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SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

[X]QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2003

Commission File Number 33-82034

INDIANTOWN COGENERATION, L.P.

INDIANTOWN COGENERATION FUNDING CORPORATION

7600 Wisconsin Avenue

(301)-280-6800

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     [X] Yes     [  ] No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)     [  ] Yes     [X] No

Indiantown Cogeneration, L.P.
Indiantown Cogeneration Funding Corporation

PART I
FINANCIAL INFORMATION

Indiantown Cogeneration, L.P. and Subsidiary
Consolidated Balance Sheets
(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
(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
(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
(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
As of June 30, 2003
(Unaudited)

1.     ORGANIZATION AND BASIS OF PRESENTATION:

Indiantown Cogeneration, L.P. (the “Partnership”) is a special purpose Delaware limited partnership formed on October 4, 1991. The Partnership was formed to develop, construct, own and operate an approximately 330 megawatt (net) pulverized coal-fired cogeneration facility (the “Facility”) located on an approximately 240-acre site in southwestern Martin County, Florida. The Facility produces electricity for sale to Florida Power & Light Company (“FPL”) and supplies steam to Louis Dreyfus Citrus, Inc. (“LDC”), successor to Caulkins Indiantown Citrus Co.

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all the information and notes required by accounting principles generally accepted in the United States for complete statements. Management believes that the accompanying unaudited consolidated financial statements, which have been prepared in accordance with interim reporting requirements, reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods for Indiantown Cogeneration, L.P. and Indiantown Cogeneration Funding Corporation. All material adjustments are of a normal recurring nature unless otherwise disclosed in this report on Form 10-Q. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

This quarterly report should be read in conjunction with the Partnership’s consolidated financial statements and notes to consolidated financial statements included in its 2002 Annual Report on Form 10-K and its other reports filed with the Securities and Exchange Commission (“SEC”) since the 2002 Annual Report on Form 10-K was filed.

2.     RELATIONSHIP WITH PG&E CORPORATION AND PG&E NATIONAL ENERGY GROUP, INC:

The Partnership is managed by PG&E National Energy Group Company (“NEG”), pursuant to a Management Services Agreement (the “MSA”). The Facility is operated by PG&E Operating Services Company (“PG&E OSC”), pursuant to an Operation and Maintenance Agreement (the “O&M Agreement”). NEG and PG&E OSC are general partnerships indirectly wholly owned by NEG, Inc., an indirect subsidiary of PG&E Corporation.

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

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Additionally, on July 8, 2003, NEG, Inc. filed its plan of reorganization (the “NEG Plan”). The NEG Plan anticipates that PG&E Corporation will have no equity interest in NEG, Inc. or any of its subsidiaries after the NEG Plan is confirmed by the Bankruptcy Court and implemented. On July 7, 2003, the officers of PG&E Corporation who were serving on the Board of Directors of NEG, Inc. resigned their positions. On July 7 and July 8, 2003, the NEG Board elected replacement directors who are not affiliated with PG&E Corporation. While continuing to maintain legal ownership, effective with this change in control of the Board and the NEG Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEG, Inc.

Neither the Partnership nor any of its NEG, Inc. affiliates, including Toyan, IPILP, NEG and PG&E OSC, are parties to the filings by NEG, Inc. or other affiliates for protection under the NEG Bankruptcy. The Partnership believes that the NEG Bankruptcy will not have a material adverse impact on its operations.

NEG, Inc. owns an indirect interest in the Partnership, and through its wholly owned subsidiaries NEG and PG&E OSC manages and operates the Project. Management believes that the Partnership or its subsidiary will not be substantively consolidated with NEG, Inc. in any bankruptcy proceeding involving NEG, Inc. The NEG Bankruptcy does not result in an event of default under the principal project contracts or the principal financing documents of the Project.

As result of the sustained downturn in the power industry, NEG, Inc. and certain of its consolidated affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade NEG, Inc. and certain of its consolidated affiliates’ credit ratings to below investment grade. The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership.

