1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K/A CURRENT REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Date of Report: November 12, 1998; Date of Earliest Event Reported: October 20, 1998) Commission File Number: 33-74254 COGENTRIX ENERGY, INC. (Exact name of registrant as specified in its charter) North Carolina 56-1853081 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 9405 Arrowpoint Boulevard, Charlotte, North Carolina 28273-8110 (Address of principal executive offices) (Zipcode) (704) 525-3800 (Registrant's telephone number, including area code) 2 Item 7. Financial Statements and Exhibits This report is an amendment to the Cogentrix Energy, Inc. report on Form 8-K filed on November 4, 1998. The report is being amended to (i) include the audited year end and unaudited interim period financial statements for the partnerships and corporations acquired, and (ii) provide the unaudited pro forma consolidated condensed financial statements of Cogentrix Energy, Inc. as of June 30, 1998 and for the six-month periods ended June 30, 1998 and December 31, 1997, and for the year ended June 30, 1997. The following financial statements and unaudited pro forma financial information are filed as part of this Form 8-K/A: Page ---- (a) Financial Statements I. Logan Generating Company, L.P., Keystone Urban Renewal Limited Partnership, Northampton Generating Company L.P. and Subsidiaries, Chambers Cogeneration Limited Partnership, and Scrubgrass Generating Company, L.P. and Subsidiaries Report of Independent Public Accountants 5 Combined Balance Sheets as of June 30, 1998 (unaudited), December 31, 1997 and 1996 6 Combined Statements of Operations for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 7 Combined Statements of Changes in Partner's Capital for the Six-Month Period Ended June 30, 1998 (unaudited) and the Years Ended December 31, 1997, 1996 and 1995 8 Combined Statements of Cash Flows for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 9 Notes to Combined Financial Statements 10 II. Birch Power Corporation, Cedar Power Corporation, Hickory Power Corporation, Palm Power Corporation, and Panther Creek Leasing, Inc. Reports of Independent Public Accountants 29 Combined Balance Sheets as of June 30, 1998 (unaudited), December 31, 1997 and 1996 32 Combined Statements of Operations for the Six-Month Period Ended June 30, 1998 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 33 Combined Statements of Changes in Stockholder's Equity for the Six-Month Period Ended June 30, 1998 (unaudited) and the Years Ended December 31, 1997, 1996 and 1995 34 Combined Statements of Cash Flows for the Six-Month Period Ended June 30, 1998 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 35 Notes to Combined Financial Statements 36 III. Indiantown and Cedar Bay Report of Independent Public Accountants 41 Combined Balance Sheets as of June 30, 1998 (unaudited), December 31, 1997 and 1996 42 Combined Statements of Operations for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 43 Combined Statements of Changes in Partner's Capital for the Six-Month Period Ended June 30, 1998 (unaudited) and the Years Ended December 31, 1997, 1996 and 1995 44 Combined Statements of Cash Flows for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 45 Notes to Combined Financial Statements 46 2 3 IV. J. Makowski Company Report of Independent Public Accountants 60 Consolidated Balance Sheets as of June 30, 1998 (unaudited), December 31, 1997 and 1996 61 Consolidated Statements of Operations for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 62 Consolidated Statements of Changes in Shareholder's Equity for the Six-Month Period Ended June 30, 1998 (unaudited) and the Years Ended December 31, 1997, 1996 and 1995 63 Consolidated Statements of Cash Flows for the Six-Month Periods Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 64 Notes to Consolidated Financial Statements 65 V. Selkirk Cogen and Mass Power Report of Independent Public Accountants 81 Combined Balance Sheets as of June 30, 1998 (unaudited), December 31, 1997 and 1996 82 Combined Statements of Income for the Six Months Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 83 Combined Statements of Changes in Partner's Capital for the Six Months Ended June 30, 1998 (unaudited) and the Years Ended December 31, 1997, 1996 and 1995 84 Combined Statements of Cash Flows for the Six Months Ended June 30, 1998 (unaudited) and 1997 (unaudited) and for the Years Ended December 31, 1997, 1996 and 1995 85 Combined Notes to Financial Statements 86 (b) Cogentrix Energy, Inc. and Subsidiary Companies Unaudited Pro Forma Financial Information Unaudited Pro Forma Consolidated Balance Sheet as of June 30, 1998 102 Notes to Unaudited Pro Forma Consolidated Balance Sheet 103 Unaudited Pro Forma Consolidated Condensed Statement of Operations for the Six-Month Period Ended June 30, 1998 104 Unaudited Pro Forma Consolidated Condensed Statement of Operations for the Six-Month Period Ended December 31, 1997 105 Unaudited Pro Forma Consolidated Condensed Statements of Operations for the Twelve-Month Period Ended June 30, 1997 106 Notes to Unaudited Pro Forma Consolidated Condensed Statements of Operations for the Six-Month Period Ended June 30, 1998, December 31, 1997 and for the Twelve-Month Period Ended June 30, 1997 107 3 4 ------------------------------ SIGNATURE 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. COGENTRIX ENERGY, INC. (Registrant) Date: November 12, 1998 /s/ JAMES R. PAGANO ---------------------------------- James R. Pagano Group Senior Vice President, Chief Financial Officer (Principal Financial Officer) 4 5 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Logan Generating Company, L.P., Keystone Urban Renewal Limited Partnership, Northampton Generating Company, L.P., Chambers Cogeneration Limited Partnership, and Scrubgrass Generating Company, L.P.: We have audited the accompanying combined balance sheets of Logan Generating Company, L.P. (a Delaware limited partnership), Keystone Urban Renewal Limited Partnership (a Delaware limited partnership), Northampton Generating Company, L.P. (a Delaware limited partnership) and subsidiaries, Chambers Cogeneration Limited Partnership (a Delaware limited partnership) and Scrubgrass Generating Company, L.P. (a Delaware limited partnership) and subsidiaries as of December 31, 1997 and 1996, and the related combined statements of operations, changes in partners' capital and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Partnerships' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Logan Generating Company, L.P., Keystone Urban Renewal Limited Partnership, Northampton Generating Company, L.P. and subsidiaries, Chambers Cogeneration Limited Partnership and Scrubgrass Generating Company, L.P. and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Washington, D.C. January 15, 1998 5 6 LOGAN GENERATING COMPANY, L.P. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES CHAMBERS COGENERATION LIMITED PARTNERSHIP SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES COMBINED BALANCE SHEETS AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996 (DOLLARS IN THOUSANDS) DECEMBER 31, JUNE 30, ----------------------- 1998 1997 1996 ----------- ---------- ---------- (UNAUDITED) ASSETS CURRENT ASSETS: Cash and cash equivalents.............................. $ 13,325 $ 8,559 $ 3,459 Restricted cash........................................ 2,103 4,171 4,539 Accounts receivable.................................... 29,908 28,735 27,138 Notes and loans receivable -- current portion.......... -- 912 385 Fuel inventory......................................... 8,152 7,603 7,691 Prepaid expenses and other............................. 8,022 3,332 4,651 ---------- ---------- ---------- Total current assets........................... 61,510 53,312 47,863 INVESTMENTS HELD BY TRUSTEE.............................. 28,414 25,509 29,469 RESTRICTED CASH.......................................... -- 1,208 31,792 NET INVESTMENT IN LEASE.................................. 230,101 228,936 226,228 LAND AND EASEMENTS....................................... 15,646 15,646 15,646 PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $112,177 (unaudited), $106,282 and $76,376, respectively.................................. 1,176,082 1,192,523 1,216,839 LONG-TERM NOTES RECEIVABLE............................... 2,864 4,400 2,312 DEFERRED FINANCING COSTS, net of accumulated amortization of $17,482 (unaudited), $13,706 and $10,531, respectively........................................... 20,446 21,347 22,365 OTHER CAPITALIZABLE COSTS, net of accumulated amortization of $11,991 and $8,970, respectively....... -- 490 654 OTHER LONG-TERM ASSETS................................... 225 463 445 ---------- ---------- ---------- $1,535,288 $1,543,834 $1,593,613 ========== ========== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES: Current portion of long-term debt...................... $ 29,476 $ 35,262 $ 40,366 Accounts payable....................................... 7,509 6,537 7,688 Interest payable....................................... 12,049 10,743 11,517 Accrued liabilities.................................... 10,632 9,263 6,125 ---------- ---------- ---------- Total current liabilities...................... 59,666 61,805 65,696 MAJOR MAINTENANCE RESERVE................................ 6,590 5,682 4,024 LONG-TERM DEBT........................................... 1,198,101 1,209,802 1,226,723 ---------- ---------- ---------- Total liabilities.............................. 1,264,357 1,277,289 1,296,443 PARTNERS' CAPITAL........................................ 270,931 266,545 297,170 ---------- ---------- ---------- $1,535,288 $1,543,834 $1,593,613 ========== ========== ========== The accompanying notes are an integral part of these combined balance sheets. 6 7 LOGAN GENERATING COMPANY, L.P. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES CHAMBERS COGENERATION LIMITED PARTNERSHIP SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES COMBINED STATEMENTS OF OPERATIONS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) SIX-MONTH PERIODS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ------------------------------ 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- -------- (UNAUDITED) (UNAUDITED) OPERATING REVENUE: Electric capacity and capacity bonus............................. $ 50,261 $ 50,304 $101,001 $100,112 $ 94,683 Electric energy revenue.............. 60,917 59,337 117,015 113,243 76,420 Steam revenue........................ 4,673 5,238 9,423 9,318 9,662 Interest rate mode agreement......... 15,636 15,314 30,628 31,336 33,719 Lease revenues....................... 8,287 8,212 16,172 17,151 18,474 Other revenue........................ 5,839 576 2,374 2,205 -- -------- -------- -------- -------- -------- 145,613 138,981 276,613 273,365 232,958 -------- -------- -------- -------- -------- OPERATING EXPENSES: Fuel and ash......................... 30,817 31,350 63,957 62,675 52,686 Operating and maintenance............ 22,004 15,662 35,246 33,059 26,149 General and administrative........... 2,776 3,334 5,248 6,116 4,189 Insurance and taxes.................. 3,473 3,474 7,136 7,749 7,229 Depreciation and amortization........ 16,540 15,429 30,176 37,667 32,725 -------- -------- -------- -------- -------- 75,610 69,249 141,763 147,266 122,978 -------- -------- -------- -------- -------- OPERATING INCOME....................... 70,003 69,732 134,850 126,099 109,980 -------- -------- -------- -------- -------- OTHER INCOME (EXPENSE): Interest expense..................... (42,669) (45,572) (96,362) (97,702) (85,798) Other................................ (1,658) 1,048 3,124 3,805 4,361 -------- -------- -------- -------- -------- (44,327) (44,524) (93,238) (93,897) (81,437) -------- -------- -------- -------- -------- NET INCOME BEFORE INCOME TAXES......... 25,676 25,208 41,612 32,202 28,543 BENEFIT (PROVISION) FOR INCOME TAXES... -- -- 42 (41) -- -------- -------- -------- -------- -------- NET INCOME............................. $ 25,676 $ 25,208 $ 41,654 $ 32,161 $ 28,543 ======== ======== ======== ======== ======== The accompanying notes are an integral part of these combined statements. 7 8 LOGAN GENERATING COMPANY, L.P. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES CHAMBERS COGENERATION LIMITED PARTNERSHIP SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES COMBINED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) PARTNERS' CAPITAL, DECEMBER 31, 1994........................ $245,421 Capital contributions..................................... 15,658 Net income................................................ 28,543 -------- PARTNERS' CAPITAL, DECEMBER 31, 1995........................ 289,622 Capital distributions..................................... (24,613) Net income................................................ 32,161 -------- PARTNERS' CAPITAL, DECEMBER 31, 1996........................ 297,170 Capital distributions..................................... (72,279) Net income................................................ 41,654 -------- PARTNERS' CAPITAL, DECEMBER 31, 1997........................ 266,545 Capital distributions..................................... (21,290) Net income................................................ 25,676 -------- PARTNERS' CAPITAL, JUNE 30, 1998 (UNAUDITED)................ $270,931 ======== The accompanying notes are an integral part of these combined statements. 8 9 LOGAN GENERATING COMPANY, L.P. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES CHAMBERS COGENERATION LIMITED PARTNERSHIP SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) SIX-MONTH PERIODS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ------------------------------- 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- --------- (UNAUDITED) (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net income........................................ $ 25,676 $ 25,208 $ 41,654 $ 32,161 $ 28,543 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization................... 16,615 16,486 33,342 40,510 33,465 Amortization of unearned lease income........... (9,382) (8,169) (18,384) (17,888) (17,855) Decrease in restricted cash..................... (838) -- 83 763 3,332 (Increase) decrease in accounts receivable...... 10,296 8,378 14,179 14,578 (3,947) Decrease (increase) in fuel inventory........... (549) (1,131) 88 (1,450) 1,153 Decrease (increase) in deposits................. (4) (3) (18) (133) 2,265 Decrease (increase) in prepaid expenses......... (1,904) (8,211) 1,319 (464) (1,058) Increase in notes receivable.................... (553) 349 (2,615) (1,068) (20) Increase (decrease) in accounts payable and other accrued liabilities..................... 2,340 6,509 1,987 (4,005) 2,215 Increase in major maintenance reserve........... 908 (516) 84 1,556 2,396 Increase (decrease) in interest payable......... 1,306 (479) 800 (472) 844 -------- -------- -------- -------- --------- Net cash provided by operating activities............................... 43,911 38,421 72,519 64,088 51,333 -------- -------- -------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Decrease in investment held by trustee............ -- (528) 3,960 2,643 27,123 Payment for construction in progress, including capitalized interest............................ -- -- -- -- (32,991) Additions to property, plant and equipment........ (1,493) (1,019) (5,597) (2,720) (74,541) Adjustments to property, plant and equipment...... -- -- -- 120 -- -------- -------- -------- -------- --------- Net cash (used in) provided by investing activities............................... (1,493) (1,547) (1,637) 43 (80,409) -------- -------- -------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease (increase) in restricted cash for financing....................................... 1,208 28,672 30,869 (4,801) (7,930) Decrease (increase) in deferred financing costs... -- (163) (2,347) 14 (2,547) Proceeds from long-term debt...................... -- 2,191 19,775 8,662 415,496 Repayment of long-term debt....................... (17,488) (11,226) (41,800) (41,630) (396,086) Increase in other equity.......................... (82) (82) -- -- -- Capital (distributions) contributions............. (21,290) (47,526) (72,279) (24,613) 15,658 -------- -------- -------- -------- --------- Net cash (used in) provided by financing activities............................... (37,652) (28,134) (65,782) (62,368) 24,591 -------- -------- -------- -------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....................................... 4,766 8,740 5,100 1,763 (4,485) CASH AND CASH EQUIVALENTS, beginning of year........ 8,559 3,459 3,459 1,696 6,181 -------- -------- -------- -------- --------- CASH AND CASH EQUIVALENTS, end of year.............. $ 13,325 $ 12,199 $ 8,559 $ 3,459 $ 1,696 ======== ======== ======== ======== ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid for interest............................ $ 89,398 $ 91,951 $ 96,249 ======== ======== ========= The accompanying notes are an integral part of these combined statements. 9 10 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS AS OF DECEMBER 31, 1997, 1996 AND 1995 1. ORGANIZATION AND BUSINESS LOGAN GENERATING COMPANY, L.P. Logan Generating Company, L.P. ("Logan"), formerly Keystone Energy Service Company, L.P., is a Delaware limited partnership formed on October 4, 1991. The general partners of Logan are Aspen Power Corporation ("Aspen"), a Delaware corporation and a wholly owned subsidiary of Bechtel Generating Company, Inc. ("BGCI") and Eagle Power Corporation ("Eagle"), a California corporation and a wholly-owned subsidiary of PG&E Generating Company ("PGC"). Eagle is also a limited partner of Logan. PGC will transfer its entire ownership interest in Eagle to U.S. Generating Company, LLC ("USGenLLC") pending approval by the Federal Energy Regulatory Commission ("FERC"). The transfer will be retroactive to December 31, 1997. The net operating profits and losses of Logan are allocated to Aspen and Eagle (collectively, the "Logan Partners") based on the following ownership percentages: GENERAL PARTNERS: Aspen..................................................... 50% Eagle..................................................... 49% LIMITED PARTNER: Eagle..................................................... 1% All distributions other than liquidating distributions will be made based on the Logan Partners' percentage interests as shown above, in accordance with the project documents and at such times and in such amounts as the Board of Control of Logan determines. KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP Keystone Urban Renewal Limited Partnership ("Urban") is a Delaware limited partnership formed on September 13, 1991. The general partner of Urban is Keystone Cogeneration Company Limited Partnership ("Keystone"), a Delaware limited partnership whose general partners are Aspen (50%) and Eagle (49%), and whose limited partner is Eagle (1%). The limited partner of Urban is Granite Generating Company, L.P. ("Granite"), a Delaware limited partnership whose general partners are Aspen (50%) and Eagle (49%), and whose limited partner is Eagle (1%). The operating profits and losses of Urban are allocated to Keystone and Granite based on the following ownership percentages: GENERAL PARTNER: Keystone.................................................. 99% LIMITED PARTNER: Granite................................................... 1% All distributions other than liquidating distributions will be made based on the percentage interests as shown above, in accordance with the project documents and at such times and in such amounts as the general partner determines. 10 11 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) Logan and Urban (collectively, the "Logan Partnerships") were formed to develop, construct, own and operate a 217 megawatt ("mw") pulverized coal-fired cogeneration station (the "Logan Project") in the Township of Logan, New Jersey. Urban holds title to the land upon which the Logan Project is situated as well as the Logan Project itself. Logan leases the Logan Project from Urban pursuant to a facilities lease agreement dated April 1, 1992. The lease commenced on the first funding date of the Logan Project's construction, and will terminate upon 1) the merger of the Logan Partnerships, 2) mutual consent between the Logan Partnerships and the Township of Logan, or 3) final payment of the Logan Partnerships' obligations incurred to finance the Logan Project. The Logan Project is designed to produce electricity for sale to Atlantic City Electric Company ("ACEC") and process steam for sale to Monsanto Chemical Company ("Monsanto") for use in its industrial operations. Logan assigned the Monsanto steam and electricity sales agreement to ACEC effective September 24, 1996. The Logan Project entered commercial operations and achieved final completion in 1994. NORTHAMPTON GENERATING COMPANY, L.P. Northampton Generating Company, L. P. ("Northampton") is a Delaware limited partnership formed on July 2, 1991. The partners are Jaeger Power Corporation ("Jaeger"), a wholly-owned indirect subsidiary of USGenLLC and Poplar Power Corporation ("Poplar"), a wholly-owned subsidiary of BGCI. Northampton was formed to construct, own and operate a 98 mw anthracite waste coal-fired electric generating project (the "Northampton Project") located in Northampton, Pennsylvania. The Northampton Project is designed to produce electricity for sale to Metropolitan Edison Company. The Northampton Project also sells a minimum of 104 million pounds per year of process steam to an unrelated third party for use in its industrial operations. The net operating profits and losses of Northampton are allocated to Jaeger and Poplar (collectively, the "Northampton Partners") based on the following ownership percentages: Jaeger...................................................... 50% Poplar...................................................... 50% All distributions other than liquidating distributions will be made based on the Northampton Partners' percentage interests as shown above, in accordance with the Northampton Project documents and at such times and in such amounts as the Board of Control of the partnership determines. The Northampton Partners have entered into equity commitment agreements which require funding up to $11,225,000 for certain Northampton Project conditions defined in the Northampton Project documents. Northampton Fuel Supply Company, Inc. (the "Fuel Company") is a wholly-owned subsidiary of Northampton. The Fuel Company was formed to (1) obtain, hold or dispose of culm, silt, tailings or other fuel components for the Northampton Project, (2) to build, construct, own or lease, operate, maintain, repair, replace or refurbish facilities, equipment, systems, components, parts, supplies or other materials necessary to obtain, handle or process or prepare such fuel components, and (3) to provide such fuel components to Northampton or any other owner or operator of the Northampton Project. Northampton Water Company, Inc. (the "Water Company") is a wholly-owned subsidiary of Northampton. The Water Company was formed to own, lease or otherwise acquire certain rights and interests and to perform certain obligations relating to the water supply for the Northampton Project. 