The letter of credit obligation was converted into a term loan.

On October 10, 2003, the Partnership closed a transaction with CL, as agent and arranger, to replace the above referenced letter of credit in the amount of $10.0 million. As a result, the restriction on the funds held in escrow was released and the term loan was repaid in full on October 14, 2003.

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Deferred financing costs and commitment fees of $2.2 million and $0.1 million, respectively, were paid in 2003 relating to this replacement letter of credit.

Debt Service Reserve Letter of Credit

During 1994, the Partnership entered into a debt service reserve letter of credit and reimbursement agreement with BNP Paribas pursuant to which a debt service reserve letter of credit in the amount of approximately $60.0 million was issued. Such agreement has a rolling term of five years subject to extension at the discretion of the participating 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 $29.9 million. Commitment fees of $0.3 million, $0.4 million, and $0.4 million were paid on this letter of credit in 2003, 2002, and 2001, respectively.

BNP Paribas notified the Partnership on May 18, 2001 of its intention not to extend the term of the agreement, which would have expired on November 22, 2005. The Partnership was unable to find an issuer to replace BNP Paribas which met the credit requirements under the Indenture. Pursuant to the terms of the Disbursement Agreement, available cash flows were 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 was achieved, which is $29.9 million per the Disbursement Agreement. No distributions were allowed to the partners until such balance was funded.

On October 10, 2003, the Partnership closed a transaction with CL, as agent and arranger, to replace the above referenced letter of credit in the amount of $29.9 million. Deposits previously made during 2003 by the Partnership into the Debt Service Reserve Account totaling $12.0 million were returned to the Revenue Account as a result of the replacement Debt Service Reserve Letter of Credit . Commitment fees of $0.1 million were paid on this replacement letter of credit in 2003.

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. At December 31, 2003 the Partnership is in compliance with all related financial covenants.

5. PURCHASE AGREEMENTS:

Coal Purchase and Transportation Agreement

A Coal Purchase and Sales Agreement (the “Coal Purchase Agreement’) was executed on February 5, 2003 between the Partnership and Massey and became effective on April 1, 2003. Under the

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Coal Purchase Agreement, which remains in effect until December 31, 2025, the base coal price was $33.75 per ton with a market price reopener provision which began in October 2003.

The First Amendment (the “Amendment”) to the Coal Purchase Agreement between Massey and the Partnership was entered into on August 21, 2003, with an effective date August 1, 2003. The principal change effected in the Coal Purchase Agreement was a decrease from $33.75 to $33.00 per ton in the base coal price with a market price reopener provision beginning the earlier of ninety days after the Partnership successfully negotiates a new fuel index under the PPA or October 1, 2005. Currently, the fuel index used to determine the coal cost component of the monthly energy payment from FPL under the PPA is no longer in effect. Within ninety days after the Partnership successfully negotiates a new fuel index under the PPA, the Partnership and Massey will utilize commercially reasonable best efforts to develop a coal price tied to a fuel index agreeable to both parties. The Partnership satisfied the applicable conditions precedent set forth in the financing documents relating to the Amendment.

The Partnership and CSX Transportation, Inc. (“CSX”) entered into a Coal Transportation Agreement dated August 6, 2003, under which CSX will deliver coal to the Facility through December 31, 2025 at the system car rate of $23.09 per ton, which is approximately 30% less than the current tariff rates for delivered coal. This system car rate is adjusted quarterly using the same index that adjusts the remaining costs component of the energy payment from FPL. CSX will also transport a minimum of 500 carloads of ash to an acceptable disposal firm on the CSX rail system. In addition, CSX rebated the Partnership $3.8 million in October 2003, which was the difference between the tariff rates and system car rates for all coal shipments for the period from April 1, 2003 through the effective date of the Coal Transportation Agreement, less $1.1 million in pre-petition and gap debt owed to CSX from Lodestar Energy, Inc. (“LEI”). CSX assigned to the Partnership their claim to the $1.1 million due from LEI under the Transportation Agreement. The Partnership satisfied the applicable conditions precedent set forth in the financing documents relating to the Coal Transportation Agreement.