As previously reported on June 13, 2003, Moody’s Investors Service (“Moody’s”) announced its decision to downgrade the senior secured debt rating of Indiantown Cogeneration, L.P. (the “Partnership”) to Ba1 from Baa3. The rating action concludes the review for possible downgrade that was initiated on October 8, 2002. The rating outlook is negative. Moody’s stated that this rating action reflects the project’s weakened financial profile, particularly due to problems with operating performance, including outages during 2001 and 2002. Moody’s further stated that while Indiantown anticipates financial improvement in the next few years, prospective coverage ratios are anticipated to be in the 1.30x to 1.40x range, below the level that would be consistent with a Baa3 rating for a coal-fired project. The rating action also incorporates some uncertainty relating to the price redetermination of a coal purchase contract, and further considers that the Partnership will be required to use any excess cash to fund or repay third party obligations over the next several years relating to three letters of credit, the largest of which is used to support the project’s six-month debt reserve of approximately $29 million. The negative outlook incorporates the involvement of NEG, Inc., as operator and as a partial owner.

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As previously reported 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 NEG Inc.’s subsidiaries. S&P stated these ratings actions follow the NEG Bankruptcy. S&P further stated that the rating on Indiantown Cogeneration Funding Corporation is not affected by the ratings action on NEG, Inc. because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEG, Inc. Therefore, S&P concluded the incentive to consolidate it in a bankruptcy of NEG, Inc. is low. S&P’s rating of the Partnership’s debt remains at “BBB- with a negative outlook”.

The downgrade by Moody’s does not trigger any requirements under the Partnership’s financing documents.

3.     SIGNIFICANT ACCOUNTING POLICIES:

Except as disclosed, the Partnership is following the same accounting principles discussed in the Partnership’s December 31, 2002 Annual Report on Form 10-K.

Adoption of New Accounting Pronouncements

On January 1, 2003, the Partnership adopted Statement of Financial Accounting Standards (“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 Partnership has a legal obligation to perform certain clean-up and security procedures. As such the Partnership has assessed the probability of when this will occur and the related cost. Upon implementation of this statement, the Partnership recorded $44,000 of property, plant and equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, $9,000 of accumulated depreciation through December 31, 2002 and an asset retirement obligation of $84,000. The cumulative effect of the change in accounting principle as a result of adopting this statement was a loss of $49,000.

If this statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the six months ended June 30, 2003 would not have been material.

In June 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for exit and disposal activities initiated after December 31, 2002. In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. This Interpretation establishes new disclosure requirements for all guarantees, but the measurement criteria are applicable to guarantees

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issued and modified after December 31, 2002. Both SFAS No. 146 and Interpretation No. 45 were adopted on January 1, 2003 and did not have an impact on the Partnership’s consolidated financial statements.

4.     RELATED PARTY TRANSACTIONS:

The Partnership has a Management Services Agreement with NEG for the day-to-day management and administration of the Partnership’s business relating to the Facility. The agreement commenced on September 30, 1992 and will continue through August 31, 2026. The cost of services is included in general and administrative expenses in the accompanying consolidated statements of operations. The total amount due to NEG for these services for the six months ended June 30, 2003 is $389,000, all of which is subordinated pursuant to the Disbursement Agreement.

The Partnership has an Operation and Maintenance Agreement with PG&E OSC, for the operations and maintenance of the Facility for a period of 30 years (starting September 30, 1992). Compensation to PG&E OSC under the agreement includes an annual base fee of which a portion is subordinate to debt service and certain other costs. The base fee is included in operating and maintenance expenses in the accompanying consolidated statements of operations. The total amount due to PG&E OSC for these services for the six months ended June 30, 2003 is $904,000, of which $151,000 is subordinated pursuant to the Disbursement Agreement.

5.     LETTERS OF CREDIT:

The Partnership, pursuant to certain of the contracts, is 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 these seven year term loans is 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 Power Purchase Agreement (“PPA”) has expired. The $1.7 million was deposited into the Revenue Account as required by the Disbursement Agreement. The Partnership intends to repay the FPL term loan as specified in 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 (formerly known as Banque Nationale de Paris). Pursuant to the terms of the Disbursement Agreement, since the debt service reserve letter of credit will expire on November 22, 2005, available cash flows are required to be deposited on a monthly basis beginning on May 22, 2002 into the Debt Service Reserve Account or the Tax Exempt Debt Service Reserve Account, as the case may be, until the required Debt Service Reserve Account Maximum Balance is achieved, which is $29.9 million.