11 12 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) CHAMBERS COGENERATION LIMITED PARTNERSHIP Chambers Cogeneration Limited Partnership ("Chambers") is a Delaware limited partnership formed on August 17, 1988. The general partners of Chambers are Peregrine Power Corporation ("Peregrine"), a California corporation and a wholly-owned indirect subsidiary of USGenLLC, and Maple Power Corporation ("Maple"), a Delaware corporation and a subsidiary of BGCI. TIFD III-T, Inc. ("TIFD"), a wholly-owned subsidiary of General Electric Capital Corporation ("GECC"), is a limited partner. Chambers is not to continue in existence beyond December 31, 2028. Chambers was formed to construct, own and operate a 262 mw coal-fired cogeneration station (the "Chambers Project") at DuPont's Chambers Works chemical complex near Carneys Point, New Jersey. The Chambers Project is designed to produce electricity for sale to ACEC, and electricity and process steam for sale to E.I. DuPont de Nemours & Company ("DuPont") for use in its industrial operations. The Chambers Project entered commercial operations and achieved final completion in 1994. Chambers is managed by U.S. Generating Company ("USGen") pursuant to a Management Services Agreement (the "MSA"). The Facility is operated by U.S. Operating Services Company ("USOSC") pursuant to an Operation and Maintenance Agreement (the "O&M Agreement"). USGen and USOSC are general partnerships originally formed between affiliates of PG&E Enterprises and Bechtel Enterprises. On September 19, 1997, USGen and USOSC each separately redeemed Bechtel Enterprises' interests in USGen and USOSC so that PG&E Enterprises now indirectly owns all of the interests in USGen and USOSC. This will not affect USGen's obligations under the MSA or USOSC's obligations under the O&M Agreement. In addition, on September 19,1997, Peregrine purchased one-third of Maple's interest in Chambers, which represents a 5% ownership interest. The net income and losses of Chambers are allocated to Peregrine, Maple and TIFD (collectively, the "Chambers Partners") based on the following ownership percentages. POST PRE 9/20/97 9/20/97 ------- ------- Peregrine.................................................. 50% 45% Maple...................................................... 10% 15% TIFD....................................................... 40% 40% All distributions other than liquidating distributions are made based on the Chambers Partners' percentage interests as shown above, in accordance with the Chambers Project documents and at such times and in such amounts as the Board of Control of Chambers determines. SCRUBGRASS GENERATING COMPANY, L.P. Scrubgrass Generating Company, L.P. ("Scrubgrass") is a Delaware limited partnership formed on December 1, 1990. The general partners of Scrubgrass are Falcon Power Corporation ("Falcon"), a California corporation and a wholly-owned indirect subsidiary of USGenLLC; Scrubgrass Power Corporation ("SPC"), a Pennsylvania corporation and a wholly-owned subsidiary of Falcon; and Pine Power Leasing, Inc. ("Pine"), a Delaware corporation and a wholly-owned subsidiary of BGCI. Falcon is also a limited partner in Scrubgrass. DCC Project Finance Four, Inc. ("DCC"), a Delaware corporation and a wholly-owned subsidiary of Dana Commercial Credit Corporation, was admitted as a limited partner after acquiring a portion of Falcon's interest in Scrubgrass. Scrubgrass is not to continue in existence after December 31, 2030. 12 13 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) The purpose of Scrubgrass is to participate in the developing, financing, engineering, construction, ownership, operation, maintenance, and leasing of a waste coal-fired 87 mw (net) electrical generating facility located in Venango County, Pennsylvania (the "Scrubgrass Project"). The Scrubgrass Project commenced commercial operations in 1993, and Scrubgrass entered into a lease agreement with Buzzard Power Corporation ("Buzzard"), a wholly-owned subsidiary of Environmental Power Corporation ("EPC"), effective June 17, 1994. (See Note 4). Scrubgrass formed two subsidiaries: Clearfield Properties, Inc. ("Clearfield"), for the purpose of purchasing a 175-acre site in Clearfield County, Pennsylvania, and acquiring access to certain coal fines material, and Leechburg Properties, Inc. ("Leechburg"), for the purpose of acquiring access rights to certain waste coal sites. The net operating profits and losses of Scrubgrass are allocated to Falcon, SPC, Pine, and DCC (collectively, the "Scrubgrass Partners") based on the following sharing ratios, in accordance with the amended partnership agreement: GENERAL PARTNERS: Falcon.................................................... 24.63% SPC....................................................... 24.87% Pine...................................................... 20.00% LIMITED PARTNERS: Falcon.................................................... 0.50% DCC....................................................... 30.00% Distributions are made pursuant to the amended partnership agreement. Generally, distributions of basic rent (contractually scheduled payments in the lease) are made in accordance with the Scrubgrass Partners' sharing ratios as shown above, and distributions of additional rent (variable based on Buzzard's monthly distributable residual operating cash) are to be 20 percent to Pine and 80 percent to Falcon. During 1996, as a result of the expiration of the bond interest rate swap (see Note 3), Falcon began sharing a portion of its additional rent with DCC based on a formula of the lesser of 10 percent of the Falcon distribution or 4 percent of the savings differential between bond interest calculated at 6.5 percent per annum and the actual monthly all-in cost of the bonds including actual interest, the cost of credit support and remarketing fees payable by Scrubgrass. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: PRESENTATION The accompanying financial statements of Logan, Urban, Northampton, Chambers, and Scrubgrass (collectively, the "Partnerships") are presented on a combined basis due to the common management of the underlying projects of the Partnerships. All inter-partnership transactions have been eliminated in combination. The accompanying combined financial statements were prepared on the accrual basis of accounting in accordance with generally accepted accounting principles. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and 13 14 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. INTERIM FINANCIAL STATEMENTS Information presented as of June 30, 1998 and for the six-month periods ended June 30, 1998 and 1997 is unaudited. In the opinion of management, however, such information reflects all adjustments, which consist of normal recurring adjustments necessary to present fairly the financial position of the combined entities as of June 30, 1998 and the results of their operations and cash flows for the six-month periods ended June 30, 1998 and 1997. The results of operations for these interim periods are not necessarily indicative of results which may be expected for any other interim period or for the years as a whole. CASH AND CASH EQUIVALENTS For the purpose of reporting cash flows, cash equivalents include short-term investments with original maturities of three months or less. RESTRICTED CASH Restricted cash includes cash and cash equivalent amounts, as defined above, which are restricted under the terms of certain of the Partnerships' agreements. Restricted cash includes amounts restricted for debt service, major maintenance, subordinated operations and maintenance costs, and amounts escrowed with the Township of Logan and Logan Municipal Utilities Authority. Restricted cash amounts held for long-term use are classified as non-current assets. FUEL INVENTORY Fuel inventory is stated at the lower of cost or market using the average cost method. PREPAID EXPENSES Prepaid expenses include $358,101 and $540,644 of prepaid insurance expenses related to property damage and other general liability policies, $1,751,573 and $2,436,563 of advance funding for expenses related to operations and maintenance, $57,500 and $60,597 of prepaid agency and bond rating fees, $886,582 and $343,511 in prepaid fuel and ash site development costs, $132,418 and $978,300 in future relocation reserves, and $145,933 and $292,025 in other prepaid expenses at December 31, 1997 and 1996, respectively. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment, which consist primarily of the projects, are recorded at actual cost. The projects are depreciated on a straight-line basis over 35 years. As of January 1, 1997, two of the Partnerships prospectively revised their calculation of depreciation to include a residual value on the projects approximating 25 percent of the gross project costs. This change increased net income for 1997 by approximately $7.9 million. Other property, plant and equipment are depreciated on a straight-line basis over the estimated remaining economic or service lives of the respective assets (ranging from 5 to 10 years). Routine maintenance and repairs are charged to expense as incurred. 14 15 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) LEASE ACCOUNTING The lease described in Note 4 meets the criteria for a "sales-type" capital lease. Accordingly, the investment in lease, unearned lease income, and lease revenues are accounted for in conformity with Statement of Financial Accounting Standards No. 13, "Accounting for Leases" ("SFAS 13"). RIGHT TO FUEL INVENTORY Scrubgrass amortizes the right to remove fuel from their fee property located in Clearfield County over the estimated minimum life of available waste fuel fines using the straight-line method. For the years ended December 31, 1997, 1996 and 1995, $161,000 of annual amortization related to these costs has been included in amortization in the accompanying combined statements of operations. ORGANIZATION COSTS The Partnerships amortize organization costs over the life of the projects using the straight-line method. Annual amortization of these costs has been included in amortization expense in the accompanying combined statements of operations. DEFERRED FINANCING COSTS Financing costs, consisting primarily of the costs incurred to obtain project financing, are deferred and amortized using the effective interest rate method over the term of financing. Financing costs related to the Debt Service Reserve Letter of Credit (see Note 3) were capitalized and accrued in 1995. Actual total costs were less than estimated; accordingly, deferred financing costs were reduced by $175,750 in 1996. Deferred financing costs incurred to obtain the Bond Letter of Credit, the Working Capital Loan commitment and the Debt Service Loan commitment are amortized on a straight-line basis over the term of the related commitment, which is not materially different from the effective interest rate method. MAJOR MAINTENANCE RESERVE The major maintenance reserve represents an accrual for anticipated expenditures for scheduled significant maintenance of the projects. The accrual is recognized ratably over the maintenance cycle of the related equipment. INTEREST INCOME In 1995, interest income included a $513,966 gain related to the sale of zero coupon bonds. INCOME TAXES Under current law, no Federal or state income taxes are paid directly by the Partnerships. All items of income and expense of the Partnerships are allocable to and reportable by the partners in their respective income tax returns. Accordingly, no provision is made in the accompanying combined financial statements for Federal or state income taxes. Income taxes reported on the accompanying combined financial statements are Federal and State income taxes paid or accrued by Clearfield and Leechburg. 15 16 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 3. BONDS AND LOANS PAYABLE The following represents the total amounts of bonds and notes payable for the Partnerships. All bonds and loans payable are secured by the assets of the projects or the real estate covered by ground leases. NEW JERSEY ECONOMIC DEVELOPMENT AUTHORITY ("NJEDA") BONDS The NJEDA issued and sold $190,000,000 of its Exempt Facility Revenue Bonds (the "Bonds") in order to finance a portion of the costs of constructing and equipping both the Logan and Chambers Projects. The issuance of the Bonds was made pursuant to an Indenture of Trust, which named First Fidelity, N.A. and Citibank, N.A., respectively, as the bond trustees. The proceeds were lent to the Partnerships pursuant to the NJEDA Authority Loan Agreement. The Bonds, which are secured by an irrevocable letter of credit, provide for interest at variable rates. The weighted-average interest rates on the Bonds were 3.59% and 3.40% at December 31, 1997 and 1996, respectively. RESOURCE RECOVERY REVENUE BONDS In 1994, in order to finance a portion of the costs of constructing and equipping the Northampton Project and the culm facility, Northampton issued and sold $205 million of Resource Recovery Revenue Bonds through the Pennsylvania Economic Development Financing Authority. The bonds were issued in three series and feature maturity dates ranging from January 1, 2007 to January 1, 2021 and interest rates ranging from 6.40% to 6.95%. VIDA BONDS In order to finance a portion of the costs of constructing and equipping the Scrubgrass Project, the Venango Industrial Development Authority ("VIDA") issued and sold $135,600,000 of its resource recovery revenue bonds (Series 1990 A and B, and Series 1993 -- Scrubgrass Project). For the years ended December 31, 1997, 1996 and 1995, tax exempt interest was incurred on the outstanding bonds at an average rate of 3.68 percent, 3.72 percent and 4.00 percent, respectively. CREDIT AND REIMBURSEMENT AGREEMENTS Pursuant to the Third Amended and Restated Reimbursement and Loan Agreement (the "Reimbursement and Loan Agreement") dated as of November 1, 1995, the Logan Partnerships entered into a financing facility with a group of banks (the "Senior Lenders"). Funding from the financing facility is drawn on Union Bank of Switzerland, New York ("UBS"), as the agent for the Senior Lenders. The financing facility provides for a construction/term loan, a bond letter of credit, a debt service reserve letter of credit and a working capital loan. The Reimbursement and Loan Agreement is secured by the Logan Project. On January 1, 1994, in order to finance a portion of the costs of constructing and equipping the Northampton Project and the culm facility, Northampton entered into a Credit and Reimbursement Agreement with a group of banks (the "Northampton Banks") wherein the Northampton Banks would provide Northampton with a financing facility. Funding from the financing facility is drawn on ABN AMRO Bank N. V., as the agent for the Northampton Banks. In order to finance a portion of the costs of constructing and equipping the Chambers Project, Chambers entered into a credit agreement (the "Original Credit Agreement") in 1991 with a group of banks (the 16 17 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) "Chambers Banks"), wherein the Chambers Banks provided Chambers with a financing facility. Funding from the financing facility was drawn on Swiss Bank Corporation, New York ("Swiss Bank") as the agent for the Chambers Banks. The financing facility provided for a construction loan commitment, which was converted to a term loan commitment in 1994 (the "Chambers Conversion Date"), a supplemental loan commitment and a letter of credit commitment. On June 9, 1997 the Original Credit Agreement was amended (the "Amendment") and restated (the "Amended and Restated Credit Agreement"). The Amendment replaced Swiss Bank Corporation, New York with ING (U.S.) Capital Corporation ("ING") as the agent bank. The Amendment increased the amount of the debt by $7,939,750, extended the maturity of the debt five years from 2009 to 2014, and consolidated the term loans (the "Term Loans"). Chambers incurred $3,759,664 in financing costs in conjunction with the Amended and Restated Credit Agreement. Of this total, $2,346,219 representing creditor bank fees (including creditor legal costs) was capitalized as deferred financing costs and is being amortized using the effective interest rate method over the term of the debt as prescribed in EITF 96-19. The remainder was expensed as required by EITF 96-19. In order to finance a portion of the costs of constructing and equipping the Scrubgrass Project, Scrubgrass entered into the Reimbursement and Loan Agreement (the "Original RLA") with a group of banks (the "Scrubgrass Banks"), wherein the Scrubgrass Banks would provide Scrubgrass with various financing facilities. Funding from the financing facilities was initially drawn on National Westminster Bank, PLC, New York ("NatWest"), as the Agent for the Scrubgrass Banks. In December 1995, Scrubgrass entered into the Amended and Restated Reimbursement and Loan Agreement (the "New RLA") which provided a new term loan facility of $12,000,000. On May 22, 1997, Scrubgrass entered into an agreement to amend the New RLA which restructured the Debt Service Loan Commitment of $6,000,000. As defined in the New RLA, an applicable margin is added to the base component of interest rates for each type of loan under each of the loan facilities provided in the New RLA. The applicable margins consist of a Eurodollar and a base component and range from 1.50% to 1.75% over the term of the New RLA. CONSTRUCTION AND TERM LOANS The Logan term loan commitment was entered into on January 24, 1995 (the "Logan Conversion Date") and was drawn to repay the outstanding balance on the construction loan. The interest rate on the term loan is based upon various short-term indices at the Logan Partnerships' option and may be changed periodically, also at the Logan Partnerships' option. Upon the construction loan maturity date of September 22, 1995 (the "Construction Loan Maturity Date"), the Term Loan commitment was made available to Northampton and was drawn upon to repay the Construction Loan. The interest rate is based upon various short-term indices at Northampton's option and may be changed periodically, also at Northampton's option. It is calculated as set forth in the Credit and Reimbursement Agreement. For the three years ending September 30, 1998, interest is either (1) the base rate, which approximates the prime rate of interest plus a margin of 0.750 percent, (2) the London Interbank Offering Rate ("LIBOR") plus a margin of 1.500 percent, or (3) the CD rate plus a margin of 1.625 percent. At December 31, 1997 and 1996, the Term Loan interest rate was 7.44 and 7.32 percent respectively. 17 18 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) The original Chambers term loan was drawn in 1994 to repay the construction loan and the supplemental loan was drawn in late 1994 to fund additional construction costs. An additional term loan amount of $7,939,750 was drawn in 1997. The June 1997 Amendment combined the three outstanding loan facilities into one term loan facility ("Term Loan"). The interest on the Term Loan is based upon various short-term rates at Chamber's option and may be changed periodically, also at Chamber's option, within certain limitations as set forth in the Amendment. The term loan commitment became available to Scrubgrass on June 30, 1994 (the "Scrubgrass Conversion Date") and was drawn to repay the construction loan. Principal repayments, based on percentages of the outstanding balance ranging from 0.100 percent to 1.617 percent, will be due monthly between July 1995 and January 2006 according to an amortization schedule provided in the New RLA. Type and term for each loan under the facility is determined at Scrubgrass's option. The interest is determined as set forth in the New RLA and is either the Eurodollar rate plus the applicable margin, or a base rate, which is the higher of the Agent's prime rate or the federal funds rate, plus the applicable margin. BOND LETTER OF CREDIT In order to support certain payments of the NJEDA bonds, the Logan Partnerships requested the Senior Lenders to issue an irrevocable letter of credit. The committed amount of the letter of credit is reduced in the same amounts as the related bond principal is repaid. The expiration date may be extended for one-year periods, annually, at the sole discretion of the Senior Lenders. Draws upon the letter of credit are to be used for the payment of principal or interest on the bonds and are to be made only when funds are not available or adequate from the debt service fund or the bond redemption fund, as established in the Bond Indenture of Trust dated April 1, 1992. The Logan Partnerships do not expect a draw on the letter of credit. If any draws are made, however, interest is calculated at a default rate that approximates the prime rate of interest plus a margin of 2.0 percent. If there is any balance outstanding on the letter of credit, the Logan Partnerships also have the option of drawing on a liquidity commitment and a refunding notes commitment by the Senior Lenders. Interest on these draws is based on various short-term interest rates as chosen by the Logan Partnerships, plus an applicable margin. The refunding notes are used to repay the liquidity notes. The refunding notes are to be repaid according to amortization schedules set forth in the Reimbursement and Loan Agreement, with final payment on September 30, 2009. In order to support certain payments of its NJEDA bonds, Chambers requested the Chambers Banks to issue an irrevocable letter of credit. Interest is calculated at a base rate which approximates the prime rate of interest plus 2.0 percent and is payable upon demand. The letter of credit secures the NJEDA bonds. The letter of credit currently expires June 9, 2007. Upon request of Chambers, the expiration date of the letter of credit may be extended at the sole discretion of the Chambers Banks. In order to support principal and interest payments on the VIDA bonds, NatWest has issued an irrevocable letter of credit to Scrubgrass. In 1995, Credit Lyonnais became the Agent, replacing NatWest. Interest on the drawn portion is calculated as a base rate that approximates the prime rate of interest plus an additional margin as defined in the New RLA. 18 19 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) TERM LETTER OF CREDIT At the beginning of commercial operations on August 28, 1995 (the "Commercial Operation Date"), Northampton established an irrevocable letter of credit with a full commitment amount available up to $66.6 million and a stated amount, at the Commercial Operation Date of $7.154 million, determined pursuant to the Power Purchase Agreement. This letter of credit secures the balance in a suspense account, which balance is determined by factoring projected energy deliveries for each generation year (the anniversary of the Commercial Operation Date) by the excess of the contract energy sales rate over a projected rate. The suspense account and the letter of credit will be provided until the balance in the suspense account becomes a negative amount or until the end of the sixteenth generation year, whichever occurs earlier. If at the end of the sixteenth year a positive balance