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, 2005. The base price of $56.25 per ton is to be adjusted annually 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

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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 $5.8 million and accumulated depreciation of $3.3 million and $2.9 million, respectively, are included in property, plant and equipment as of December 31, 2003 and 2002. Amortization expense related to the leased assets is included in depreciation expense. Payments of $0.6 million, including principal and interest, were made in 2003, 2002, and 2001.

Future minimum payments related to the Car Leasing Agreement as of December 31, 2003 are as follows (dollars in millions):

6. SALES AND SERVICES AGREEMENTS:

Power Purchase Agreement

On May 21, 1990, the Partnership entered into a PPA with FPL for sale 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. The coal cost component of the energy payment is derived from a contractual formula defined in the PPA based on the actual cost of domestic coal at another FPL plant, St. Johns River Power Park (“SJRPP”). This fuel index is no longer in effect due to an interruption of Central Appalachian coal deliveries to the SJRPP. The Partnership and FPL, within one year of the interruption, are to agree upon a comparable replacement index. Until a replacement index becomes effective, the coal cost component is escalated according to the index in the SJRPP long- term domestic Appalachian coal contract which had been in effect until the interruption in deliveries. The Partnership and FPL have been in discussions to resolve the replacement index issue.

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Energy Services Agreement

On September 30, 1992, the Partnership entered into an Energy Services Agreement with Caulkins. In September 2001, Caulkins sold its processing plant to 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 (“QF”) under PURPA. The Facility declared Commercial Operation with LDC on March 1, 1996. LDC purchased the minimum quantity of steam in 2003 for the Partnership to maintain its QF status under PURPA.

7. RELATED PARTY TRANSACTIONS:

Management Services Agreement

The Partnership has an MSA with PSC, which provides for the day-to-day management and administration of the Partnership’s business relating to the Facility. The MSA will continue through October 31, 2028. Compensation to PSC under the agreement includes an annual base fee of $0.7 million (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 in 2003 and 2002 of $0.5 million and $0.6 million, respectively, were subordinated pursuant to the Disbursement Agreement and were paid in full on October 14, 2003. Payments of $4.4 million, $3.1 million, and $4.2 million, in 2003, 2002, and 2001 were made to PSC, respectively. As of December 31, 2003 and 2002, the Partnership owed PSC $0.2 million and $0.8 million, respectively, which are included in accounts payable and accrued liabilities in the accompanying consolidated balance sheets.

Operations and Maintenance Agreement

The Partnership’s O&M Agreement with OSC provides 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, OSC will pay liquidated damages to the Partnership. Compensation to 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 in 2003 and 2002 of $0.5 million and $1.0 million, respectively, and earned fees in 2003 and 2002 of $0.4 million and $0.3 million, respectively, were subordinated pursuant to the Disbursement Agreement and were paid in full on October 14, 2003. Payments of $9.8 million, $7.1 million, and $9.3 million were made to OSC in 2003, 2002, and 2001, respectively. As of December 31, 2003 and 2002, the Partnership owed OSC $0.8 million and $2.1 million, respectively, which is included in accounts payable and accrued liabilities in the accompanying consolidated balance sheets.

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Distribution to Partners

A distribution of $20.0 million was made to the Partners in 2003. There were no distributions made to the Partners in 2002 and a distribution totaling $12.4 million was made in 2001.

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, 2003 and 2002 (in millions).

Current market interest rates were used to estimate fair 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 trade, 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, 2003, the Partnership recorded additional electric energy revenue of $0.4 million for additional 2003 payments estimated to be due from FPL in conjunction with the annual fuel audit to be conducted in early 2004 and performed under the PPA.