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The Partnership made deposits totaling $6.0 million through July 31, 2003 and expects to have the required balance fully funded by the end of the first quarter of 2005.

6.     NEW COAL PURCHASE, RAIL TRANSPORTATION AND ASH DISPOSAL AGREEMENTS:

A Back-up 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 Back-up Coal Agreement, Massey will provide coal under substantially similar terms to the Coal Supply Agreement, which the Partnership had with Lodestar Energy, Inc. prior to the termination of the agreement on March 31, 2003. The base coal price is $33.75 per ton with a market price reopener provision beginning in October 2003.

On July 28, 2003 the Partnership and Massey agreed in principal to amend the Back-up Coal Agreement effective August 1, 2003. The principal change effected in the Back-up Coal Agreement is 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 is working on satisfying the applicable conditions precedent set forth in the financing documents relating to the amendment and expects this to be completed in the third quarter of 2003.

The Partnership and CSX Transportation (“CSX”) entered into a Coal Transportation Agreement dated August 6, 2003, which CSX will deliver coal to the Facility through December 31, 2025. In addition, CSX will transport a minimum of 500 carloads of ash to an acceptable disposal firm on the CSX rail system. For additional information, see Part II, Item 5, Replacement of Coal Supplier below.

7.     CONCENTRATIONS 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, who provides more than 99% of the Partnership revenues and is considered to be of investment grade.

Item 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements of the Partnership and the notes to the consolidated financial statements included herein. Further, this Quarterly

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Report on Form 10-Q should be read in conjunction with the Partnership’s 2002 Annual Report on Form 10-K.

Cautionary Statement Regarding Forward-Looking Statements

The information in this Quarterly Report on Form 10-Q includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. Use of words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could,” and similar expressions help identify forward-looking statements. These statements are based on current expectations and assumptions which the Partnership believes are reasonable and on information currently available to the Partnership. Actual results could differ materially from those contemplated by the forward-looking statements. Although the Partnership believes that the expectations reflected in the forward-looking statements are reasonable, future results, events, levels of activity, performance or achievements cannot be guaranteed. Although the Partnership is not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:

Operational Risks

The Partnership’s future results of operations 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 and fuel deliveries and prices.

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 Power Purchase Agreement (“PPA”).

Accounting and Risk Management

The Partnership’s future results of operations 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.

Litigation and Environmental Matters

The Partnership’s future results of operations 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.

Overview

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. In the 2003 agreement year the Facility is entitled to four weeks of outages to perform scheduled maintenance. Differences in the timing and scope of scheduled maintenance can have a significant impact on the revenues and operational costs.

The Partnership replaced its fuel supplier effective April 1, 2003. Please see Part II, Item 5, Other Information, for a description of the Partnership’s actions with respect to the replacement of the coal supplier.

The Partnership has obtained all material environmental permits and approvals required as of June 30, 2003, in order to continue the operation of the Facility. Certain of these permits and approvals are subject to periodic renewal. Certain additional permits and approvals will be required in the future for the continued operation of the Facility. The Partnership is not aware of any technical circumstances that would prevent the issuance of such permits and approvals or the renewal of currently existing permits.

Relationship with NEG, Inc.

On July 8, 2003, NEG, Inc. and certain subsidiaries voluntarily filed petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (collectively, the “NEG Bankruptcy”) in

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the Greenbelt Division of the United States Bankruptcy Court for the District of Maryland (the “Bankruptcy Court”).

Additionally, on July 8, 2003, NEG, Inc. filed its plan of reorganization (“the NEG Plan”). The NEG Plan anticipates that PG&E Corporation will have no equity interest in NEG, Inc. or any of its subsidiaries after the NEG Plan is confirmed by the court and implemented. On July 7, 2003, the officers of PG&E Corporation who were serving on the Board of Directors of NEG, Inc. resigned their positions. On July 7 and July 8, 2003, the NEG Board elected replacement directors who are not affiliated with PG&E Corporation. While continuing to maintain legal ownership, effective with this change in control of the Board and the NEG Bankruptcy, PG&E Corporation no longer retains significant influence over the ongoing operations of NEG, Inc.