remains, Northampton will pay the utility the amount of the balance. In accordance with the terms of the Power Purchase Agreement, the stated amount of the term letter of credit was increased to $36,582,155 in January of 1997, and $36,983,156 in January of 1998. No draws were made against the term letter of credit during 1997 or 1996. DEBT SERVICE RESERVE LETTERS OF CREDIT In order to release $15,624,000 from a debt service reserve, the Logan Partnerships requested the Senior Lenders to consent to and issue a $20,000,000 letter of credit in its stead. The Senior Lenders consented and the letter of credit was integrated into the existing financing structure, creating the Reimbursement and Loan Agreement. The funds released were used to pay amounts due the construction contractor, costs to achieve the letter of credit and distributions to the Partners. The initial expiration date was November 15, 2000, with an annual provision of extending the five-year term at the sole discretion of the providers of the letter of credit. The letter of credit currently expires November 15, 2002. In accordance with Chambers' Amended and Restated Credit Agreement, the $25,000,000 debt service reserve account was replaced with a $22,750,000 letter of credit issued by the Chambers Banks. Interest on any outstanding balance is payable quarterly and is calculated based on various short-term rates selected by Chambers for each draw. The letter of credit currently expires June 9, 2004. Upon request of Chambers, the expiration date of the letter of credit may be extended at the sole discretion of the Chambers Banks. In order to fund general debt service, the Banks have provided Scrubgrass with a debt service loan commitment. The commitment of $6,303,000 under the Original RLA has been reduced to $6,000,000 under the New RLA. On May 22, 1997, Scrubgrass entered into an agreement to amend the New RLA which restructured the debt service loan commitment of $6,000,000. Credit Lyonnais assumed from NatWest a debt service (Series A/B) loan commitment of $3,000,000. At December 31, 1997 Scrubgrass and Buzzard had drawn $3,000,000 on this commitment. This amount has been included as a debt service loan receivable in the accompanying combined balance sheets. The debt service (Series A) principal of this loan commitment must be reduced in increments of $600,000 every six months beginning on or before July 1, 1998 and ending on or before July 3, 2000. Principal reductions of the Credit Lyonnais debt service (Series A) loan will result in an increase in the outstanding commitment value of the Credit Lyonnais debt service (Series B) loan until it becomes a $3,000,000 commitment on or before July 3, 2000. The $3,000,000 debt service (Series B) loan commitment balance remained with NatWest. Type and term for each loan under the facility is determined at Scrubgrass's option. The interest is determined as set forth in the New RLA and is either the Eurodollar rate plus the applicable 19 20 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) margin, or a base rate, which is the higher of the Agent's prime rate or the federal funds rate, plus the applicable margin. WORKING CAPITAL LOANS A working capital loan commitment provides up to $9,500,000 for the seasonal working capital requirements of the Logan Project. The Logan Partnerships are required to pay down the loan to zero for a minimum of one week per year. Interest on any outstanding balance is payable quarterly and is calculated based on various short-term indices at the Logan Partnerships' option and is determined separately for each draw. A working capital loan commitment ("Working Capital Loan") provided for the initial working capital requirements of the Northampton Project. The interest rate is based upon various short-term indices at Northampton's option and is determined separately for each draw. On the Construction Loan Maturity Date, the working capital loan commitment was increased by $3 million and extends for a period of four years from the Construction Loan Maturity Date. No draws were made against the working capital loan commitment during 1997 and 1996. The Chambers' Amended and Restated Credit Agreement provides for a working capital loan commitment from the Chambers Banks of up to $5,000,000 to fund operation and maintenance expense requirements of the Project. Chambers is required to repay and maintain a zero balance for a minimum of one week per year. Interest on any outstanding balance is payable quarterly and is calculated based on various short-term rates selected by Chambers, for each draw. The full amount of the principal is due at the earlier of June 9, 2004 or on the date on which all loans under the Amended and Restated Credit Agreement are due in full. Pursuant to the New RLA, the working capital loan provides for seasonal working capital requirements of the lessee, occurring after the Conversion Date. The Chambers Banks agreed to make a portion of the working capital facility available to fund net startup costs prior to the Conversion Date; $1,600,000 of proceeds from the new term loan were used to repay these borrowings. Type and term for each working capital loan under the New RLA is determined at Scrubgrass's option. The interest is either the Eurodollar rate plus the applicable margin, or a base rate, which is the higher of the Agent's prime rate or the federal funds rate, plus the applicable margin. Pursuant to the New RLA, the core component was set at $2,000,000. The outstanding loan balance is required to be paid down to the core level for 20 consecutive days each calendar year. A commitment fee of 0.125 percent was applied to the undrawn loan commitment through December 31, 1995. In 1994, Scrubgrass entered into a lessee working capital loan agreement with Buzzard whereby Scrubgrass is to provide Buzzard with funds for seasonal working capital requirements with regard to the Scrubgrass Project. The terms and conditions set forth in this agreement are consistent with those above for Scrubgrass's working capital loan facility with the Scrubgrass Banks. The commitment extends to any undrawn amounts on Scrubgrass's working capital loan as described above. Pursuant to the New RLA, the lessee working capital loan agreement was amended to maintain consistency with the terms of Scrubgrass's working capital loan facility. At December 31, 1997 and 1996, Buzzard had drawn $2,311,666 and $2,696,143, respectively, on this commitment. These amounts have been included as a note receivable in the accompanying combined balance sheets. 20 21 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) JUNIOR LOAN AGREEMENT On November 1, 1993, in order to finance a portion of the costs of constructing and equipping the Logan Project, the Logan Partnerships renegotiated a junior loan agreement (the "Junior Loan Agreement") with Foster Wheeler Energy Corporation (the "Junior Lender") in the amount of $4,800,000. No cash was advanced to the Logan Partnerships by the Junior Lender. The advances were made by deferring the final $4,800,000 payment due to the Junior Lender from BPC under the construction subcontract between the Junior Lender and BPC. In addition, accrued interest of $143,205 was added to the principal outstanding at the Conversion Date. Interest is due quarterly at the rate equal to the Treasury rate, as defined, plus 4.95 percent. Principal payments are due quarterly between March 31, 1996 and December 31, 2009, according to an amortization schedule provided in the Junior Loan Agreement. TRANSMISSION LINE INTERCONNECTION LETTER OF CREDIT At Funded Closing, which occurred on February 1, 1994, Northampton provided an irrevocable letter of credit in the amount of $100,000 pursuant to the Transmission Service Agreement. This letter of credit secures Northampton's obligation to reimburse the utility owning the transmission line for any improvements, changes or repairs to its regional transmission system that are necessitated by the interconnection of the Project to the system. The transmission line interconnection letter of credit will be maintained throughout the term of the Transmission Service Agreement, which extends until 25 years from the Commercial Operation Date. CONTRACT LETTER OF CREDIT In order to support obligations of Scrubgrass pursuant to the power sales agreement with Pennsylvania Electric Company ("Penelec"), the Scrubgrass Banks have provided Scrubgrass with a contract letter of credit commitment. At December 31, 1997 and 1996, the contract letter of credit had a stated value of $7,410,000 and $10,700,000, respectively. The letter of credit was issued to Penelec during 1993, and it will be drawn only if liquidated damages are due to Penelec. Repayment of any draw is due immediately, at a default rate that approximates the prime rate of interest plus 2.00 percent. Effective January 1, 1997, Amendment Number One to the New RLA assigned all of Credit Lyonnais's rights and obligations as contract letter of credit issuer to Landesbank Hessen-Thuringen Girozentrale Bank ("Helaba"). The stated amount of the contract letter of credit was reduced to $4,100,000 by Helaba on January 1, 1998, as required by Penelec under the power sales agreement. 21 22 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) VENDOR LOANS Vendor loans at December 31, 1997 and 1996, which were entered into at lease commencement and subsequently restructured in December 1995, are as follows: 1997 1996 -------- ---------- To USGen, $900,000 with interest payable at eight percent, payable in forty-eight equal monthly installments of principal and interest, commencing January 1996........... $504,413 $ 718,337 To USGen, $429,000 with interest payable at eight percent, payable in two annual installments of principal and interest, commencing January 1997......................... 157,610 429,000 To EPC, $452,000 with interest payable at eight percent, principal and interest payable on demand, commencing January 1996.............................................. 85,190 121,319 -------- ---------- Total............................................. $747,213 $1,268,656 ======== ========== Payment of principal and interest on these loans is subordinated to the VIDA bonds and the loans under the New RLA. NOTE AND MORTGAGE PAYABLE On December 22, 1993, in order to finance the purchase of several waste fuel sites, the Fuel Company entered into a $6 million Promissory Note and Purchase Money Mortgage with unrelated third parties. FUTURE MINIMUM PAYMENTS Future minimum principal payments at December 31, 1997, required by the debt instruments outstanding are as follows (in thousands): 1998..................................................... $ 35,262 1999..................................................... 39,187 2000..................................................... 45,731 2001..................................................... 50,511 2002..................................................... 53,511 Thereafter............................................... 1,020,862 ---------- Total.......................................... $1,245,064 ========== INTEREST RATE SWAP AGREEMENTS The Partnerships have entered into a total of sixteen interest rate swap agreements, with an aggregate notional balance of $349,574,000, to manage interest costs and the risk associated with changing interest rates. The agreements have effectively converted the variable rate tax-exempt bond debt into fixed rate debt, as they require the Partnerships to pay fixed rates under the agreements and receive variable rate-based payments in return. Total swap interest cost was $10,329,241, $10,924,438 and $8,867,209 in 1997, 1996 and 1995, respectively. Refer to Note 8 for fair value information related to the swap agreements. 22 23 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) Counterparties to the interest rate swap agreements are major financial institutions. While the Partnerships may be exposed to credit losses in the event of nonperformance by these counterparties, they do not anticipate losses. 4. LEASE AND SUBLEASE AGREEMENTS GENERAL Certain of the Partnerships have long-term lease agreements with third parties for the use of land and equipment and for certain other services. These leases have initial terms expiring between October 1999 and July 2020. Future minimum lease payments under these lease agreements are as follows (in thousands): 1998........................................................ $ 1,208 1999........................................................ 1,218 2000........................................................ 1,079 2001........................................................ 836 2002........................................................ 639 Thereafter.................................................. 13,903 ------- Total............................................. $18,883 ======= PROJECT LEASE Buzzard agreed to lease the Scrubgrass Project facility and sublease the project site from Scrubgrass (the "Lease") for a term of 22 years with a renewal option for an additional three years. The residual value of the property at the end of the lease term is $0. Estimated minimum lease payments over the term (including the renewal period) of the Lease as of December 31, 1997 are as follows (dollars in thousands): 1998........................................................ $ 16,602 1999........................................................ 16,857 2000........................................................ 17,581 2001........................................................ 17,317 2002........................................................ 18,673 Thereafter.................................................. 414,489 -------- Total............................................. $501,519 ======== The implicit rate in the Lease is 8.34 percent. The components of the net investment in lease at December 31, 1997 are as follows: Gross investment in lease................................... $501,519 Unearned income............................................. (272,583) -------- Net investment in lease................................... $228,936 ======== 23 24 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 5. SUPPLY AGREEMENTS COAL SUPPLY Certain of the Partnerships have long-term coal supply agreements with third parties to supply the coal requirements of the respective electric generating facilities. These contracts have initial terms of 20 years and do not require the Partnerships to purchase any minimum quantities. Prices under the agreements are either nominated on a periodic basis based on expected dispatch or increase periodically based on price index formulas as defined in the respective agreements. LIME SUPPLY Certain of the Partnerships have long-term lime purchase agreements with third parties to supply the lime requirements of the respective electric generating facilities. These agreements have contract periods ranging from 10 to 25 years. One of the agreements requires the purchase of a minimum of 1,500 tons of limestone per year, at an initial delivered cost of $76 per ton. Prices under the agreements generally increase based on price index formulas as defined in the respective agreements. OTHER Certain of the Partnerships have long-term agreements for ash management services with third parties. These contracts have terms ranging from 15 to 20 years and prices under the agreements generally increase annually based on price index formulas as defined in the respective agreements. 6. SALES AGREEMENTS POWER PURCHASE AGREEMENTS Each of the Partnerships has a long-term power purchase agreement with a public utility for sales of the respective electric generating facilities' power output. These agreements have contract terms ranging from 25 to 30 years and generally provide for both capacity and energy payments. Prices paid by the utilities generally escalate annually based on formulas contained in the respective agreements. One of the Partnerships has entered into a cost-based dispatch agreement with its purchasing utility with a guaranteed minimum dispatch level. Another of the Partnerships has entered into an excess capacity and energy sales agreement with its purchasing utility under which the pricing of capacity and energy is negotiated at market prices. STEAM AND ELECTRICITY SALES AGREEMENTS Certain of the Partnerships have steam and electric sales agreements with third parties which have contract terms ranging from 15 to 30 years. Prices under the agreements are generally adjusted periodically based on formulas contained in the respective agreements. OTHER One of the Partnerships has a 25-year contract with a public utility to provide for the transmission of that facility's electrical output to the ultimate purchasing utility under the power purchase agreement. 24 25 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 7. RELATED-PARTY TRANSACTIONS CONSTRUCTION CONTRACT Urban and Northampton entered into separate turnkey construction contracts with Bechtel Power Corporation ("BPC"), an affiliate of BGCI, for the design, engineering, procurement, construction, start-up and testing of their respective projects. The Urban contract provided for certain bonuses and fees in addition to the fixed price for the plant. The contract also provided BPC a 50 percent share in net profits, as defined in the contract, from the sale of any excess energy entered into within 2 years of final acceptance, December 19, 1994, for the lesser of the initial term of the excess power sales agreement or 5 years. This provision applies to the Excess Capacity and Energy Sales Agreements described in Note 6. Logan incurred $13,727, $60,234 and $41,079 of expense in 1997, 1996 and 1995, which is included in other accrued liabilities in the accompanying combined balance sheets, related to this provision of the contract. Construction of the Northampton Project commenced in October 1993. Substantial completion occurred on August 26, 1995 and final completion on December 22, 1995. All construction contract payments including retainage have been made as of December 31, 1996. A warranty claim receivable to BGCI for items totaling $61,120 is outstanding as of December 31, 1997 and is included in accounts receivable in the accompanying combined balance sheets. MANAGEMENT SERVICES AGREEMENT The Partnerships have separate management services agreements with USGen, a wholly owned indirect subsidiary of USGenLLC. The agreement provides for USGen to provide day-to-day management and administration of the Partnerships' business relating to the projects. The agreement will continue for 33 years from commencement for Logan, 25 years from commencement for Northampton, and until either party terminates the agreement for Chambers. Compensation to USGen under the agreements includes an annual base fee totalling approximately $1,200,000, escalated annually, wages and benefits for employees working on behalf of the Partnerships and other costs directly related to the Partnerships. Total payments to USGen were $4,951,578, $5,345,169 and $4,648,625 in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, the Partnerships owed USGen $658,539 and $779,884, respectively, which is included in accounts payable in the accompanying combined balance sheets. OPERATIONS AND MAINTENANCE AGREEMENT The Partnerships have separate operations and maintenance agreements with USOSC, a wholly owned indirect subsidiary of USGenLLC, for operations and maintenance of the Projects during construction and for 10 to 25 years after substantial completion of construction of the Projects. Thereafter, the agreement will be automatically renewed for periods of 5 years for the three of the Projects until terminated by either party with at least 6 to 12 months notice. Compensation to USOSC includes the reimbursement of direct and indirect operational expenses, a base fee totaling $2,115,900 per year, additional fees based on targeted plant performance, safety bonuses of up to approximately $425,000 per year and an employee incentive bonus. These fees are adjusted annually by a measure of inflation as defined in the agreement. If targeted plant performance is not reached, USOSC will pay liquidated damages to the Partnership. Total payments to USOSC were $24,390,226, $25,514,646 and $19,848,237 in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, the Partnerships owed USOSC $2,777,214 and $2,964,606, respectively, which are 25 26 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) included in other accrued liabilities in the accompanying combined balance sheets. At December 31, 1997, $446,000 had been advanced to USOSC and is included in prepaid expenses. POWER BROKERING/MARKETING AGREEMENT The Partnerships of Logan and Chambers have a power brokering/marketing agreement with PG&E ET. The agreement provides for PG&E ET to provide certain services to the Partnerships related to the sale of capacity and energy as well as other power-related services, including but not limited to spinning reserves, operating reserves and emission allowances from the Partnerships to various electric utilities and other entities. The agreements both commenced on April 7, 1995 and shall expire automatically three years from the commencement date; provided, however, that either party may terminate the agreement upon 60 days' prior written notice to the other party. Compensation to PG&E ET is negotiated on a deal-by-deal basis. Payments of $0, $67,341 and $69,830 were made to PG&E ET in 1997, 1996 and 1995, respectively. Payments of $3,969,879, $2,956,473 and $0 were received from PG&E ET in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, PG&E ET owed the Partnerships $352,769 and $380,718, respectively, which is included in accounts receivable in the accompanying combined balance sheets. LEASE AGREEMENT Chambers has a lease agreement with Carneys Point Generating Company, L.P. ("CPGC"), which is owned 50% by Topaz Power Corporation and 50% by Garnet Power Corporation, both subsidiaries of USGen. CPGC agreed to lease the plant and sublease the site from Chambers. In addition, certain contracts and agreements related to Chambers are assigned to CPGC by Chambers. The lease commenced upon the Chambers Conversion Date pertaining to the Credit Agreement for a period of 24 years. WASTE DISPOSAL AGREEMENT In December 1993, Northampton entered into a Waste Disposal Agreement with the Fuel Company. Under the terms of the agreement, the Partnership will dispose of anthracite coal refuse material which the Fuel Company will make available to Northampton from waste coal sites leased and owned by the Fuel Company. Northampton will supply ash to the Fuel Company for use in the reclamation of the waste coal sites and ash disposal areas. The Fuel Company presently has access to waste coal supplies sufficient to supply approximately 17.8 years of waste coal to Northampton. Northampton is required to reimburse the Fuel Company for all expenses incurred in the excavation, handling and loading of the waste coal and in the unloading and handling of ash. During 1997, 1996 and 1995, this reimbursement amounted to $8,686,684, $9,276,824 and $1,923,560, respectively. FUEL SERVICES AGREEMENT The Fuel Company entered into a Fuel Services Agreement with USOSC effective January 1, 1996. The agreement is effective for five years from the agreement date. At the sole discretion of the Fuel Company, the agreement may be extended for up to two additional 10 year terms. Under the terms of the agreement, USOSC will staff and operate the fuel, ash and silt sites and manage the operation and maintenance of the culm facility. Compensation to USOSC includes the reimbursement of direct and indirect operational expenses. In addition, a base fee of $250,000 is paid annually. If targeted plant performance for each operating year based on fuel recoveries is reached, a recovery earned fee shall be paid by the Fuel Company to USOSC. 