10. SUBSEQUENT EVENT:

On March 19, 2004 S&P placed its BBB- rating on the debt of ICL Funding on Credit Watch with negative implications. The credit watch reflects the risk of a downgrade if the PPA negotiations with FPL regarding a new energy payment index are not resolved to mitigate the current mismatch between energy revenues and fuel expenses.

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Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     None.

Item 9A Controls and Procedures

An evaluation of the disclosure controls and procedures of the Partnership and ICL Funding as of December 31, 2003 has been conducted under the supervision and with the participation of the principal executive officer and principal financial officer of both the Partnership and ICL Funding. Based on that evaluation, such officers have concluded that, as of such date, the disclosure controls and procedures of the Partnership and ICL Funding are effective, in that they provide reasonable assurance that such officers are alerted on a timely basis to material information that is required to be included in the Partnership’s and ICL Funding’s periodic filings under the Securities Exchange Act of 1934, as amended.

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PART III

Item 10 Directors and Executive Officers

Partnership Governance

The Board of Control is delegated authority under the Partnership Agreement for the management and control of the business and affairs of the Partnership, subject to restrictions set forth in the Partnership Agreement. Day-to-day management and administration of the Facility is carried out by PSC pursuant to a management services agreement under the supervision of the Board of Control.

Indiantown Cogeneration, L.P. Board of Control and Executive Officers

     The following table sets forth the names, ages and positions of the members of the Board of Control and the executive officers of the Partnership. Members of the Board of Control are elected from time to time by, and serve at the pleasure of, the Partners of the Partnership. Officers are elected from time to time by vote of the Board of Control.

     Brian G. Martin is Asset Manager in the Asset Management Department for Cogentrix Energy, Inc. (“Cogentrix”) and has been with Cogentrix since 2000. Prior to joining Cogentrix , Mr. Martin held several management positions with a manufacturer of steam generators. Mr. Martin holds a B.S. degree in Fuel Science from the Pennsylvania State University.

     Thomas J. Bonner is Vice President – Asset Management for Cogentrix and has been with Cogentrix since 1987. Prior to joining Cogentrix, Mr. Bonner spent 5 years as a utility manager in an integrated fiber and chemical production facility. Mr. Bonner holds a B.S. from the U.S. Naval Academy, and an M.B.A. from Old Dominion University.

     P. Chrisman Iribe is President and Chief Operating Officer of Power Services Company (formerly PG&E National Energy Group Company), an affiliate of the Partnership, and has been with Power Services Company since it was formed in 1989. Prior to joining Power Services Company, Mr. Iribe was senior vice president for planning, state relations and public affairs with ANR Pipeline Company, a natural gas pipeline company and a subsidiary of the Coastal Corporation. Mr. Iribe holds a B.A. degree in Economics from George Washington University.

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     Sanford L. Hartman is Vice President, Chief Counsel and Secretary of Power Services Company, an affiliate of the Partnership, and has been with Power Services Company since 1990. Prior to joining Power Services Company, Mr. Hartman was counsel to Long Lake Energy Corporation, an independent power producer with headquarters in New York City, and was an attorney with the Washington, D.C. law firm of Bishop, Cook, Purcell & Reynolds. Mr. Hartman has a B.A. in Political Science from Drew University and a J.D. from Temple University.

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.

Audit Committee

     The Board of Directors of the ICL Funding performs the functions and responsibilities of an audit committee of the Partnership and ICL Funding. The Board of Directors has determined that one of its members, Thomas E. Legro, is an audit committee financial expert as defined in Item 401(h) of the Securities and Exchange Commission’s (“the Commission”) Regulation S-K, and has also determined that Mr. Legro is not “independent” within the meaning of such provision because he is an executive officer of both the Partnership and ICL Funding, as well as an employee of an affiliated person, NEGT Services Company, LLC, a subsidiary of NEGT. The Partnership and ICL Funding, however, are not required under the Commission’s rules implementing Section 10A(m) of the Securities Exchange Act of 1934, as amended, to have an audit committee consisting of “independent” members because they are not listed issuers within the meaning of such rules.