Neither the Partnership nor any of its NEG, Inc. affiliates, including Toyan, IPILP, NEG and PG&E OSC, are parties to the filings by NEG, Inc. or other affiliates for protection under the NEG Bankruptcy. The Partnership believes that the NEG Bankruptcy will not have a material adverse impact on its operations. The NEG Bankruptcy does not result in an event of default under the principal project contracts or the principal financing documents of the Project.

NEG, Inc. owns an indirect interest in the Partnership, and through its wholly owned subsidiaries NEG and PG&E OSC manages and operates the Project. Management believes that the Partnership or its subsidiary will not be substantively consolidated with NEG, Inc. in any bankruptcy proceeding involving NEG, Inc.

Results of Operations

The following table sets forth operating revenue and related data for the three and six months ended June 30, 2003 and 2002 (dollars and volumes in millions).

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

     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.

Three Months Ended June 30, 2003 Compared to the Three Months Ended June 30, 2002

Overall Results

Net loss for the three months ended June 30, 2003, was approximately $1.0 million compared to the net income of approximately $0.5 million for the corresponding period in the prior year. The $1.5 million decrease is primarily attributable to an increase in operating and maintenance costs in 2003 of $2.1 million primarily due to increased costs for maintenance repairs and costs associated with the termination and replacement of the Coal Purchase and Transportation Agreement (see Part II, Item 5, Replacement of Coal Supplier), offset by the receipt of monthly capacity bonus payments in 2003 as compared to no receipt of bonus payments in 2002.

Operating Revenues

For the three months ended June 30, 2003, the Partnership had total operating revenues of approximately $44.8 million as compared to $40.0 million for the corresponding period in the prior year. The $4.8 million increase in operating revenue is primarily due to increased capacity bonus payments of $3.0 million due to the higher CBF, and an increase in electric energy revenue of $1.8 million resulting from the increase in the unit energy cost paid by FPL.

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Cost of Sales

Costs of sales for the three months ended June 30, 2003, were approximately $29.4 million as compared to $23.6 million for the corresponding period in the prior year. The overall cost of fuel and ash increased $3.6 million resulting from the termination of the coal purchase agreement and the increase in coal transportation costs paid under the CSX tariff rail rates (see Item 5 below). There was also an increase in operating and maintenance costs in 2003 of $2.2 million primarily due to repairs for tube leaks in the main boiler, as well as repairs to the auxiliary boiler and to the pulverizers.

Non-Operating Income (Expense)

Net interest expense for the three months ended June 30, 2003 and 2002 was approximately $13.6 million and $13.4 million, respectively. June 2002 and December 2002 principal payments of Series A-9 of the first mortgage bonds decreased interest expense by approximately $0.3 million. This was offset by an increase in interest expense of $0.1 million due to the conversion of the FPL Termination Fee and the LDC letters of credit into term loans and an increase of $0.4 million related to the amortization of deferred financing costs.

Six Months Ended June 30, 2003 Compared to the Six Months Ended June 30, 2002

Overall Results

Net income for the six months ended June 30, 2003, was approximately $3.6 million compared to the net income of approximately $2.3 million for the corresponding period in the prior year. The $1.3 million increase is primarily attributable to the receipt of monthly capacity bonus payments in 2003 as compared to no receipt of bonus payments in 2002, offset by costs associated with the termination and replacement of the Coal Purchase and Transportation Agreement (see Part II, Item 5, Replacement of Coal Supplier).

Operating Revenues

For the six months ended June 30, 2003, the Partnership had total operating revenues of approximately $89.6 million as compared to $82.3 million for the corresponding period in the prior year. The $7.3 million increase in operating revenue is primarily due to increased capacity bonus payments of $5.6 million due to the higher CBF, and an increase in electric energy revenue of $1.5 million resulting from the increase in the unit energy cost paid by FPL.