26 27 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) Liquidated damages shall be paid by USOSC to the Fuel Company if the targeted fuel recoveries are not met. Similarly, if targeted cost incentives are met, an earned fee shall be paid by the Fuel Company to USOSC. If not met, liquidated damages shall be incurred by USOSC. The cost incentive fee or related liquidated damages were not effective for 1996 and were not incurred in 1997. Payment of the base fee, earned fees, and discretionary fees are subordinated to debt service on the Project. During 1997, 1996 and 1995, $3,032,351, $2,210,991 and $0, respectively, in cost reimbursement and fees was incurred and is included in fuel inventory in the accompanying consolidated balance sheets and fuel expense in the accompanying consolidated statements of operations. At December 31, 1997, $103,400 had been advanced to USOSC and is carried as a prepaid expense on the accompanying combined balance sheets. In December 1993, the Fuel Company entered into a fuel services agreement with an unrelated third party, which was replaced by the agreement described above. During 1995, $2,507,181 in cost reimbursements and fees was capitalized as part of the Fuel Company cost of construction. Cost reimbursement and fees of $1,349,822 incurred during the 4th quarter of 1995 are included in fuel expense in the accompanying combined statement of operations. EXCESS CAPACITY SALES AGREEMENT In June 1996, Northampton entered into an excess capacity sales agreement with PG&E ET. The sales agreement became effective June 1, 1996 and is to extend through May 31, 1998. The agreement states that Northampton will supply to PG&E ET an amount of installed capacity up to 24mw. During 1997, 1996 and 1995, $229,950, $94,050 and $0, respectively, was received from PG&E ET under the provisions of the agreement. INTERCOMPANY LOAN During the period from July through September 1995, Scrubgrass received $375,028 of equity rents from Buzzard. These funds were restricted pending release by the Scrubgrass Banks, which occurred during December 1995. Scrubgrass borrowed $375,028 from USOSC during 1995 to fund scheduled distributions to the Partners. Pursuant to an agreement between USOSC, Scrubgrass and the Agent, restricted cash of this amount was paid directly to USOSC in January 1996. CONSULTING AND OTHER SERVICES In 1996 and 1995, respectively, Chambers incurred and recorded expenses for consulting and other services in the amount of $228 and $6,068 from BGCI and $28,352 and $15,073 from Bechtel Power Corporation, an affiliate of BGCI. No such expenses were incurred in 1997. Northampton entered into a services agreement with BGCI to provide management, administrative, procurement, environmental and financial services to the Partnership. Compensation to BGCI includes reimbursement for personnel and other direct costs as defined in the agreement. Payments for 1997, 1996 and 1995 were $416,993, $408,770 and $61,581, respectively, and are included in general and administrative expenses in the accompanying combined statement of operations. At December 31, 1997 and 1996, the Partnership owed BGCI $33,750 and $91,719 respectively, which is included in other accrued liabilities in the accompanying combined balance sheet. 27 28 LOGAN GENERATING COMPANY, L.P., KEYSTONE URBAN RENEWAL LIMITED PARTNERSHIP, NORTHAMPTON GENERATING COMPANY, L.P. AND SUBSIDIARIES, CHAMBERS COGENERATION LIMITED PARTNERSHIP AND SCRUBGRASS GENERATING COMPANY, L.P. AND SUBSIDIARIES NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 8. DISCLOSURES ABOUT FAIR VALUES OF FINANCIAL INSTRUMENTS The carrying amounts of the Partnerships' cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses, accounts payable, interest payable, accrued financing and acquisition costs, working capital loan and other accrued liabilities approximate fair value because of the short maturities of these instruments. The carrying amounts of the Partnerships' bonds payable, term loan payable and junior loan payable are equal to their fair value because of the variable nature of the interest obligations thereon. The fair value of the vendor loans approximates their carrying value because market rates of interest approximate the actual rates on these loans. The fair value on other long-term debt is estimated based on currently quoted market prices for similar types of borrowing arrangements and is also considered to approximate its carrying value. The fair value of interest rate swap agreements, which are not carried on the accompanying combined balance sheets, is estimated by determining the difference between the fixed payments on the agreements and what the fixed payments would be based on current market fixed rates for the appropriate maturity, then calculating the present value of that difference for the remaining terms of the agreements at current fixed market rates. The estimated fair value of the interest rate swap agreements is a liability of approximately $18.1 million and $27.4 million, respectively, at December 31, 1997 and 1996. 28 29 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors Bechtel Enterprises, Inc. San Francisco, California We have audited the accompanying combined balance sheets of Birch Power Corporation, Cedar Power Corporation, Hickory Power Corporation, Palm Power Corporation, and Panther Creek Leasing, Inc. (collectively, the "Entities") as of December 31, 1997 and 1996 and the related combined statements of operations, stockholder's equity, and cash flows for the years ended December 31, 1997, 1996, and 1995. These financial statements are the responsibility of the Entities' management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Gilberton Power Company; Cedar Bay Generating Company, L.P.; Morgantown Energy Associates (a partnership); or Indiantown Cogeneration, L.P. (collectively, the "Investees"). The Entities' combined investment in the Investees was $23,583,000 and $29,895,000 at December 31, 1997 and 1996, respectively. The Entities' combined equity income (loss) in the Investees was $801,000, $394,000 and $(2,216,000) for the years ended December 31, 1997, 1996, and 1995, respectively. The financial statements of the Investees were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for the Investees, is based solely on the reports of the other auditors. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Birch Power Corporation, Cedar Power Corporation, Hickory Power Corporation, Palm Power Corporation, and Panther Creek Leasing, Inc. as of December 31, 1997 and 1996, and the combined results of their operations and their combined cash flows for the years ended December 31, 1997, 1996, and 1995 in conformity with generally accepted accounting principles. /s/ PRICEWATERHOUSECOOPERS LLP San Francisco, California June 8, 1998 29 30 REPORT OF INDEPENDENT AUDITORS Board of Control Gilberton Power Company We have audited the balance sheets of Gilberton Power Company as of December 31, 1997 and 1996, and the related statements of income, partners' capital, and cash flows for each of the three years in the period ended December 31, 1997 (not presented separately herein). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Gilberton Power Company at December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ERNST & YOUNG LLP Harrisburg, Pennsylvania January 16, 1998 30 31 INDEPENDENT AUDITORS' REPORT To the Partners of Morgantown Energy Associates: We have audited the balance sheets of Morgantown Energy Associates (a "Partnership") as of December 31, 1997 and 1996, and the related statements of operations, partners' capital and cash flows for each of the three years in the period ended December 31, 1997 (not presented separately herein). These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Morgantown Energy Associates at December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Richmond, Virginia February 25, 1998 31 32 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. COMBINED BALANCE SHEETS AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996 (IN THOUSANDS OF DOLLARS) JUNE 30, DECEMBER 31, DECEMBER 31, 1998 1997 1996 ------------ ------------ ------------ (UNAUDITED) ASSETS Current assets: Cash............................................ $ 2,174 $ 23,268 $ 6,593 Accounts and notes receivable from investees.... 18,283 17,088 17,732 -------- -------- -------- Total current assets.................... 20,457 40,356 24,325 Equity in investees............................... 21,718 23,583 29,895 Investment in leveraged lease..................... 18,541 18,831 31,036 -------- -------- -------- Total assets............................ $ 60,716 $ 82,770 $ 85,256 ======== ======== ======== LIABILITIES Current liabilities: Accounts payable................................ $ 286 $ 242 $ 106 Accrued expenses................................ 670 588 633 Income taxes payable............................ 3,784 4,009 399 -------- -------- -------- Total current liabilities............... 4,740 4,839 1,138 Unearned and deferred income...................... 6,586 7,120 13,575 Deferred income taxes............................. 20,863 19,462 20,088 Minority interest................................. 14,892 15,010 17,217 -------- -------- -------- Total liabilities....................... 47,081 46,431 52,018 -------- -------- -------- Commitments and contingencies (Note 7) STOCKHOLDER'S EQUITY Common stock...................................... 50 50 50 Additional paid-in capital........................ 24,815 48,379 48,379 Accumulated deficit............................... (11,230) (12,090) (15,191) -------- -------- -------- Total stockholder's equity.............. 13,635 36,339 33,238 -------- -------- -------- Total liabilities and stockholder's equity........................... $ 60,716 $ 82,770 $ 85,256 ======== ======== ======== The accompanying notes are an integral part of these combined financial statements. 32 33 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. COMBINED STATEMENTS OF OPERATIONS FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 (IN THOUSANDS OF DOLLARS) YEAR ENDED DECEMBER 31, SIX-MONTH PERIOD ----------------------------- ENDED JUNE 30, 1998 1997 1996 1995 ------------------- ------- ------- ------- (UNAUDITED) Operating income: Income (loss) from investees................. $ 1,077 $ 801 $ 394 $(2,216) Income from leveraged lease.................. 534 1,885 2,018 2,201 Service revenue from investees............... 472 1,081 954 407 ------- ------- ------- ------- 2,083 3,767 3,366 392 ------- ------- ------- ------- Operating expenses: General and administrative expenses.......... 165 373 323 337 Service costs................................ 307 755 604 269 ------- ------- ------- ------- 472 1,128 927 606 ------- ------- ------- ------- Net operating income (loss).......... 1,611 2,639 2,439 (214) Other income (expense): Gain on partial sale of equity in investees................................. -- 2,721 -- -- Loss on partial sale of investment in leveraged lease........................... -- (1,919) -- -- Interest from investees, net................. 1,590 3,397 2,616 3,664 Other income (expenses)...................... 8 (81) (62) (213) ------- ------- ------- ------- Income before minority interest................ 3,209 6,757 4,993 3,237 Minority share in loss......................... 57 238 218 329 ------- ------- ------- ------- Income before income taxes..................... 3,266 6,995 5,211 3,566 Provision for income taxes..................... (2,406) (3,894) (1,338) (4,021) ------- ------- ------- ------- Net income (loss).................... $ 860 $ 3,101 $ 3,873 $ (455) ======= ======= ======= ======= The accompanying notes are an integral part of these combined financial statements. 33 34 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. COMBINED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 (IN THOUSANDS OF DOLLARS) ADDITIONAL TOTAL COMMON PAID-IN ACCUMULATED STOCKHOLDER'S STOCK CAPITAL DEFICIT EQUITY ------ ---------- ----------- ------------- Balance, January 1, 1995...................... $50 $48,379 $ (9,865) $38,564 Net loss...................................... -- -- (455) (455) --- ------- -------- ------- Balance, December 31, 1995.................... 50 48,379 (10,320) 38,109 Net income.................................... -- -- 3,873 3,873 Common stock dividends........................ -- -- (8,744) (8,744) --- ------- -------- ------- Balance, December 31, 1996.................... 50 48,379 (15,191) 33,238 Net income.................................... -- -- 3,101 3,101 --- ------- -------- ------- Balance, December 31, 1997.................... $50 $48,379 $(12,090) $36,339 Net income (Unaudited)........................ -- -- 860 860 Reduction of additional paid-in capital (Unaudited)................................. -- (23,564) -- (23,564) --- ------- -------- ------- Balance, June 30, 1998........................ $50 $24,815 $(11,230) $13,635 === ======= ======== ======= The accompanying notes are an integral part of these combined financial statements. 34 35 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996, AND 1995 (IN THOUSANDS OF DOLLARS) SIX-MONTH PERIOD ENDED YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------- 1998 1997 1996 1995 ----------- ------- ------- -------- (UNAUDITED) Cash flows from operating activities: Net income (loss).................................... $ 860 $ 3,101 $ 3,873 $ (455) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Minority share of losses.......................... (57) (238) (218) (329) Deferred income taxes............................. 1,401 (626) 300 4,587 Equity in net income (loss) of investees.......... (1,077) (801) (394) 2,216 Income from leveraged lease....................... (534) (1,885) (2,018) (2,201) Leveraged lease payment received.................. 290 115 133 1,219 Gain on partial sale of equity in investees....... -- (2,721) -- -- Loss on partial sale of investment in leveraged lease........................................... -- 1,919 -- -- Dividends received from investees................. 2,942 4,831 5,972 3,834 Decrease (increase) in accounts and notes receivable from investees....................... (1,195) 644 (2,239) (2,206) Increase in accounts payable...................... 44 136 93 12 Increase (decrease) in accrued liabilities........ 82 (45) 200 225 Increase (decrease) in income taxes payable....... (225) 3,610 455 (1,168) -------- ------- ------- -------- Net cash flows provided by operating activities................................. 2,531 8,040 6,157 5,734 -------- ------- ------- -------- Cash flows from investing activities: Additional investment in investees................... -- (23) (24) (16,811) Proceeds from partial sale of equity in investees.... -- 5,027 -- -- Proceeds from partial sale of investment in leveraged lease............................................. -- 5,600 -- -- Proceeds from sale of equipment...................... -- -- -- 2,022 -------- ------- ------- -------- Net cash flows provided by (used in) investing activities....................... -- 10,604 (24) (14,789) -------- ------- ------- -------- Cash flows from financing activities: Common stock dividends paid.......................... -- -- (8,744) -- Reduction of additional paid-in capital.............. (23,564) -- -- -- Partial redemption of minority interest.............. (61) (1,969) -- -- -------- ------- ------- -------- Net cash flows used in financing activities................................. (23,625) (1,969) (8,744) -- -------- ------- ------- -------- Net increase (decrease) in cash.............. (21,094) 16,675 (2,611) (9,055) Cash at beginning of period............................ 23,268 6,593 9,204 18,259 -------- ------- ------- -------- Cash at end of period.................................. $ 2,174 $23,268 $ 6,593 $ 9,204 ======== ======= ======= ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid during the period for taxes.................. $ 1,229 $ 910 $ 583 $ 602 ======== ======= ======= ======== The accompanying notes are an integral part of these combined financial statements. 35 36 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. NOTES TO COMBINED FINANCIAL STATEMENTS (IN THOUSANDS OF DOLLARS) 1. NATURE OF BUSINESS The accompanying combined financial statements of Birch Power Corporation, Cedar Power Corporation, Hickory Power Corporation, Palm Power Corporation, and Panther Creek Leasing, Inc. (collectively, the Entities) represent a combination of these five Entities which are each wholly-owned subsidiaries of Bechtel Enterprises, Inc. (Parent). Four of these entities hold interests in power plants through equity investments in investees and one holds an interest in a leveraged lease of a power plant through a partnership investment. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION Information presented as of June 30, 1998 and for the six-month period then ended is unaudited. In the opinion of management, however, such information reflects all adjustments, which consist of normal recurring adjustments necessary to present fairly the financial position of the Entities as of June 30, 1998 and the results of operations and cash flows for the six-month period then ended. The results of operations for this interim period is not necessarily indicative of results which may be expected for any other interim period or for the year as a whole. EQUITY IN INVESTEES Equity in investees are investments in investees which own or derive revenues from power projects. The investees are accounted for on the equity basis due to the Entities' ability to exercise significant influence over them. Each Entity's share of income or loss from equity in investees is included in operating revenues in the combined statements of operations. INCOME TAXES The Entities were included in the consolidated federal income tax return of Bechtel Group, Inc. (BGI) in 1996 and 1995 and Bechtel Generating Company, Inc. (BGCI) in 1997. It is the policy of BGI and BGCI to allocate their consolidated current income tax liability to each profitable company in the group on the basis of the ratio of each profitable company's current income tax liability to the total consolidated current income tax liability, except for companies with separate tax-sharing agreements. No current tax benefit is allocated to loss companies of the consolidated group other than companies with separate tax sharing agreements with BGI in 1996 and 1995 and BGCI in 1997. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred taxes are calculated based on provisions of enacted tax law. USE OF ESTIMATES The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts in the financial statements and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates. 36 37 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) NEW ACCOUNTING PRONOUNCEMENTS In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130, Reporting Comprehensive Income. This pronouncement establishes standards for the reporting and display of comprehensive income and its components in financial statements. Comprehensive income is defined as the total of net income and all other nonowner changes in equity. This statement will be adopted for the Entities effective January 1, 1998. The Entities' management believes this pronouncement will not have a material effect on the financial statements. 3. EQUITY IN INVESTEES The following table summarizes each Entity's percentage equity in investees as of December 31, 1997, 1996, and 1995: DECEMBER 31, ------------------ ENTITY AFFILIATE 1997 1996 1995 - ------ --------- ---- ---- ---- Birch Power Corporation Gilberton Power Company 19% 19% 19% Cedar Power Corporation Cedar Bay Generating Company, L.P. 16 16 16 Hickory Power Corporation Morgantown Energy Associates (a partnership) 15 15 15 Palm Power Corporation Indiantown Cogeneration, L.P. 10 12 12 In September 1997, Palm Power Corporation decreased its ownership from 12% to 10% of its equity in Indiantown Cogeneration, L.P. for $5,027 with a gain of $2,721. The following table presents summarized financial information for the above four Investees in which the Entities hold interests: DECEMBER 31, DECEMBER 31, ------------ ------------ 1997 1996 ------------ ------------ Balance sheet data: Current assets............................................ $ 95,341 $ 108,830 Noncurrent assets......................................... 1,401,621 1,441,600 ---------- ---------- Total assets...................................... $1,496,962 $1,550,430 ========== ========== Current liabilities....................................... $ 104,538 $ 99,947 Noncurrent liabilities.................................... 1,209,134 1,242,895 Partners' equity.......................................... 183,290 207,588 ---------- ---------- Total liabilities and partners' equity............ $1,496,962 $1,550,430 ========== ========== YEAR ENDED DECEMBER 31, ------------------------------ 1997 1996 1995 -------- -------- -------- Statement of operations data: Operating revenues................................... $367,311 $362,857 $199,300 Net income (loss).................................... 12,363 7,160 (11,675) The Entities' share of net income (loss)............. 801 394 (2,216) 37 38 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 4. INVESTMENT IN LEVERAGED LEASE Panther Creek Leasing, Inc. (Panther) is the lessor in a leveraged lease agreement entered into in 1993 under which a power plant having an estimated economic life of 20 years was leased for a term of 19.5 years. Panther's equity investment represented 21 percent of the purchase price; the remaining 79 percent was furnished by third-party financing in the form of long-term debt that provides for no recourse against Panther and is collateralized by a first lien on the property. At the end of the lease term, the power plant will be turned back to Panther. The residual value at that time is estimated to be 20 percent of the cost. Panther's net investment in the leveraged lease is composed of the following elements at December 31, 1997 and 1996: DECEMBER 31, DECEMBER 31, ------------ ------------ 1997 1996 ------------ ------------ Rentals receivable (net of principal and interest on the nonrecourse debt)......................................... $13,441 $ 22,186 Estimated residual value of leased assets................... 5,390 8,850 Less: Unearned and deferred income.......................... (7,120) (13,575) ------- -------- Investment in leveraged lease............................... 11,711 17,461 Less: Deferred taxes........................................ (4,917) (8,580) ------- -------- Net investment in leveraged lease........................... $ 6,794 $ 8,881 ======= ======== In December 1997, Panther sold 39.1% of its investment in the leveraged lease for $5,600 at a loss of $1,919. 5. COMMON STOCK The Common stock of the Entities at December 31, 1997 and 1996 was as follows: NUMBER OF SHARES ------------------------ PAR VALUE ISSUED AND PER SHARE AUTHORIZED OUTSTANDING --------- ---------- ----------- Birch Power Corporation................................ $1.00 100,000 10,000 Cedar Power Corporation................................ $1.00 10,000 10,000 Hickory Power Corporation.............................. $1.00 10,000 10,000 Palm Power Corporation................................. $1.00 10,000 10,000 Panther Creek Leasing, Inc............................. $1.00 10,000 10,000 38 39 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 6. INCOME TAXES The provision for income taxes for the years ended December 31, 1997, 1996, and 1995 consists of the following: DECEMBER 31, ------------------------ 1997 1996 1995 ------ ------ ------ Current: Federal................................................... $4,239 $ 815 $ (893) State..................................................... 281 223 327 ------ ------ ------ 4,520 1,038 (566) ------ ------ ------ Deferred: Federal................................................... (626) 300 4,587 ------ ------ ------ $3,894 $1,338 $4,021 ====== ====== ====== Reconciliations between the federal statutory income tax rate and the Entities' combined effective tax rates are as follows: YEAR ENDED DECEMBER 31, ---------------------------------------------------------- 1997 1996 1995 ---------------- ---------------- ---------------- Tax at federal statutory rate..................... $2,448 35.0% $1,824 35.0% $1,248 35.0% State income taxes, net of federal tax effect....... 186 2.7 118 2.2 194 5.4 Effect of consolidated tax allocation............... 1,311 18.7 (471) (9.0) 2,813 78.9 Other...................... (51) (0.7) (133) (2.5) (234) (6.5) ------ ----- ------ ----- ------ ----- Effective tax rate......... $3,894 55.7% $1,338 25.7% $4,021 112.8% ====== ===== ====== ===== ====== ===== Significant components of the Entities' net deferred tax liability as of December 31, 1997 and 1996 are as follows: DECEMBER 31, DECEMBER 31, ------------ ------------ 1997 1996 ------------ ------------ Deferred tax liability: Tax loss from investees................................... $(19,019) $(15,906) Leveraged lease........................................... (4,917) (8,580) Other..................................................... (29) -- -------- -------- (23,965) (24,486) -------- -------- Deferred tax asset: Net operating losses...................................... 4,503 4,301 Other..................................................... -- 97 -------- -------- 4,503 4,398 -------- -------- Net deferred tax liability.................................. $(19,462) $(20,088) ======== ======== 39 40 BIRCH POWER CORPORATION, CEDAR POWER CORPORATION, HICKORY POWER CORPORATION, PALM POWER CORPORATION, AND PANTHER CREEK LEASING, INC. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 7. COMMITMENTS AND CONTINGENCIES LINE OF CREDIT An associate of the Parent has made available to the Entities a total revolving credit facility of $125,000 at December 31, 1997 against which the Entities had no borrowings. An associated company has guaranteed the credit facility which requires the associated company to maintain a minimum level of stockholder's equity. GUARANTEES AND LETTERS OF CREDIT Letters of credit of $762 were outstanding at December 31, 1997. At December 31, 1997, the Entities have committed to contribute to certain investee Entities capital of $2,012, all of which is contingent upon certain conditions. The aforementioned capital contributions are secured by letters of credit or collateral of the Parent and the associated company. TAX CREDITS The Internal Revenue Service (IRS) has issued a technical advice memorandum disallowing energy tax credits taken by the partners of Gilberton Power Company (GPC). GPC is appealing this decision and believes it will prevail. An unsuccessful appeal could nullify the Birch Limited Partnership (BLP) sharing ratio change which occurred on April 1, 1993. As a result, Birch Power Corporation could take a charge to pre-tax book income and owe cash to its BLP partner, ESI Energy Inc. The maximum potential liability is approximately $1,200 through 1997. This estimate does not include interest or any other charges. 40 41 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Indiantown Cogeneration, L.P. and Cedar Bay Generating Company, L.P.: We have audited the accompanying combined balance sheets of Indiantown Cogeneration, L.P. (a Delaware limited partnership) and Cedar Bay Generating Company, L.P. (a Delaware limited partnership) as of December 31, 1997 and 1996, and the related combined statements of operations, changes in partners' capital and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Partnerships' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Indiantown Cogeneration, L.P. and Cedar Bay Generating Company, L.P. as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. /s/ ARTHUR ANDERSEN LLP Washington, D.C. January 19, 1998 41 42 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. COMBINED BALANCE SHEETS AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996 (DOLLARS IN THOUSANDS) DECEMBER 31, JUNE 30, ----------------------- 1998 1997 1996 ----------- ---------- ---------- (UNAUDITED) ASSETS CURRENT ASSETS: Cash and cash equivalents.............................. $ 2,517 $ 3,342 $ 407 Restricted cash........................................ 7,282 8,584 18,501 Accounts receivable.................................... 27,448 27,276 28,191 Inventories............................................ 2,471 1,675 3,784 Prepaid expenses....................................... 2,198 1,861 1,717 Investments held by Trustee, including restricted funds of $2,747 (unaudited), $2,765 and $3,673, respectively........................................ 2,539 13,009 18,750 ---------- ---------- ---------- Total current assets........................... 44,455 55,747 71,350 INVESTMENTS HELD BY TRUSTEE, restricted funds............ 13,767 13,501 13,001 DEPOSITS................................................. 70 65 60 LAND..................................................... 8,582 8,582 8,579 PROPERTY, PLANT & EQUIPMENT, net of accumulated depreciation of $99,230 (unaudited), $84,614 and $55,084, respectively.................................. 1,100,991 1,114,688 1,141,711 FUEL RESERVE............................................. 2,397 3,141 3,592 DEFERRED FINANCING COSTS, net of accumulated amortization of $51,065 (unaudited), $49,875 and $47,342, respectively........................................... 31,180 32,370 34,903 ---------- ---------- ---------- $1,201,442 $1,228,094 $1,273,196 ========== ========== ========== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES: Current portion of long-term debt...................... $ 18,715 $ 20,052 $ 16,278 Current portion of lease payable....................... 277 267 248 Accounts payable and accrued liabilities............... 23,717 22,255 24,417 Accrued interest....................................... 2,319 2,337 12,180 ---------- ---------- ---------- Total current liabilities...................... 45,028 44,911 53,123 LONG-TERM DEBT: Interest payable....................................... 35,648 29,703 18,088 Bonds and notes payable................................ 992,631 1,001,234 1,021,286 Retainage payable...................................... 20,000 20,000 20,000 Lease payable -- railcars.............................. 4,730 4,871 5,138 ---------- ---------- ---------- Total long-term debt........................... 1,053,009 1,055,808 1,064,512 ---------- ---------- ---------- Total liabilities.............................. 1,098,037 1,100,719 1,117,635 PARTNERS' CAPITAL........................................ 103,405 127,375 155,561 ---------- ---------- ---------- $1,201,442 $1,228,094 $1,273,196 ========== ========== ========== The accompanying notes are an integral part of these combined balance sheets. 42 43 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. COMBINED STATEMENTS OF OPERATIONS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) SIX-MONTH PERIOD ENDED JUNE 30, FISCAL YEAR ENDED DECEMBER 31, ------------------------- ------------------------------ 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- -------- (UNAUDITED) (UNAUDITED) OPERATING REVENUES: Electric capacity and capacity bonus............................. $104,005 $103,476 $206,762 $198,489 $ 83,019 Electric energy revenue.............. 30,755 29,741 68,988 73,068 31,100 Steam revenue........................ 7,823 7,879 15,774 15,355 14,695 -------- -------- -------- -------- -------- 142,583 141,096 291,524 286,912 128,814 -------- -------- -------- -------- -------- OPERATING EXPENSES: Fuel and ash......................... 41,243 41,672 92,485 95,958 51,390 Operating and maintenance............ 17,670 17,068 39,334 32,356 16,484 General and administrative........... 7,867 7,325 13,581 14,483 11,998 Insurance and taxes.................. 3,361 3,418 6,705 7,483 222 Depreciation and amortization........ 15,518 13,223 31,201 34,872 15,433 -------- -------- -------- -------- -------- 85,659 82,706 183,306 185,152 95,527 -------- -------- -------- -------- -------- OPERATING INCOME....................... 56,924 58,390 108,218 101,760 33,287 OTHER INCOME (EXPENSE): Interest expense..................... (55,633) (56,137) (111,867) (112,674) (54,332) Other................................ 1,220 1,797 3,543 5,636 3,390 -------- -------- -------- -------- -------- (54,413) (54,340) (108,324) (107,038) (50,942) -------- -------- -------- -------- -------- NET INCOME (LOSS)...................... $ 2,511 $ 4,050 $ (106) $ (5,278) $(17,655) ======== ======== ======== ======== ======== The accompanying notes are an integral part of these combined statements. 43 44 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. COMBINED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) PARTNERS' CAPITAL, DECEMBER 31, 1994........................ $ 74,889 Capital contributions..................................... 140,000 Net loss.................................................. (17,655) -------- PARTNERS' CAPITAL, DECEMBER 31, 1995........................ 197,234 Capital distributions..................................... (36,395) Net loss.................................................. (5,278) -------- PARTNERS' CAPITAL, DECEMBER 31, 1996........................ 155,561 Capital distributions..................................... (28,080) Net loss.................................................. (106) -------- PARTNERS' CAPITAL, DECEMBER 31, 1997........................ 127,375 Capital distributions..................................... (26,481) Net Income................................................ 2,511 -------- PARTNERS' CAPITAL, JUNE 30, 1998 (UNAUDITED)................ $103,405 ======== The accompanying notes are an integral part of these combined statements. 44 45 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 SIX-MONTH PERIOD ENDED JUNE 30, FISCAL YEAR ENDED DECEMBER 31, ------------------------- ------------------------------- 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- --------- (UNAUDITED) (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net loss.......................................... $ 2,511 $ 4,050 $ (106) $ (5,278) $ (17,655) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation and amortization................. 15,809 14,250 32,063 35,747 15,445 Decrease (increase) in restricted cash........ 1,302 9,057 9,917 (2,553) 5,566 Decrease (increase) in accounts receivable.... (171) 549 915 (7,186) (5,553) Decrease (increase) in fuel inventory and reserves................................... (52) 1,647 2,560 (1,743) 3,440 (Increase) decrease in deposits and other prepaid expenses........................... (343) (539) (149) 1,017 (32) Increase (decrease) in accounts payable, other accrued liabilities, and accrued interest................................... 7,431 (5,965) (389) 695 12,035 -------- -------- -------- -------- --------- Net cash provided by operating activities............................... 26,487 23,049 44,811 20,699 13,246 -------- -------- -------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Decrease in investment held by trustee............ 10,205 3,007 5,241 40,001 33,218 Cash paid for construction in progress............ (434) -- -- -- (167,448) Additions to property, plant and equipment........ (489) (1,580) (2,511) (12,411) (5,144) Sale of property, plant and equipment............. -- -- -- -- 7,882 Decrease in retainage payable..................... -- -- -- -- (11,946) -------- -------- -------- -------- --------- Net cash provided by (used in) investing activities............................... 9,282 1,427 2,730 27,590 (143,438) -------- -------- -------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Increase in deferred financing costs.............. -- -- -- -- (5,287) Proceeds from long-term debt...................... -- -- -- -- 142,045 Repayment of long-term debt....................... (9,982) (8,093) (16,278) (14,200) (145,838) Decrease in lease payable -- railcars............. (131) (122) (248) (231) -- Capital contributions............................. -- -- -- -- 140,000 Capital distributions............................. (26,481) (16,278) (28,080) (36,395) -- -------- -------- -------- -------- --------- Net cash (used in) provided by financing... (36,594) (24,493) (44,606) (50,826) 130,920 -------- -------- -------- -------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.................................. (825) (17) 2,935 (2,537) 728 CASH AND CASH EQUIVALENTS, beginning of period...... 3,342 407 407 2,944 2,216 -------- -------- -------- -------- --------- CASH AND CASH EQUIVALENTS, end of period............ $ 2,517 $ 390 $ 3,342 $ 407 $ 2,944 ======== ======== ======== ======== ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid for interest.......................... $107,338 $ 99,184 $ 105,723 ======== ======== ========= The accompanying notes are an integral part of these combined statements. 45 46 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS 1. ORGANIZATION AND BUSINESS INDIANTOWN COGENERATION, L.P. Indiantown Cogeneration, L.P. ("Indiantown") is a special purpose Delaware limited partnership formed on October 4, 1991. The general partners are Toyan Enterprises ("Toyan"), a California corporation and a wholly-owned special purpose indirect subsidiary of U.S. Generating Company LLC ("USGenLLC"), and Palm Power Corporation ("Palm"), a Delaware corporation and a special purpose indirect subsidiary of Bechtel Enterprises, Inc. ("BEn"). The sole limited partner is TIFD III-Y, Inc. ("TIFD"), a special purpose indirect subsidiary of General Electric Capital Corporation ("GECC"). During 1994, Indiantown formed its sole, wholly owned subsidiary, Indiantown Cogeneration Funding Corporation ("ICL Funding"), to act as agent for, and co-issuer with, Indiantown in accordance with the 1994 bond offering discussed in Note 5. ICL Funding has no separate operations and has only $100 in assets and capitalization. Indiantown was formed to develop, construct, and operate a 330 megawatt (net) pulverized coal-fired cogeneration facility (the "Facility") located on approximately 240 acres in southwestern Martin County, Florida. The Facility was designed to produce electricity for sale to Florida Power & Light Company ("FP&L") in accordance with the Power Purchase Agreement discussed in Note 7. The Facility also supplies steam to Caulkins Indiantown Citrus Co. ("Caulkins") for its plant located near the Facility in accordance with the Energy Services Agreement discussed in Note 7. Indiantown was in the development stage through December 21, 1995 and commenced commercial operations on December 22, 1995 (the "Commercial Operation Date"). Indiantown's continued existence is dependent on its ability to sustain successful operations. Management of Indiantown is of the opinion that its assets are realizable at their current carrying value. Indiantown is managed by U.S. Generating Company ("USGen") pursuant to a Management Services Agreement (the "MSA"). The Facility is operated by U.S. Operating Services Company ("USOSC") pursuant to an Operation and Maintenance Agreement (the "O&M Agreement"). USGen and USOSC are general partnerships originally formed between affiliates of PG&E Enterprises and Bechtel Enterprises. On September 19, 1997, USGen and USOSC each separately redeemed Bechtel Enterprises' interests in USGen and USOSC so that PG&E Enterprises through USGenLLC now indirectly owns all of the interests in USGen and USOSC. This will not affect USGen's obligations under the MSA or USOSC's obligations under the O&M Agreement. In addition, on September 19, 1997, Toyan purchased 16.67% of Palm's interest in Indiantown, which represents a 2% ownership interest in the partnership. The net profits and losses of Indiantown are allocated to Toyan, Palm and TIFD (collectively, the "Indiantown Partners") based on the following ownership percentages: FROM SEPTEMBER 20, 1997 UNTIL SEPTEMBER 20, 1997 ----------------------- ------------------------ Toyan............................... 50% 48% Palm................................ 10% 12% TIFD................................ 40% 40% All distributions other than liquidating distributions will be made based on the Indiantown 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 Indiantown determines. The Indiantown Partners contributed, pursuant to an equity commitment agreement, approximately $140,000,000 of equity when commercial operation commenced in December 1995. 46 47 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) CEDAR BAY GENERATING COMPANY, L.P. Cedar Bay Generating Company, L.P. ("Cedar Bay") is a Delaware limited partnership formed on April 2, 1993. The general partners of Cedar Bay are Cedar Bay Cogeneration, Inc. ("CBCI"), a California corporation and special purpose indirect subsidiary of PG&E Enterprises ("PG&EE"), and Cedar II Power Corporation ("Cedar II"), a Delaware corporation and special purpose indirect subsidiary of BEn. CBCI is also the limited partner of Cedar Bay. Cedar Bay was formed to construct, own and operate a 250 megawatt power plant (the "Project") located in Jacksonville, Florida. The Project produces electricity for sale to FP&L. The Project sells a minimum of 3,328 million pounds per year of process steam to Stone Container Corporation ("Stone"), formerly Seminole Kraft, an unrelated third party, for use in its industrial operations. Cedar Bay has incurred significant net losses during the three years ended December 31, 1997. The Project is experiencing positive operating cash flow from operations but the level of the operating cash flow is not sufficient to pay full debt service. When Cedar Bay was formed, it was anticipated that there would be recurring net losses (declining over time) until 2005. The reduction of future net losses is the result of gradually increasing rates under the Power Purchase Agreement discussed in Note 7 with FP&L and the related reduction of interest expense due to the pay-down of the bonds and notes payable. The amount of the current net losses has also been impacted negatively by the underpayment of capacity payments by FP&L. Management believes that capacity payments are significantly understated as a result of FP&L's breach of the PPA. Cedar Bay has filed suit against FP&L to recover these additional payments and for declaratory (future) relief. However, until Cedar Bay obtains substantial discovery from FP&L concerning the dispatch of its system, it is not possible to precisely compute the damages claimed (see Note 8). No revenue has been recorded for disputed capacity payments. Cedar Bay's current projections show that, due to the increasing energy rates and the decrease in debt service, positive net earnings will occur in 2003. Cedar Bay's ability to meet its financial obligations is dependent on its ability to sustain successful operations and the successful resolution of its litigation with FP&L. The net operating profits and losses of Cedar Bay are allocated to CBCI and Cedar II (collectively, the "Cedar Bay Partners") based on the following ownership percentages: CBCI........................................................ 80% Cedar II.................................................... 20% All distributions other than liquidating distributions will be made based on the Cedar Bay 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 Cedar Bay determines. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRESENTATION The accompanying financial statements of Indiantown and Cedar Bay, (collectively the "Partnerships"), are presented on a combined basis due to the common management of the operating facilities of the Partnerships. The accompanying combined financial statements were prepared on the accrual basis of accounting in accordance with generally accepted accounting principles. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 47 48 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) INTERIM FINANCIAL STATEMENTS The combined financial statements as of June 30, 1998 and for the periods ended June 30, 1998 and 1997 are unaudited and are presented pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying combined financial statements reflect all adjustments (which are of normal recurring nature) necessary to present fairly the financial position and results of operations and cash flows for the interim periods, but are not necessarily indicative of the results of operations for a full fiscal year. CASH AND CASH EQUIVALENTS For the purpose of reporting cash flows, cash equivalents include short-term investments with original maturities of three months or less. RESTRICTED CASH Restricted cash, which consists of cash and cash equivalent amounts as defined above, includes amounts restricted for use in operations and for capital expenditures. FUEL INVENTORY Coal and lime inventories are stated at the lower of cost or market using the average cost method. PREPAID EXPENSES Prepaid expenses of approximately $1,500,000 as of December 31, 1997, include $968,000 for operation and maintenance funding, $427,000 for insurance costs related to property damage and other general liability policies and $97,000 for prepayments of the annual administrative fees for the letters of credit and for the trustee. Prepaid expenses of approximately $1,356,000 as of December 31, 1996, include $363,000 for operation and maintenance funding, $871,000 for insurance costs related to property damage and other liability policies and $121,000 for prepayments of the annual administrative fees for the letters of credit and for the trustee. DEPOSITS Deposits are stated at cost plus accrued interest and include amounts required under certain of Indiantown's agreements, as described in Note 4, and approximately $168,000 for Cedar Bay utility deposits, as of December 31, 1997 and 1996. INVESTMENTS HELD BY TRUSTEE Investments held by the trustee represent bond and equity proceeds held by a bond trustee/disbursement agent and are carried at cost which approximates market. All funds are invested in either Nations Treasury Fund-Class A or other permitted investments for longer periods. The proceeds include $12,501,000 of restricted tax-exempt debt service reserve to be held long term, as required by the financing documents. Indiantown maintains restricted investments covering a portion of debt principal and interest payable, as required by the financing documents. These investments are classified as current assets in the accompanying combined balance sheets. A qualifying facility ("QF") reserve of $1 million is also held long term (see Note 5). 