Code of Ethics

     As employees of NEGT Services Company, LLC, a subsidiary of NEGT, the principal executive officer and principal financial officer of both the Partnership and ICL Funding Corporation are subject to a code of business conduct and ethics contained within the NEGT employee handbook most recently modified in December 2003 (the “Code of Ethics”). The Code of Ethics is intended to promote honest and ethical conduct and compliance with the laws and governmental rules and regulations to which the companies are subject. A printed copy of the Code of Ethics will be provided free of charge to any bondholder upon written request to Indiantown Cogeneration, L.P., Investor Relations, c/o NEGT at the Partnership’s principal executive offices listed on the cover page of this Report.

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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 PSC 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 OSC on a cost-plus basis. In addition to a base fee, 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, 2003, are held as follows:

     All of the outstanding shares of common stock of ICL Funding are owned by the Partnership.

Item 13 Certain Relationships and Related Transactions

The Partnership has several material contracts with affiliated entities. These contracts, which include the Management Services Agreement and the Operations and Maintenance Agreement, are described elsewhere in this report, most notably in Note 7 to the consolidated financial statements.

Item 14 Principal Accountant Fees and Services

The following table presents fees for professional services rendered by Ernst & Young LLP and billed to the Partnership for the audits of the annual consolidated financial statements of the Partnership and its subsidiary for the years ended December 31, 2003 and 2002, and fees for other services billed by Ernst & Young LLP during those periods:

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Audit Fees – Audit fees relate to services rendered in connection with the audit of the annual financial statements included in the Partnership’s Annual Reports on Form 10-K and the quarterly reviews of financial statements included in the Partnership’s Quarterly Reports on Forms 10-Q.

Audit-Related Fees – Audit-related fees relate to services for consultations concerning financial accounting and reporting matters and to a report from Ernst & Young LLP on applying agreed-upon procedures performed in accordance with the provisions in the PPA for a quarterly letter the Partnership submits to FPL meeting the conditions of security requirements.

Tax Fees – Tax fees relate to services for tax compliance.

Pre-Approval Policies

The Board of Directors of ICL Funding acts as the audit committee for the Partnership (“Audit Committee”).

The Audit Committee pre-approves all audit and non-audit services provided by the Partnership’s independent auditor prior to the engagement of the independent auditor with respect to such services. The Chief Accounting Officer, who is also a member of the Audit Committee, has the authority to approve any additional audit services and permissible non-audit services provided the the Audit Committee is informed of such approval at its next regularly scheduled meeting.

All of the services provided by Ernst & Young LLP for fiscal year 2003 and related fees were approved in advance by the Audit Committee in accordance with established pre-approval policies.

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PART IV

Item 15 Exhibits, Financial Statement Schedules and Reports on Form 8-K

a)

Documents filed as of this Report

b)

Reports on Form 8-K:

The Partnership filed a current report on Form 8-K dated October 27, 2003 announcing the replacement of credit agreements. This report was amended by a report on Form 8-K/A filed on November 13, 2003.

      c) Exhibits:

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50

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** 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.

******** Incorporated by reference from the annual report on Form 10-K file no. 33-82034 filed by the Registrants with the SEC in March 2003.

********* Incorporated by reference from the current report on Form 8-K file no. 33-82034 filed by the Registrants with the SEC in October 2003.

********** Incorporated by reference from the current report on Form 10-Q file no. 33-82034 filed by the Registrants with the SEC in November 2003.

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SIGNATURES

     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 29, 2004.

	Indiantown Cogeneration, L.P.
March 29, 2004	Date:/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.

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SIGNATURES

     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 29, 2004.

	Indiantown Cogeneration Funding Corporation
Date: March 29, 2004	/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.

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EXHIBIT INDEX