Cost of Sales

Costs of sales for the six months ended June 30, 2003, were approximately $53.7 million as compared to $48.1 million for the corresponding period in the prior year. The overall cost of fuel and ash increased $3.5 million resulting from the termination of the coal purchase agreement and the increase in coal transportation costs paid under the CSX tariff rail rates (see

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Item 5 below). There was also an increase in operating and maintenance costs in 2003 of $2.1 million primarily due to repairs for tube leaks in the main boiler, as well as repairs to the auxiliary boiler and to the pulverizers.

Non-Operating Income (Expense)

Net interest expense for the six months ended June 30, 2003 and 2002 was approximately $26.8 million. June 2002 and December 2002 principal payments of Series A-9 of the first mortgage bonds decreased interest expense by approximately $0.5 million. This was offset by an increase in interest expense of $0.1 million due to the conversion of the FPL Termination Fee and the LDC letters of credit into term loans and an increase of $0.4 million related to the amortization of deferred financing costs.

Liquidity and Capital Resources

Net cash provided by operating activities for the six months ended June 30, 2003 was approximately $11.1 million as compared to $5.5 million for the corresponding period in 2002. Net cash provided by operating activities represents net income, adjusted by non-cash expenses and income, which primarily consist of approximately $8.5 million of depreciation, amortization and accretion, plus the net effect of changes within the Partnership’s operating assets and liability accounts.

Net cash used in investing activities for the six months ended June 30, 2003 was approximately $2.8 million as compared to net cash provided by investing activities of $0.4 million for the six months ended June 30, 2002. Net cash used in investing activities increased due to an increase in investments held by the trustee.

Net cash used in financing activities for the six months ended June 30, 2003 was $8.1 million as compared to $5.9 million for the corresponding period in 2002. This increase is due to repayments of loans under the letter of credit agreement for $0.7 million and the increase of $1.5 million in the installment payment for the First Mortgage Bonds.

Credit Ratings

As previously reported on June 13, 2003, Moody’s Investors Service (“Moody’s”) announced its decision to downgrade the senior secured debt rating of Indiantown Cogeneration, L.P. (the “Partnership”) to Ba1 from Baa3. The rating action concludes the review for possible downgrade that was initiated on October 8, 2002. The rating outlook is negative. Moody’s stated that this rating action reflects the project’s weakened financial profile, particularly due to problems with operating performance, including outages during 2001 and 2002. Moody’s further stated that while Indiantown anticipates financial improvement in the next few years, prospective coverage ratios are anticipated to be in the 1.30x to 1.40x range, below the level that would be consistent with a Baa3 rating for a coal-fired project. The rating action also incorporates some uncertainty relating to the price redetermination of a coal purchase contract,

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and further considers that the Partnership will be required to use any excess cash to fund or repay third party obligations over the next several years relating to three letters of credit, the largest of which is used to support the project’s six-month debt reserve of approximately $29 million. The negative outlook incorporates the involvement of NEG, Inc., as operator and as a partial owner.

As previously reported 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 NEG Inc.’s subsidiaries. S&P stated these ratings actions follow the NEG Bankruptcy. S&P further stated that the rating on Indiantown Cogeneration Funding Corporation is not affected by the ratings action on NEG, Inc. because this project financing is structured as a bankruptcy-remote entity and is not 100% owned by NEG, Inc. Therefore, S&P concluded the incentive to consolidate it in a bankruptcy of NEG, Inc. is low. S&P’s rating of the Partnership’s debt remains at “BBB- with a negative outlook”.

The downgrade by Moody’s does not trigger any requirements under the Partnership’s financing documents.

Bonds

The Partnership’s total borrowings from inception through June 30, 2003 were $769 million. An equity loan of $139 million was repaid on December 26, 1995. As of June 30, 2003, the borrowings included $125 million from the 1994 Tax Exempt Bonds and all of the available First Mortgage Bond proceeds.

The weighted average interest rate paid by the Partnership on its debt for the six months ended June 30, 2003 and 2002 was 9.201% and 9.202%, respectively.

Credit Agreements

The Partnership, pursuant to certain of the contracts, is 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 these seven year term loans is 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 Power Purchase Agreement (“PPA”) has expired. The $1.7 million was deposited into the Revenue Account as required by the Disbursement Agreement. The Partnership intends to repay the FPL term loan as specified in the Disbursement Agreement.