48 49 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at cost and is being depreciated over its useful life, estimated to be 35 years, using the straight-line method. As of January 1, 1997, Indiantown prospectively revised its calculation of depreciation to include a residual value on its Facility approximating 25 percent of the gross Facility costs. This charge increased net income for 1997 by approximately $4.5 million. Other property, plant and equipment are depreciated on a straight-line basis over the estimated economic or service lives of the respective assets (ranging from 5 to 7 years). Routine maintenance and repairs are charged to expense as incurred. In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("SFAS No. 121"). SFAS No. 121, which was adopted by the Partnerships as of January 1, 1996, establishes criteria for recognizing and measuring impairment losses when recover of recorded long-lived asset values is uncertain. The adoption of this pronouncement did not have an impact on the Partnerships' combined financial condition or results of operations in 1997 or 1996. FUEL RESERVE The fuel reserve, carried at cost, represents an approximate thirty-day supply of coal held for emergency purposes. DEFERRED FINANCING COSTS Financing costs, consisting primarily of the costs incurred to obtain project financing, are deferred and amortized using the effective interest rate method over the term of the related permanent financing. MAJOR MAINTENANCE RESERVE The major maintenance reserve represents an accrual for anticipated expenditures for scheduled significant maintenance of the projects. The expense is recognized ratably over the maintenance cycle of the related equipment. The major maintenance reserve was $865,000 and $1,455,000 at December 31, 1997 and 1996, respectively and is included in accounts payable and accrued liabilities in the accompanying combined balance sheets. INCOME TAXES Under current law, no Federal or state income taxes are paid directly by the Partnerships. All items of income and expense of the Partnerships are allocable to and reportable by the Partners in their respective income tax returns. Accordingly, no provision is made in the accompanying combined financial statements for Federal or state income taxes. RECLASSIFICATIONS Certain 1995 and 1996 balances have been reclassified to conform to the current year presentation. 3. DETAIL OF PARTNERS' CAPITAL The detail of Partners' capital as reflected in the accompanying combined balance sheets as of December 31, 1997 and 1996 is as follows (dollars in thousands). 49 50 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 1997 1996 -------- -------- INDIANTOWN: Toyan Enterprises................................. $ 53,063 $ 55,775 Palm Power Corporation............................ 10,613 13,943 TIFD III-Y, Inc................................... 42,450 46,479 -------- -------- Total................................... $106,126 $116,197 CEDAR BAY: Cedar Bay Cogeneration, Inc....................... $ 16,999 $ 31,491 Cedar II Power Corporation........................ 4,250 7,873 -------- -------- Total................................... 21,249 39,364 -------- -------- Total Partners' Capital................. $127,375 $155,561 ======== ======== 4. DEPOSITS In 1991, in accordance with a contract between Indiantown and Martin County, Indiantown provided Martin County with a security deposit in the amount of $149,000 to secure installation and maintenance of required landscaping materials. This amount is included in current assets as of December 31, 1997 and 1996. The landscaping has been completed and Indiantown has applied to Martin County for a return of funds in excess of the required deposit as security for the first year maintenance. In 1991, in accordance with the Planned Unit Development Zoning Agreement between Indiantown and Martin County, Indiantown deposited $1,000,000 in trust with the Board of County Commissioners of Martin County (the "PUD Trustee"). Income from this trust will be used solely for projects benefiting the community of Indiantown. On July 23, 2025, the PUD Trustee is required to return the deposit to Indiantown. As of December 31, 1997 and 1996, estimated present values of this deposit of $65,000 and $60,000, respectively, are included in deposits in the accompanying combined balance sheets. The remaining balance is included in deferred financing costs. 5. BONDS AND NOTES PAYABLE FIRST MORTGAGE BONDS Indiantown and ICL Funding jointly issued $505,000,000 of First Mortgage Bonds (the "First Mortgage Bonds") in a public issuance registered with the Securities and Exchange Commission. Proceeds from the issuance were used to repay outstanding balances of $273,513,000 on a prior construction loan and to complete the Facility. The First Mortgage Bonds are secured by a lien on and security interest in substantially all of the assets of Indiantown. The First Mortgage Bonds were issued in 10 separate series with interest rates ranging from 7.38 to 9.77 percent and with maturities ranging from 1996 to 2020. Interest is payable semi-annually on June 15 and December 15 of each year and commenced on June 15, 1995. Interest expense related to the First Mortgage Bonds was $46,800,091, $47,456,604 and $47,513,881 in 1997, 1996 and 1995, respectively. TAX EXEMPT FACILITY REVENUE BONDS Indiantown invested the proceeds from the issuance of $113,000,000 of Series 1992A and 1992B Industrial Development Revenue Bonds (the "1992 Bonds") through the Martin County Industrial Development Authority (the "MCIDA") in an investment portfolio with Fidelity Investments Institutional Services Company. On November 22, 1994, Indiantown refunded the 1992 Bonds with proceeds from the issuance of $113,000,000 Series 1994A and of $12,010,000 Series 1994B Tax Exempt Facility Refunding Revenue Bonds 50 51 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) which were issued on December 20, 1994 (the Series 1994A Bonds and the Series 1994B Bonds, collectively, the "1994 Tax Exempt Bonds"). The 1994 Tax Exempt Bonds were issued by the MCIDA pursuant to an Amended and Restated Indenture of Trust between the MCIDA and NationsBank of Florida, N.A. (succeeded by The Bank of New York Trust Company of Florida, N.A.) as trustee (the "Trustee"). Proceeds from the 1994 Tax Exempt Bonds were loaned to Indiantown pursuant to the MCIDA Amended and Restated Authority Loan Agreement dated as of November 1, 1994 (the "Authority Loan"). The Authority Loan is secured by a lien on and a security interest in substantially all of the assets of Indiantown. The 1994 Tax Exempt Bonds, which mature December 15, 2025, carry fixed interest rates of 7.875 percent and 8.05 percent for Series 1994A and 1994B, respectively. Total interest paid related to the 1994 Tax Exempt Bonds was $9,865,555 for each of the years ended December 31, 1997 and 1996 and $10,939,752 for the year ended December 31, 1995. The Tax Exempt Bonds and the First Mortgage Bonds are equal in seniority. SENIOR PROJECT DEBT Cedar Bay's Senior Project Debt consists of borrowings from a syndicate of banks led by Banque Paribas as agent (the "Bank Lenders") and a group of institutions (the "Institutional Lenders") (collectively, the "Senior Lenders"). Senior Project Debt advances funded by the Bank Lenders are accruing interest at the London Interbank Offered Rate ("LIBOR") plus 1.50 percent or a Federal Funds rate plus 0.50 percent. Senior project debt advances funded by the Institutional Lenders are accruing interest at a fixed rate of approximately 12.14 percent. Debt due Bank Lenders will be repaid as scheduled quarterly payments through the year 2009. Debt due Institutional Lenders is scheduled to be repaid in quarterly installments throughout the year 2013. Prepayments are permitted. Collateral for the Senior Project Debt consists of the plant and related facilities and all agreements relating to the operation of the Cedar Bay Project. The Senior Project Debt also requires maintenance of certain negative and affirmative covenants. Cedar Bay pays a commitment fee of 0.5 percent per annum until completion on the undisbursed portion of the Bank Lenders' commitment. In addition, Cedar Bay shall pay to the agent a fee of $100,000 per annum, adjusted for inflation. SUBORDINATED PROJECT DEBT Cedar Bay's Subordinated Project Debt commitments have been assigned to, and assumed by, Gray Hawk Power Corporation ("GHPC"), a special purpose indirect subsidiary of PG&EE, and Cedar I Power Corporation ("Cedar I"), a special purpose indirect subsidiary of BEn, and the terms of such commitments have been modified. The principal amount of this debt commenced bearing interest on January 1, 1994, and bears interest at an annual rate of 15.6 percent thereafter until the principal amount of such loans is paid in full. The unpaid subordinated interest accrues interest at the prime commercial lending rate announced by The Chase Manhattan Bank plus 3 percentage points. Interest on the Subordinated Project Debt is to be paid at the time cash becomes available to Cedar Bay. Management does not anticipate a positive cash flow sufficient to repay the balance of accrued interest outstanding as of December 31, 1997 within the next twelve months. Accordingly, this amount is classified as a noncurrent liability in the accompanying combined balance sheets. The Subordinated Project Debt is scheduled to be repaid by the year 2019. Future minimum lease payments related to outstanding First Mortgage Bonds, 1994 Tax Exempt Bonds, Senior Project Debt, and Subordinated Project Debt at December 31, 1997 are as follows (in thousands). 51 52 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 1998............................................. $ 20,052 1999............................................. 17,362 2000............................................. 7,928 2001............................................. 13,045 2002............................................. 11,666 Thereafter....................................... 951,233 ---------- Total.................................. $1,021,286 ========== EQUITY LOAN In 1994, with proceeds from the issuance of the First Mortgage Bonds, an equity loan in the amount of $139,000,000 was paid in full and Indiantown and TIFD entered into an Amended and Restated Equity Loan Agreement (the "Equity Loan Agreement") for a maximum loan of $139,000,000 to be drawn at Indiantown's request, incorporating the same terms as the original loan. As of the Commercial Operation Date, the maximum amount of the loan had been drawn and was outstanding. This loan was repaid with an equity contribution on December 26, 1995, as discussed below. Indiantown paid $2,813,357 in interest and $2,561,428 in commitment fees during 1995. No such interest or fees related to this loan were paid in 1997 or 1996. EQUITY CONTRIBUTION AGREEMENT Pursuant to an Equity Contribution Agreement, dated as of November 1, 1994, between TIFD and NationsBank of Florida, N.A. (succeeded by The Bank of New York Trust Company of Florida, N.A.), the Indiantown Partners contributed approximately $140,000,000 of equity on December 26, 1995. Proceeds were used to repay the $139,000,000 outstanding under the Equity Loan Agreement. The remaining $1,000,000 was deposited with the Trustee according to the disbursement agreement among Indiantown, the Trustee and the other lenders and is included in current investments held by trustee in the accompanying combined balance sheet as of December 31, 1997 and 1996. REVOLVING CREDIT AGREEMENT The Revolving Credit Agreement provides for the availability of funds for the working capital requirements of the Indiantown Facility. It has a term of seven years from November 1, 1994, subject to extension at the discretion of the banks party thereto. The interest rate is based upon various short-term indices chosen at Indiantown's option and is determined separately for each draw. This credit facility includes commitment fees, to be paid quarterly, of .375 percent on the unborrowed portion. The face amount of the original working capital letter of credit was increased in November 1994 from $10 million to $15 million. Under the original and new working capital credit facilities, Indiantown paid $57,031, $57,187 and $57,031 in commitment fees in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, no draws for working capital had been made to Indiantown under the Revolving Credit Agreement. TERMINATION FEE LETTER OF CREDIT On or before the Commercial Operation Date, Indiantown was required to provide FP&L with a letter of credit equal to the total termination fee as defined in the Power Purchase Agreement in each year not to exceed $50,000,000. Pursuant to the terms of the Letter of Credit and Reimbursement Agreement, Indiantown obtained a commitment for the issuance of this letter of credit. At the Commercial Operation Date, this letter of credit replaced the completion letter of credit outlined below. The initial amount of $13,000,000 was issued for the first year of operations and increased to $23,000,000 in January of 1997. During 52 53 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) 1997, 1996 and 1995 no draws were made on this letter of credit. Commitment fees of $572,819 and $509,395 were paid on this letter of credit in 1997 and 1996, respectively. Cedar Bay has provided FP&L with a letter of credit in the amount of $10 million. The total letter of credit facility is $20 million. FP&L may draw on this letter of credit in the event a termination fee is due and owed under the terms of the Power Purchase Agreement (see Note 7). FP&L COMPLETION LETTER OF CREDIT At financial closing in October 1992, Indiantown provided to FP&L a letter of credit in the amount of $9,000,000 pursuant to the Power Purchase Agreement. This letter of credit was terminated in 1994 and a new one was issued with essentially the same terms. The Power Purchase Agreement (see Note 7) requires that Indiantown pay FP&L for each day beyond December 1, 1995, that the Facility did not achieve commercial operation. Because the commercial operation date did not occur before December 1, 1995, commencing December 1, 1995 and until December 22, 1995, FP&L was entitled to draw on the letter of credit in the amount of $750,000 per calendar month pro-rated for a partial month. In lieu of drawing on the letter of credit, Indiantown paid FP&L $508,065 in delay damages on December 22, 1995. Upon issuance of the above Termination Fee Letter of Credit, the FP&L Completion Letter of Credit was terminated. Commitment fees of $102,656 were paid on this letter of credit in 1995. FP&L QF LETTER OF CREDIT Within 60 days after the Commercial Operation Date, Indiantown was required to provide a letter of credit for use in the event of a loss of QF status under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). The initial amount was $500,000 increasing by $500,000 per agreement year to a maximum of $5,000,000. Pursuant to the terms of the Letter of Credit and Reimbursement Agreement, Indiantown obtained a commitment for the issuance of this letter of credit. The amount will be used by Indiantown as necessary to maintain or reinstate the Facility's qualifying facility status. Indiantown may, in lieu of a letter of credit, make regular cash deposits to a dedicated account in amounts totaling $500,000 per agreement year to a maximum of $5,000,000. In February 1996, Indiantown established a QF account with the trustee. The balance in this account at December 31, 1997 and 1996, was $1,000,000 and $500,000, respectively, and is included in noncurrent, restricted investments held by trustee in the accompanying combined balance sheets. STEAM HOST LETTER OF CREDIT At financial closing in October 1992, Indiantown provided Caulkins a letter of credit in the amount of $10,000,000 pursuant to the Energy Services Agreement (see Note 7). This letter of credit was terminated in 1994 and a new one was issued with essentially the same terms. In the event of a default under the Energy Services Agreement (see Note 7), Indiantown is required to pay liquidated damages in the amount of $10,000,000. Failure by Indiantown to pay the damages within 30 days allows the steam host to draw on the letter of credit for the amount of damages suffered by Caulkins. As of December 31, 1997, 1996 and 1995, no draws had been made on this letter of credit. Commitment fees of $60,833 were paid relating to this letter of credit in each of 1997, 1996 and 1995. DEBT SERVICE RESERVE LETTER OF CREDIT On November 22, 1994, Indiantown also entered into a debt service reserve letter of credit and reimbursement agreement with Banque Nationale de Paris pursuant to which a debt service reserve letter of credit in the amount of approximately $60 million was issued. Such agreement has a rolling term of five years subject to extension at the discretion of the banks party thereto. Drawings on the debt service reserve letter of credit are available to pay principal and interest on the First Mortgage Bonds, the 1994 Tax-Exempt Bonds 53 54 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) and interest on any loans created by drawings on such debt service reserve letter of credit. Cash and other investments held in the debt service reserve account will be drawn on prior to any drawings on the debt service reserve letter of credit. As of December 31, 1997, 1996 and 1995, no draws had been made on this letter of credit. Commitment fees of $875,496 and $835,435 were paid on this letter of credit in 1997 and 1996, respectively. Cedar Bay has issued a letter of credit in favor of Wilmington Trust Company ("Wilmington Trust"), the trustee, in the amount of $10 million. If, at any time, funds available are insufficient to pay all amounts required to be paid to the Senior Lenders, Wilmington Trust shall make a drawing under the debt service letter of credit. Any payment under the letter of credit converts to a debt service reimbursement obligation which must be repaid prior to any subordinated obligations or distributions. RETAINAGE LETTER OF CREDIT Cedar Bay has provided Multipower Associates ("MPA") with a letter of credit in the amount of $20 million to secure the Partnership's obligation to pay retainage amounts due (see Note 6). INTEREST RATE SWAP AGREEMENT Cedar Bay has entered into an interest rate swap agreement having a total notional principal amount of $156 million. This agreement effectively changes the interest rate on the portion of the debt covered by the notional amounts to a fixed rate of 9.58 percent. At December 31, 1997, the notional amount outstanding under the swap agreement was $130 million. The notional amounts outstanding will vary according to a fixed schedule that is based on scheduled amortization of principal amounts. The swap agreement will terminate on December 31, 2000. Total cash paid under the agreement was $5,113,354, $5,412,154 and $4,451,245 in 1997, 1996 and 1995, respectively. Counterparties to the interest rate swap agreement are major financial institutions. While Cedar Bay may be exposed to credit losses in the event of non-performance by these counterparties, Cedar Bay does not anticipate losses. 6. COMMITMENTS AND CONTINGENCIES ENGINEERING, PROCUREMENT AND CONSTRUCTION CONTRACT The final fixed price of Cedar Bay's engineering, procurement and construction contract with MPA is $319.5 million. The contract provides for $20 million of the retainage to be paid after five years. Cedar Bay's obligation to pay this amount is secured by a letter of credit (see Note 5). However, Cedar Bay intends to borrow an additional $20 million from the Senior Lenders in 1999 in order to pay the retainage amount due under this contract. Such additional advance has been approved by the Senior Lenders as of December 31, 1997. Cedar Bay has entered into an amended and restated contract dated as of March 31, 1993 (the "Contract") with MPA. Cedar Bay had informed MPA that MPA did not complete successfully in January and March 1994 certain performance tests set forth in the Contract. Cedar Bay had also informed MPA that it has failed to provide Cedar Bay a functional ash pelletizer system ("APS"). In 1995, Cedar Bay and MPA reached a settlement which provides a lump sum payment from MPA of $15 million to settle all claims, other than a specific list of open warranty items. The settlement amount has been paid through a release of the $11.9 million held in retention as of December 31, 1994, plus a cash payment of $3.1 million. $7.3 million of the settlement amount representing recovery of incremental operating costs was recorded as a reduction in operating and maintenance expense in 1995. The remaining $7.7 million of the settlement amount, representing recovery of incremental costs incurred during construction and start-up testing, was recorded as a 54 55 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) reduction in property, plant and equipment as of December 31, 1995. As part of the settlement, the final performance acceptance was deemed to have been achieved as of March 11, 1994. GROUND LEASE AGREEMENT Commencing April 29, 1991, Stone leased the plant site (approximately 30 acres), along with certain easements, to Cedar Bay for a term of 50 years, unless extended by mutual agreement. For the first 23 years, the rent is $500,000 per year, payable in arrears. After the first 23 years, the rent will be a fair market rate, as defined and as mutually determined by Cedar Bay and Stone. There is also an additional rent provision which is effective if the Steam Services Agreement (see Note 7) is terminated through Cedar Bay's breach. COAL PURCHASE AND TRANSPORTATION AGREEMENT Indiantown entered into a 30-year purchase contract with Lodestar Energy, Inc. ("Lodestar") (formerly known as Costain Coal, Inc.), commencing from the first day of the calendar month following the Commercial Operation Date, for the purchase of the Facility's annual coal requirements at a price defined in the agreement, as well as for the disposal of ash residue. Indiantown has no obligation to purchase a minimum quantity of coal under this agreement. In 1997, Indiantown entered into an arrangement with Lodestar and the coal transporter to compensate Indiantown for reduced FP&L revenues when the Facility runs at minimum load during decommit periods. In exchange for Indiantown's continued purchase and transportation of coal during these periods, Lodestar and the coal transporter each pay Indiantown a portion of the foregone FP&L revenues. Cedar Bay executed an agreement with Lodestar, for the supply and transportation of coal and ash waste transportation and disposal services. The term of the agreement is for 20 years from January 25, 1994. Lodestar will supply 100 percent of the Project's requirements, expected to be approximately 925,000 tons of coal per year, and the pricing is based on the cost of coal, as defined in the agreement. LIME PURCHASE AGREEMENT On May 1, 1992, Indiantown entered into a lime purchase agreement with Chemical Lime Company of Alabama, Inc. for supply of the Facility's lime requirements for the Facility's dry scrubber sulfur dioxide removal system. The initial term of the agreement is 15 years from the Commercial Operation Date and may be extended for successive 5-year periods. The agreement may be canceled by either party after January 1, 2000, upon proper notice. Indiantown has no obligation to purchase a minimum quantity of lime under the agreement. 