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).