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The Partnership entered into a debt service reserve letter of credit and reimbursement agreement, dated as of November 1, 1994, with BNP Paribas (formerly known as Banque Nationale de Paris). Pursuant to the terms of the Disbursement Agreement, since the debt service reserve letter of credit will expire on November 22, 2005, available cash flows are required to be deposited on a monthly basis beginning on May 22, 2002 into the Debt Service Reserve Account or the Tax Exempt Debt Service Reserve Account, as the case may be, until the required Debt Service Reserve Account Maximum Balance is achieved, which is $29.9 million. The Partnership made deposits totaling $6.0 million through July 31, 2003 and expects to have the required balance fully funded by the end of the first quarter of 2005.

In order to provide for the Partnership’s working capital needs, the Partnership entered into a Revolving Credit Agreement with Credit Suisse dated as of November 1, 1994. In September 2001, Credit Suisse notified the Partnership of its intention not to extend the term of the agreement, which expired on November 22, 2001.

The Partnership is actively engaging in discussions with financial institutions to obtain replacement letters of credit and a working capital facility; however, the Partnership cannot give assurances that it will be successful in obtaining replacement letters of credit and a working capital facility.

The Partnership believes that it will have adequate cash flows from operations in 2003 to timely fund all future working capital, capital expenditures, major maintenance requirements and cover debt repayment obligations.

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 is 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. As of June 30, 2003, a 10% decrease in interest rates would be immaterial to the Partnership’s consolidated financial statements.

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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 is in the process of conducting its audit of the 2002 documentation provided by the Partnership of actual energy costs to determine if 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, which was the basis for the index. The Partnership and FPL, within one year, shall agree upon a comparable replacement index.

Significant Commitments

There have been no new significant contractual obligations or commercial commitments since December 31, 2002 other than the coal, rail and ash agreements disclosed in Part II, Item 5, Replacement of Coal Supplier below.

Critical Accounting Policies

The Partnership is following the same accounting principles discussed in the Partnership’s December 31, 2002 Annual Report on Form 10-K.

Accounting Principles Issued But Not Yet Adopted

In January 2003, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity or arrangement it is involved. A “variable interest entity” is an entity that does not have sufficient equity investment at risk to permit the entity to finance its activities without additional subordinated financial support from other parties or an entity where equity investors lack the essential characteristics of a controlling financial interest.

Until the issuance of FIN 46, a company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is

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subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns, or both. A company that consolidates a variable interest entity is now referred to as the “primary beneficiary” of that entity.

FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Partnership between February 1, 2003 and June 30, 2003. The consolidation requirements are applicable to the Partnership in the third quarter 2003. The Partnership is currently evaluating the impacts of Interpretation No. 46’s initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements, and is currently unable to estimate variable interest entities that will be consolidated or disclosed when FIN 46 becomes effective.

Legal Matters

The Partnership is currently not involved in any legal proceedings.

Regulations and Environmental Matters

The Partnership has obtained all material environmental permits and approvals required, as of June 30, 2003, in order to continue commercial operation of the Facility. Certain of these permits and approvals are subject to periodic renewal. The Partnership is not aware of any technical circumstances that would prevent the issuance of such permits and approvals or the renewal of currently issued permits.

Item 3 QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

The Partnership is exposed to market risk from changes in interest rates and energy commodity prices 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 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations above).

Item 4 CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of the Partnership’s disclosure controls and procedures conducted on July 16, 2003, the Partnership’s principal executive officer and principal financial officer of Indiantown Cogeneration, L.P. and Indiantown Cogeneration Funding Corporation have concluded that such controls and procedures effectively ensure that information required to be

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disclosed by the Partnership in reports the Partnership files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission (“SEC”) rules and forms.

Changes in Internal Controls

There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

PART II
OTHER INFORMATION

Item 5 OTHER INFORMATION

Replacement of Coal Supplier

The Partnership had a coal purchase agreement (the “Coal Purchase Agreement”) with Lodestar Energy, Inc. (LEI) pursuant to which LEI supplied all of the coal for the facility. On April 27, 2001, an order for relief was entered in the Involuntary Petition under Chapter 11 of the United States Bankruptcy Code with respect to LEI and its parent, Lodestar Holdings Inc. (“LHI”), in the U.S. Bankruptcy Court in Lexington, Kentucky. Since that time, LHI and LEI have been operating their business as “debtors in possession.”