7. SALES AND SERVICES AGREEMENTS INDIANTOWN Power Purchase Agreement On May 21, 1990, Indiantown entered into a Power Purchase Agreement with FP&L for sales of the Facility's electric output. As amended, the agreement is effective for a 30-year period, commencing with the Commercial Operation Date. The pricing structure provides for both capacity and energy payments. Capacity payments remain relatively stable because the amounts do not vary with dispatch. Price increases are contractually provided. Capacity payments include a bonus or penalty payment if actual capacity is in excess of or below specified levels of available capacity. Energy payments are derived from a contractual formula defined in the agreement based on the actual cost of domestic coal at another FP&L plant, St. Johns River Power Park. 55 56 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) Energy Services Agreement On September 30, 1992, Indiantown entered into an Energy Services Agreement with Caulkins. Commencing on the Commercial Operation Date and continuing throughout the 15-year term of the agreement, Caulkins is required to purchase the lesser of 525 million pounds of steam per year or the minimum quantity of steam per year necessary for the Facility to maintain its status as a Qualifying Facility under PURPA. The Facility provided steam to Caulkins in 1995 during start-up and testing of the Facility, and declared Commercial Operation with Caulkins on March 1, 1996. CEDAR BAY Power purchase agreement Cedar Bay has a 31-year Power Purchase Agreement with FP&L for the sale of the Project's electric power output. On January 25, 1994, the contract was approved by the Florida Public Service Commission and was effective commencing with commercial operations, as defined in the agreement. The pricing structure provides for both capacity and energy payments. Capacity payments remain relatively stable as the amount does not vary with dispatch and price increases are contractually provided. Energy payments are based on a formula as defined in the agreement. Certain obligations under the agreement are secured on a second lien subordinated basis by all owned assets of Cedar Bay. Steam services agreement The Steam Services Agreement ("Steam Agreement") between Cedar Bay and Stone has an initial contract term of 22 years from January 25, 1994. The Project will supply up to 380,000 pounds per hour of steam to the Stone mill and Stone must purchase and productively use at least 600 million pounds of steam per year, which is sufficient for the Project to maintain its status as a Qualifying Facility under PURPA. Stone's payments for steam will include a monthly fixed capacity payment escalating at a fixed rate and an energy payment based on the amount of steam actually delivered. Stone's energy payment escalates with the cost of coal delivered to the Project. If Cedar Bay causes an interruption in Stone's production through loss of steam supply then Cedar Bay is liable for liquidated damages. At December 31, 1997 and 1996 Cedar Bay owed Stone $226,510 and $289,844, respectively, for liquidated damages, which are included in accounts payable and other accrued liabilities in the accompanying combined balance sheets. Stone has taken the position that Cedar Bay may be in default of its obligations under the Steam Agreement for an alleged failure by Cedar Bay to take, utilize, or pay for short recycled fiber rejects. Cedar Bay has informed Stone that it has met its obligations under the Steam Agreement. Stone has instituted legal action against Cedar Bay with respect to this matter. As management of Cedar Bay believes that it currently has no obligation in connection with the fiber reject materials, no such liability has been recorded in the accompanying financial statements. See Note 11 for further discussion of this matter. Cedar Bay received a letter of credit in the amount of $10 million from Stone for use in the event of a loss of qualifying status under PURPA. The amount would be used by Cedar Bay as necessary to maintain or reinstate the qualifying status. 8. LEGAL MATTERS In December 1997, Cedar Bay filed an action in Circuit Court for Duval County, Florida against FP&L. This action seeks damages and declaratory relief for underpayment of capacity payments arising out of FP&L's breach of the Power Purchase Agreement between FP&L and Cedar Bay (see Note 6), and FP&L's 56 57 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) breach of the implied covenant of good faith, fair dealing and commercial reasonableness between the parties. Although Cedar Bay intends to vigorously pursue this matter to recover amounts owed by FP&L, and to have future capacity payments made in a manner consistent with the Power Purchase Agreement, the outcome in this action is uncertain at this time. 9. RELATED PARTY TRANSACTIONS CONSTRUCTION CONTRACT Indiantown entered into a construction agreement with Bechtel Power Corporation ("Bechtel Power"), an affiliate of BEn, for the design, engineering, procurement, construction, start-up and testing of the Facility (the "Construction Contract"). As of December 31, 1997, the total contract value was $440,442,879 including change orders to date. Payments of $440,442,879 have been made to Bechtel Power under the Construction Contract since inception, including $450,000 paid in 1997 as a final settlement for punch list items paid in 1997 for which $900,000 had been retained in 1996. Bechtel Power guaranteed that Substantial Completion of the Indiantown Facility would occur on or prior to January 21, 1996, the Guaranteed Completion Date. Substantial Completion is achieved when the Facility demonstrates that it has met emissions guarantees and has achieved 88 percent of guaranteed net electrical output during required test periods. A schedule bonus for Substantial Completion prior to the Guaranteed Completion Date is provided in the Construction Contract. Substantial Completion was declared as of December 22, 1995 and a $6.1 million schedule bonus was paid on April 4, 1996. Performance bonuses of $4.5 million were paid on April 4, 1996, as a portion of the estimate of the total performance bonuses and a final payment of $3.9 million was made on September 17, 1996. Final completion occurred on December 13, 1996. CONSULTING SERVICES In 1997, 1996 and 1995 Indiantown paid engineering consulting fees of $0, $10,159 and $13,279, respectively, to Bechtel Generating Company, a wholly-owned subsidiary of BEn. RAILCAR LEASE Indiantown entered into a 15 year Car Leasing Agreement with GE Capital Railcar Services Corporation, an affiliate of GECC, to furnish and lease 72 pressure differential hopper railcars to Indiantown for the transportation of fly ash and lime. The cars were delivered starting in April 1995, at which time the lease was recorded as a capital lease. The leased asset of $5,753,375 and accumulated depreciation of $1,017,347, is included in property, plant and equipment at December 31, 1997. Payments of $629,856, including principal and interest, were made in 1997, and the lease obligation of approximately $5,138,000 at December 31, 1997 is reported as a lease payable in the accompanying combined balance sheets. Future minimum payments related to the Car Leasing Agreement at December 31, 1997, are approximately as follows: 1998............................................. $ 267,000 1999............................................. 287,000 2000............................................. 309,000 2001............................................. 332,000 2002............................................. 383,000 Thereafter....................................... 3,560,000 ---------- Total $5,138,000 ========== 57 58 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) DEVELOPMENT COSTS At the original financial closing in October 1992, Indiantown paid development fees and reimbursed certain costs, totaling $14.8 million to PG&E Enterprises, $3.9 million to BEn, $11.1 million to GECC and $1.2 million to USGen, related to the development of the Facility. DISTRIBUTION TO PARTNERS On June 16 and December 15, 1997, as provided in the Partnership Agreement, Indiantown distributed approximately $16.3 million and approximately $11.8 million, respectively, to the Indiantown Partners. An additional $3 million of distributable cash was retained for capital projects and is included in cash and cash equivalents as of December 31, 1997, on the accompanying combined balance sheet. Funds distributed were from electric and steam revenues collected during the second full year of commercial operations. SERVICES AGREEMENT Cedar Bay entered into a services agreement with BEn to provide management, administrative, procurement, engineering and financial services to the Partnership. Compensation to BEn includes reimbursement for personnel and other direct costs as defined in the agreement. Payments of $414,716, $450,161 and $412,674 were made to BEn in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, Cedar Bay owed BEn $79,785 and $78,816, respectively, which is included in accounts payable and other accrued liabilities in the accompanying combined balance sheets. Cedar Bay entered into a services agreement with Bechtel Power, a related party of BEn, to provide management, technical, administrative, procurement, engineering and financial services to the Partnership. Compensation to Bechtel Power includes reimbursement for personnel and other direct costs as defined in the agreement. Payments of $1,733, $163,381 and $590,321 were made to Bechtel Power in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, there were no amounts owed to Bechtel Power. MANAGEMENT SERVICES AGREEMENT Indiantown and Cedar Bay both have separate Management Services Agreements with USGen. The agreements provide for USGen to provide day-to-day management and administration of each entity's business relating to their respective projects. The Cedar Bay agreement will continue for the term of the Power Purchase Agreement while the Indiantown agreement will last for a term of 34 years. Compensation to USGen under the agreement includes an annual base fee of $1.5 million for Cedar Bay and $650,000 for Indiantown, wages and benefits for employees performing work on behalf of the Partnerships and other costs directly related to the Partnerships. The base fee is subject to an annual adjustment. Payments of $8.4 million, $3.9 million and $6.3 million were made to USGen in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, the Partnerships' owed USGen $831,741 and $4.3 million, respectively, which is included in accounts payable and other accrued liabilities in the accompanying combined balance sheets. OPERATIONS AND MAINTENANCE AGREEMENT Indiantown and Cedar Bay both have separate Operation and Maintenance Agreements with USOSC for periods of 30 and 31 years, respectively. Under the Indiantown agreement, after the 30 year period the agreement will be automatically renewed for periods of 5 years until terminated by either party with 12 months notice. If targeted plant performance is not reached, USOSC will pay liquidated damages to the Partnerships. Compensation to USOSC under the agreement includes an annual base fee of $1.5 million ($900,000 of which is subordinate to debt service and certain other costs) for Indiantown, $1.0 million for Cedar Bay, certain earned fees and bonuses based on the Facility's performance and reimbursement for certain costs 58 59 INDIANTOWN COGENERATION, L.P. CEDAR BAY GENERATING COMPANY, L.P. NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED) including payroll, supplies, spare parts, equipment, certain taxes, licensing fees, insurance and indirect costs expressed as a percentage of payroll and personnel costs. The fees are adjusted quarterly by a measure of inflation as defined in the agreement. Payments of $21.0 million, $13.7 million, and $14.7 million were made to USOSC in 1997, 1996 and 1995, respectively. At December 31, 1997 and 1996, Indiantown owed USOSC $212,458 and $61,802 respectively, which is included in accounts payable and accrued liabilities in the accompanying combined balance sheets. At December 31, 1997 and 1996, Cedar Bay had prepaid USOSC $218,423 and $363,124, respectively, which is included in deposits and other prepaid expenses in the accompanying combined balance sheets. 9. DISCLOSURE ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying amounts of the Partnerships' cash and cash equivalents, accounts receivable, deposits, prepaid expenses, investments held by trustee, accounts payable, accrued liabilities and accrued interest approximate fair value because of the short maturities of these instruments. Interest rate swap agreement entered into by Cedar Bay have no carrying value on the accompanying combined balance sheets. The fair value of Cedar Bay's swap agreement is based upon estimated market values provided by an independent investment bank, and is estimated to be a liability of $13,885,900 and $15,872,638 as of December 31, 1997 and 1996, respectively. The following table presents the carrying amounts and estimated fair values of certain of the Partnerships' financial instruments at December 31, 1997 and 1996. DECEMBER 31, 1997 FINANCIAL LIABILITIES CARRYING AMOUNT FAIR VALUE --------------------- ----------------- ------------ Tax Exempt Bonds............................................ $125,010,000 $146,016,272 First Mortgage Bonds........................................ $486,504,000 $590,214,789 Senior Project Debt/Subordinated Project Debt............... $409,772,000 $343,798,018 DECEMBER 31, 1996 FINANCIAL LIABILITIES CARRYING AMOUNT FAIR VALUE --------------------- ----------------- ------------ Tax Exempt Bonds............................................ $125,010,000 $143,067,534 First Mortgage Bonds........................................ $496,205,000 $570,178,669 Senior Project Debt/Subordinated Project Debt............... $416,349,000 $380,502,000 For the Tax Exempt Bonds and First Mortgage Bonds, the fair values of the Partnerships' bonds payable are based on the stated rates of the Tax Exempt Bonds and First Mortgage Bonds and current market interest rates to estimate market values for the Tax Exempt Bonds and the First Mortgage Bonds. For the Senior Project Debt and Subordinated Project Debt fair values are based upon current market prices for similar instruments. 10. SUBSEQUENT EVENT On January 19, 1998, the Florida Department of Environmental Protection issued a Consent Order which resolved Cedar Bay's dispute with Stone regarding the short recycled fiber rejects in favor of Cedar Bay. Cedar Bay expects that Stone will submit an objection to the terms of the order. 59 60 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of J. Makowski Company, Inc.: We have audited the accompanying consolidated balance sheets of J. Makowski Company, Inc. (a Delaware corporation) as of December 31, 1997 and 1996, and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of J. Makowski Company, Inc. and its subsidiaries as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. Washington, D.C. /s/ Arthur Andersen LLP February 5, 1998 60 61 J. MAKOWSKI COMPANY, INC. CONSOLIDATED BALANCE SHEETS AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996 (DOLLARS IN THOUSANDS) JUNE 30, DECEMBER 31, DECEMBER 31, 1998 1997 1996 ----------- ------------ ------------ (UNAUDITED) Assets Current Assets: Cash...................................................... $ 19,775 $ 35,377 $ 9,625 Restricted cash........................................... 562 218 243 Accounts receivable....................................... 14,790 19,975 27,336 Due from parent -- income taxes........................... -- 6,437 7,125 Fuel inventory and supplies............................... 3,566 1,855 2,816 Prepaid and other......................................... 213 848 391 -------- -------- -------- Total current assets............................... 38,906 64,710 47,536 -------- -------- -------- Notes Receivable -- Long-term............................... 1,525 1,480 1,696 Equity investments.......................................... 209,231 211,857 219,133 Property, plant and equipment: Feedline facility, net of accumulated depreciation of $1,750 (unaudited), $1,543 and $1,173................... 6,356 6,540 6,910 Office and other equipment, net of accumulated depreciation of $559 (unaudited), $2,805 and $1,592..... 1,445 3,239 3,307 -------- -------- -------- 7,801 9,779 10,217 Power sales and other deposits.............................. -- 343 343 Power sales agreements, net of accumulated amortization of $4,804 and $3,597 in 1997 and 1996, respectively.......... 15,474 15,333 16,540 Goodwill, net of accumulated amortization of $10,653 (unaudited), $9,424 and $6,005............................ 64,263 65,492 68,911 Management service agreements, net of accumulated amortization of $10,795 and $9,785 in 1997 and 1996, respectively.............................................. -- 5,900 6,910 -------- -------- -------- Total assets....................................... $337,200 $374,894 $371,286 ======== ======== ======== Liabilities and Stockholders' Equity Current liabilities: Accounts payable.......................................... $ 2,337 $ 11,568 $ 4,057 Accrued expenses.......................................... 9,479 19,085 17,270 Current portion of long-term debt......................... 2,068 3,040 3,054 Dividend payable.......................................... -- 10,000 -- Notes payable to affiliates............................... 43,804 43,804 43,804 -------- -------- -------- Total current liabilities.......................... 57,688 87,497 68,185 Deferred lease liability.................................... -- -- 1,330 Deferred revenue............................................ 475 125 -- Deferred income taxes....................................... 86,652 92,145 89,984 Long-term debt.............................................. 21,074 22,130 24,195 Other long-term liabilities................................. 5,742 5,022 3,920 Commitments and contingencies............................... -- -- 16,407 Minority interest........................................... 2,462 1,818 1,761 -------- -------- -------- Total liabilities.................................. 174,093 208,737 205,782 -------- -------- -------- Stockholders' equity: Preferred stock, $.01 par value; 10,000 shares authorized, none issued............................................... -- -- -- Class A common stock, $.01 par value; 2,000,000 shares authorized, 1,094,585 issued.............................. 11 11 11 Additional paid-in capital.................................. 200,929 203,886 202,577 Accumulated deficit......................................... (37,833) (37,740) (37,084) -------- -------- -------- Total stockholders' equity......................... 163,107 166,157 165,504 -------- -------- -------- Total liabilities and stockholders' equity......... $337,200 $374,894 $371,286 ======== ======== ======== The accompanying notes are an integral part of these consolidated balance sheets. 61 62 J. MAKOWSKI COMPANY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) SIX-MONTH PERIOD ENDED JUNE 30, YEAR ENDED DECEMBER 31, ------------------------- ------------------------------ 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- -------- (UNAUDITED) (UNAUDITED) Revenues: Steam and power sales............. $42,909 $29,530 $ 94,461 $ 87,812 $ 85,275 Fuel sales........................ 14,359 18,034 35,565 35,366 32,517 Service billings, primarily to affiliates...................... 1,025 4,512 9,586 13,081 17,791 Equity in earnings of operational projects........................ 3,544 8,066 17,172 17,813 5,268 ------- ------- -------- -------- -------- Total revenues............... 61,837 60,142 156,784 154,072 140,851 ------- ------- -------- -------- -------- Operating expenses: Cost of sales -- steam and power........................... 18,820 11,204 59,988 56,193 51,072 Fuel costs........................ 14,359 17,993 35,565 35,366 32,517 Cost related to service billings........................ 416 -- 4,151 4,252 1,905 Operating lease payments-Pittsfield............. 11,220 11,220 24,350 25,197 22,439 General and administrative........ 3,938 5,829 9,436 13,679 23,567 Depreciation and amortization..... 6,177 5,957 17,452 11,878 11,168 Feasibility and development....... -- 230 258 1,384 8,991 ------- ------- -------- -------- -------- Total operating expenses..... 54,930 52,433 151,200 147,949 151,659 ------- ------- -------- -------- -------- Operating income....................... 6,907 7,709 5,584 6,123 (10,808) Interest income........................ 689 295 1,533 1,135 764 Interest expense....................... (3,653) (2,722) (5,428) (5,520) (3,140) Write-down of asset to fair value...... -- -- -- (39,702) -- Loss on sale of Mason Assets........... (3,143) -- -- -- -- Other (expense)/income................. 0 (2,976) (4,487) 4,344 399 ------- ------- -------- -------- -------- Income (loss) before income taxes and minority interest in earnings........ 800 2,306 (2,798) (33,620) (12,785) Minority interest in earnings.......... (210) (203) (412) (399) (342) ------- ------- -------- -------- -------- Income (loss) before income taxes...... 590 2,103 (3,210) (34,019) (13,127) Provision (benefit) for income taxes... 683 1,601 (2,554) (8,846) (4,714) ------- ------- -------- -------- -------- Net income (loss)...................... $ (93) $ 502 $ (656) $(25,173) $ (8,413) ======= ======= ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. 62 63 J. MAKOWSKI COMPANY, INC. CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) CLASS A CLASS B COMMON STOCK COMMON STOCK ----------------- ---------------- ADDITIONAL NUMBER PAR NUMBER PAR PAID-IN ACCUMULATED SHARES VALUE SHARES VALUE CAPITAL DEFICIT TOTAL --------- ----- -------- ----- ---------- ----------- -------- Balance at December 31, 1994.......... 1,094,585 $11 150,000 $ 2 $237,204 $ (3,498) $233,719 Retirement of Class B Common Stock........................ -- -- (150,000) (2) (38,048) -- (38,050) Net loss.............................. -- -- -- -- -- (8,413) (8,413) --------- --- -------- --- -------- -------- -------- Balance at December 31, 1995.......... 1,094,585 11 -- -- 199,156 (11,911) 187,256 ========= === ======== === ======== ======== ======== Contributed capital................... -- -- -- -- 3,421 -- 3,421 Net loss.............................. -- -- -- -- -- (25,173) (25,173) --------- --- -------- --- -------- -------- -------- Balance at December 31, 1996.......... 