A new Ash Disposal Agreement was executed on February 1, 2003 between the Partnership and VFL Technology Corp. (“VFL”) and has a term of four years with an option for an additional two years. The agreement calls for the nominal removal of 1,000 to 1,500 tons of dry fly ash per week, which is approximately 50% of the fly ash produced each week, and allows for the removal of up to 100% of the fly ash produced by the Facility. The disposal fee is $21.85 per ton and is adjusted quarterly beginning on May 1, 2003 in accordance with a Producer Price Index, which includes labor to load trucks, the transportation vehicles, transportation costs and disposal fee. This agreement, combined with other current ash disposal agreements, allows the Partnership to dispose of all of the Partnership’s ash without relying on Lodestar. The Partnership has satisfied the applicable conditions precedent set forth in the Partnership’s financing documents relating to the entering into of the Ash Disposal Agreement.

A Back-up Coal Agreement was executed on February 5, 2003 between the Partnership and Massey Coal Sales, Inc. (“Massey”). Under the Back-up Coal Agreement, Massey provides coal under substantially similar terms to the Coal Supply Agreement should the Coal Supply Agreement with Lodestar be terminated. The base coal price is $33.75 per ton with a market price reopener provision beginning in October 2003.

On March 20, 2003, the Partnership and a bankruptcy court appointed trustee negotiated a settlement which effectively terminated the Coal Purchase Agreement as of March 31, 2003. A motion for an order approving the settlement was filed in the U.S. Bankruptcy Court on March 21, 2003. An order approving the settlement was entered by the Bankruptcy Court on April 4,

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2003. At closing, the Partnership made a settlement payment to the court appointed trustee, on behalf of LEI, in the amount of $805,000 and general releases in form and substance mutually acceptable were exchanged between the Partnership and LEI. One outstanding release has not yet been exchanged regarding the Transportation Agreement and monies owed to the rail transporter, CSX from LEI. Until such a release is obtained, $195,000 will be placed into an escrow account. Once the order approving the settlement was entered, the Back-up Coal Agreement became effective retroactively to the date of termination of the Coal Purchase Agreement specified in the settlement. Upon the receipt of the release, the Transportation Agreement will revert to the Partnership. The Partnership has satisfied the applicable conditions precedent set forth in the Partnership’s financing documents relating to the entering into of this settlement.

The Partnership and CSX have had discussions related to the Transportation Agreement and CSX has taken a position that approximately $1.1 million in pre-petition and gap debt owed to CSX from LEI must be paid by the Partnership before the Transportation Agreement can be implemented. The Partnership and CSX entered into a Coal Transportation Agreement dated August 6, 2003, which CSX will deliver coal to the Facility through December 31, 2025 at the system car rate of $23.09, 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 will rebate the Partnership 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 the $1.1 million in pre-petition and gap debt owed to CSX from LEI. Upon payment of the rebate, CSX will assign to the Partnership their claim to the $1.1 million due from LEI under the Transportation Agreement. The Partnership is working on satisfying the applicable conditions precedent set forth in the financing documents relating to the Coal Transportation Agreement and expects this to be completed in the third quarter of 2003.

On July 28, 2003 the Partnership and Massey agreed in principal to amend the Back-up Coal Agreement effective August 1, 2003. The principal change effected in the Back-up Coal Agreement is 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 is working on satisfying the applicable conditions precedent set forth in the financing documents relating to the amendment and expects this to be completed in the third quarter of 2003.

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Item 6 EXHIBITS AND REPORTS ON FORM 8-K

a) Exhibits:

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b) Reports on Form 8-K:

The Partnership filed a current report on Form 8-K dated June 17, 2003 announcing the decision of Moody’s Investors Service to downgrade the senior secured debt rating of Indiantown Cogeneration, L.P.

The Partnership filed a current report on Form 8-K dated July 8, 2003 announcing the Chapter 11 bankruptcy filing of PG&E National Energy Group, Inc.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized

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EXHIBIT INDEX