1,094,585 11 -- -- 202,577 (37,084) 165,504 ========= === ======== === ======== ======== ======== Contributed capital................... -- -- -- -- 16,559 -- 16,559 Dividend, September 1997.............. -- -- -- -- (5,250) -- (5,250) Dividend, December 1997............... -- -- -- -- (10,000) -- (10,000) Net loss.............................. -- -- -- -- -- (656) (656) --------- --- -------- --- -------- -------- -------- Balance at December 31, 1997.......... 1,094,585 11 -- -- 203,886 (37,740) 166,157 ========= === ======== === ======== ======== ======== Distribution of MSA's to Bechtel...... -- -- -- -- 8,014 -- 8,014 Other Equity Adjustment............... -- -- -- -- (9,944) -- (9,944) Dividend, June 1998................... -- -- -- -- (1,027) -- (1,027) Net Loss.............................. -- -- -- -- -- (93) (93) --------- --- -------- --- -------- -------- -------- Balance at June 30, 1998 (Unaudited)......................... 1,094,585 $11 -- $-- $200,929 $(37,833) $163,107 ========= === ======== === ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. 63 64 J. MAKOWSKI COMPANY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX-MONTH PERIODS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (DOLLARS IN THOUSANDS) SIX-MONTH PERIODS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ------------------------------- 1998 1997 1997 1996 1995 ----------- ----------- -------- -------- --------- (UNAUDITED) (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net (loss) income....................................... $ (93) $ 502 $ (656) $(25,173) $ (8,413) Adjustments to reconcile net loss to net cash provided by operating activities: Write-down of asset to fair value..................... -- -- -- 39,702 -- Investment earnings on projects....................... (3,544) (8,132) (17,172) (17,813) (5,268) Cash distributions from projects...................... 5,005 6,228 19,724 18,834 11,013 Write-off of equity investments, net.................. (332) -- 1,240 -- -- Depreciation and amortization......................... 6,177 6,324 17,452 12,562 11,168 Provision for deferred income taxes................... 683 (1,949) 2,161 (12,097) 1,372 Minority interest in earnings......................... 210 203 412 399 342 Gain on sale of investment............................ -- -- -- -- (773) Loss on sale of Mason Assets.......................... 3,143 -- -- -- -- Other equity adjustments.............................. (9,944) -- -- -- -- Change in assets and liabilities: Restricted cash..................................... (344) 28 25 697 (705) Accounts receivable................................. 5,185 (3,700) 7,361 2,099 (11,847) Due to parent....................................... -- -- -- (2,961) 2,961 Fuel inventory and supplies......................... (1,711) 267 961 (512) (577) Prepaid and other................................... 635 (224) (457) 983 (545) Notes receivable long-term.......................... (45) -- -- -- -- Goodwill............................................ -- -- -- 181 -- Accounts payable.................................... (9,231) 9,526 7,511 (1,110) 9,980 Accrued expenses.................................... (9,606) (1,090) 1,815 (7,063) 617 Due from parent -- income taxes..................... 6,437 -- 688 2,785 (6,011) Deferred lease liability............................ -- (592) (1,330) 331 (102) Other long-term liabilities......................... 720 232 1,102 (1,589) (350) Deferred revenue.................................... 350 -- 125 -- -- Refundable income taxes............................. -- 3,532 -- -- -- Commitments and contingencies....................... -- -- (16,407) -- -- -------- ------- -------- -------- --------- Net cash (used in) provided by operating activities.................................... (6,305) 11,155 24,555 10,255 2,862 -------- ------- -------- -------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Investments in projects................................. 2,731 (450) (6,621) (4,215) (10,254) Proceeds from sale of investments....................... -- -- -- -- 8,050 Plant and equipment..................................... -- (390) (1,057) (980) (1,155) -------- ------- -------- -------- --------- Net cash provided by (used in) investing activities........................................ 2,731 (840) (7,678) (5,195) (3,359) -------- ------- -------- -------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from notes payable to affiliates............... -- -- -- -- 33,804 Proceeds from long-term debt............................ -- -- -- -- Repayment of long-term debt............................. (2,028) (1,025) (2,079) (2,482) (1,494) Equity contributions.................................... 1,027 -- 16,559 3,421 -- Return of capital....................................... -- -- -- -- (8,050) Retirement of Class B common stock...................... -- -- -- -- (30,000) Proceeds from other loans............................... -- -- -- 120 130 Distribution to stockholders............................ (11,027) -- (5,250) -- -- Net increase (decrease) in line of credit............... -- 16 -- (853) 876 Distributions to minority investor...................... -- (175) (355) (367) (357) -------- ------- -------- -------- --------- Net cash (used in) provided by financing activities........................................ (12,028) (1,184) 8,875 (161) (5,091) -------- ------- -------- -------- --------- Net increase (decrease) in cash............................. (15,602) 9,131 25,752 4,899 (5,588) Cash at beginning of period................................. 35,377 9,625 9,625 4,726 10,314 -------- ------- -------- -------- --------- Cash at end of period....................................... $ 19,775 $18,756 $ 35,377 $ 9,625 $ 4,726 ======== ======= ======== ======== ========= Supplemental disclosure of cash flow information: Cash paid during the period for: Interest, net of amounts capitalized.................... $ 2,481 $ 3,705 $ 3,128 Income taxes............................................ -- -- 252 ======== ======== ========= The accompanying notes are an integral part of these consolidated financial statements. 64 65 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION, BUSINESS AND PRINCIPLES OF CONSOLIDATION J. Makowski Company, Inc. (the "Company" or "JMC") is principally engaged in the development and management of electric generation and natural gas projects in which it has an equity ownership interest. The Company also provides consulting, managerial, administrative and fuel supply services, under management service agreements, to these projects and other entities engaged in the generation of electricity and steam and the transportation and management of natural gas supplies. The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and its majority-owned and controlled partnerships: Pittsfield Generating Company, L.P. ("Pittsfield") and Berkshire Feedline Acquisition, L.P. ("BFALP"). Pittsfield leases and operates the Pittsfield project, a 160-megawatt natural gas-fired cogeneration facility. BFALP owns and operates the pipeline that connects the natural gas transmission line of the Tennessee Gas Pipeline Company to the Pittsfield project (the "Feedline"). All material intercompany accounts and transactions have been eliminated. On August 25, 1994, PG&E Enterprises and Bechtel Enterprises through Beale Generating Company, ("Beale") acquired the stock of the Company. The acquisition was accounted for under the purchase method and the related adjustments to the fair value of the assets acquired and liabilities assumed were pushed down to the Company. See Note 13 for discussion of significant transactions affecting the Company and Beale in 1998. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES INTERIM FINANCIAL STATEMENTS Information presented as of June 30, 1998 and for the six-month periods ended June 30, 1998 and 1997 is unaudited. In the opinion of management, however, such information reflects all adjustments, which consist of normal recurring adjustments necessary to present fairly the financial position of the Company as of June 30, 1998 and the results of operations and cash flows for the six-month periods ended June 30, 1998 and 1997. The results of operations for these interim periods is not necessarily indicative of results which may be expected for any other interim period or for the year as a whole. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. CASH EQUIVALENTS The Company considers all highly liquid securities with a maturity of three months or less to be cash equivalents. FUEL INVENTORY AND SUPPLIES Inventories are stated at the lower of cost or market. Costs for materials, supplies and oil inventories are determined by the first-in, first-out method. EQUITY INVESTMENTS Most of the Company's investments in projects (see Note 3) are accounted for under the equity method. Such investments are carried at cost, determined to be the fair market value assigned at the Beale acquisition 65 66 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) in 1994, adjusted for the Company's proportionate share of undistributed earnings or losses and project distributions during the year and the differences between the Company's cost and the related underlying book values of the Company's equity investments which are being amortized on a straight-line basis over the estimated remaining lives of the projects (as of August 25, 1994), 25 to 38 years. DEVELOPMENT COSTS Project development costs (included in equity investments) of $1,467,720 and $221,505 as of December 31, 1997 and 1996, respectively, represent costs incurred after executing a power sales contract or obtaining a viable project site or signing a letter of intent and prior to obtaining project financing and starting physical construction. These costs represent amounts incurred for professional services, salaries, permits, options and other direct and incremental costs and are included in construction in progress when the project financing is obtained or expensed at the time the Company determines the project will not be developed. Development costs expensed include project-screening costs associated with identifying a potential project and include salaries, feasibility studies, legal and other costs. These costs are expensed as incurred, as they relate to projects not yet under development. DEPRECIATION The cost of property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives: Feedline facility........................................ 22 years Critical spare parts..................................... 16 years Furniture and fixtures................................... 7 years Office equipment......................................... 5 years CRITICAL SPARE PARTS Critical spare parts consist of major replacement equipment and recurring maintenance supplies required to be maintained in order to facilitate routine maintenance activities and minimize unscheduled maintenance outages. These parts are included in office and other equipment in the accompanying consolidated balance sheets and are depreciated using the straight-line method over the remaining useful life of the operating lease, which expires in 2010. POWER SALES AGREEMENTS Power sales agreements are intangible assets resulting from the Beale acquisition and are being amortized using the straight-line method over the remaining terms of the agreements (as of August 25, 1994), 15 years. GOODWILL Goodwill results from the Beale acquisition and is being amortized on a straight-line basis over 30 years. MANAGEMENT SERVICE AGREEMENTS Management service agreements are an intangible asset resulting from the Beale acquisition and are being amortized using the straight-line method over the remaining weighted average term of the agreements (as of August 25, 1994), 17.5 years. 66 67 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) INCOME TAXES Pursuant to the provisions of Statement of Financial Accounting Standards No. 109, deferred income tax assets and liabilities are recorded for the estimated future tax resulting from differences in the carrying value of assets and liabilities for tax and financial reporting purposes. LONG-LIVED ASSETS In March 1995, the Financial Accounting Standards Board ("FASB") issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed Of", effective for fiscal years beginning after December 15, 1995. SFAS No. 121 establishes accounting standards for the impairment of long-lived assets and requires that a loss be recognized for those assets if the sum of the expected future cash flows from the use of the asset and its eventual disposition (undiscounted) is less that the carrying amount of the asset. The Company adopted SFAS No. 121 on January 1, 1996. RECLASSIFICATIONS Certain 1995 and 1996 amounts have been reclassified to conform to the 1997 presentation. 3. EQUITY INVESTMENTS The Company holds equity interests in several partnerships, which were formed to build, own and operate various energy production, gas storage and transportation facilities. See Note 13 for discussion of the sale of the Ocean State Power ("OSP") projects in June 1998 and see the discussion later in this note related to the sale of TBG Cogen ("TBG"). The Company also participates in a cost-sharing agreement related to the Portland Pipeline project, for which a partnership has not yet been formed. The investment in the Portland Pipeline project was dividended to Beale in March 1998 (see Note 13). The Company's ownership interest in this project was 6.6%. Debt incurred by the partnerships is nonrecourse to the Company. The Company generally has developed its cogeneration projects as "qualifying facilities" ("QF's") under the Public Utility Regulatory Policies Act of 1978, as amended, so that the projects are not subject to rate and operational regulation under the Federal Power Act or state laws, and the Company is not subject to regulation as a public utility holding company under the Public Utility Holding Company Act of 1935, as amended. The following is a summary of aggregated financial information for all of the Company's investments, which are accounted for under the equity method: DECEMBER 31, DECEMBER 31, 1997 1996 ------------ ------------ (000'S) (000'S) COMBINED BALANCE SHEETS Current assets........................................... $ 280,538 $ 289,478 Development costs........................................ 48,975 49,980 Property and equipment, net.............................. 1,398,750 1,470,130 Other assets............................................. 68,098 55,159 ---------- ---------- Total assets..................................... $1,796,361 $1,864,747 ========== ========== Current liabilities...................................... 132,876 149,533 Other liabilities, principally nonrecourse project indebtedness.......................................... 1,241,654 1,280,052 Equity................................................... 421,831 435,162 ---------- ---------- Total liabilities and equity..................... $1,796,361 $1,864,747 ========== ========== The Company's share of equity.............................. $ 57,727 $ 63,686 ========== ========== 67 68 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DECEMBER 31, DECEMBER 31, DECEMBER 31, 1997 1996 1995 ------------ ------------ ------------ (000'S) (000'S) (000'S) COMBINED STATEMENTS OF OPERATIONS Net sales.................................... $675,334 $677,814 $626,713 ======== ======== ======== Operating profit............................. $233,527 $242,783 $198,739 ======== ======== ======== Earnings before taxes........................ $124,863 $125,154 $ 67,434 ======== ======== ======== The Company's share of equity in earnings of operational projects....................... $ 17,172 $ 17,813 $ 5,268 ======== ======== ======== SUMMARY OF INVESTMENTS The Company's share of equity in the net assets of projects......................... $ 57,727 $ 63,686 $ 55,814 Basis difference in carrying value of investees and Company's investments........ 155,610 157,143 213,200 -------- -------- -------- $213,337 $220,829 $269,014 ======== ======== ======== OPERATIONAL PROJECTS At December 31, 1997, the Company had investments in six operational facilities (five electric projects and one pipeline project). See Note 13 related to the sale of two of the operational facilities (the OSP projects and a pipeline development project). Also see information later in this note related to the sale of TBG in February 1998. The five electric facilities have contracted to sell electric generating capacity to utilities and other customers under long-term power sales agreements. The facilities are fueled primarily by natural gas purchased under long-term supply agreements and, with a few exceptions, long-term firm transportation contracts. Generally, changes in energy payments under a project's power sales contract correspond approximately to changes in fuel cost, and, in certain cases, prices and costs are directly linked. Each project, except for the OSP projects, which are not QF facilities, also sells steam for industrial and other purposes under a long-term contract to an unaffiliated company located adjacent to the project site. These steam sales contracts require the purchaser to take at least the minimum steam necessary for the project to maintain its QF status. The operations of and the rates charged by the OSP projects and Iroquois Gas Transmission System ("IGTS") are subject to regulation on the federal and state levels in the United States and certain gas transportation agreements are subject to regulation on the federal and provincial levels in Canada. The Company's interests in each of these projects have been pledged as collateral for each of the projects' respective nonrecourse financing. TBG COGEN On February 5, 1998, Calpine Corporation ("Calpine") acquired JMC's interest in TBG Cogen. This 10% interest was held by a wholly-owned subsidiary of JMC. The purchase price included a $125,000 non-refundable good faith deposit paid prior to December 31, 1997, which is included as deferred revenue in the accompanying consolidated balance sheet, and $1,125,000 in cash, paid at the time of sale. Subsequent to the purchase, Calpine assumes all liabilities of the Company's wholly-owned subsidiary, including the $1,000,000 demand notes discussed in Note 6. This sale resulted in an immaterial loss to the Company; accordingly, no adjustments to the Company's investment in TBG Cogen are included in the accompanying consolidated financial statements. 68 69 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) SELKIRK COGEN PARTNERS, L.P. ("SELKIRK") In October 1995, Niagara Mohawk Power Corporation ("NIMO") filed its "Power Choice" proposal with the New York State Public Service Commission and filed a Report on Form 8-K with the Securities and Exchange Commission whereby NIMO described proposals to restructure the utility's business, including the reorganization of its assets and the renegotiations of its contracts with non-regulated generators, like Selkirk. NIMO had proposed that, if it cannot renegotiate its contracts with the non-regulated generators, it would take possession of such independent power projects through the power of eminent domain and subsequently sell such assets. Further, NIMO stated that it had not ruled out the ultimate possibility of a filing for restructuring under Chapter 11 of the U.S. Bankruptcy Code. On March 10, 1997, NIMO filed a Form 8-K with the Securities and Exchange Commission in which it announced an agreement in principle to terminate certain power purchase contracts. The Company is committed to negotiate to reach agreement on a restructured power purchase agreement for Selkirk. The Company cannot definitively determine the effect, if any, the restructured power purchase agreement will have on the Selkirk project. At this time the Company believes any agreement with NIMO will not threaten the continued existence of the Selkirk project. Given the current facts, the Company believes its investment in Selkirk is probable of recovery. However, should current facts change, there is a reasonable possibility of loss. See Note 13 for additional disclosure related to negotiations with NIMO. Consolidated Edison ("ConEd"), a power purchaser at Selkirk, by a letter dated September 19, 1994, claimed the right to acquire a portion of Unit 2's natural gas supply not used in operating Unit 2 (the "excess gas"), when Unit 2 is dispatched off-line or at less than full capacity. The ConEd power purchase agreement contains no express language granting ConEd any rights to such excess gas and Selkirk has stated to ConEd that claims to excess gas are without merit. To date ConEd has paid all amounts invoiced by Selkirk in accordance with the ConEd power purchase agreement. If ConEd were to prevail in its claim to Unit 2's excess natural gas volumes, Selkirk would lose its ability to engage in lay-off sales of such volumes at favorable prices relative to their costs, and thus cash flows from gas resale activities would also be materially and adversely affected. The Company is unable to determine the outcome of this uncertainty. On June 20, 1990 and October 29, 1992, Selkirk entered into currency exchange agreements to hedge against future exchange rate fluctuations which could result in additional costs incurred under fuel transportation agreements which are denominated in Canadian dollars. Selkirk is exposed to credit loss under the currency agreements. In the unlikely event that a counterparty fails to meet the terms of the agreements, Selkirk's exposure is limited to the currency exchange rate differential. However, Selkirk does not anticipate nonperformance by the counterparties. MASSPOWER MASSPOWER has entered into interest rate exchange agreements to mitigate the interest rate risks associated with its floating-rate term loans. The agreements provide for the exchange of fixed-rate interest payment obligations for floating-rate interest payment obligations on notional amounts of principal. In addition, MASSPOWER has three currency exchange agreements with different banks to mitigate the currency exchange risks associated with MASSPOWER's Canadian fuel transportation costs. In the event of default by any of the bank counterparties to the interest rate and currency exchange agreements, MASSPOWER could be exposed to interest rate and currency exchange rate risks. MASSPOWER does not anticipate nonperformance by any of the counterparties. 69 70 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DEVELOPMENT AND CONSTRUCTION PROJECTS Altresco Lynn, L.P. ("Riverworks") At December 31, 1995, Riverworks had an outstanding development loan due to General Electric Capital Corporation ("GECC") that amounted to $12,568,000, which was used to finance development and pre-construction costs. The note had as a maturity date the earlier of March 31, 1996 or the date of construction financing. The development loan was a liability of Riverworks, the partnership had no assets, and the loan was nonrecourse to the Company. In March 1996, Boston Edison Company ("BECO") and GECC negotiated a tentative agreement that BECO would pay $9.2 million to Riverworks for withdrawing the power bid. In June 1996, $7.025 million was paid to GECC, $700,000 was paid to the Company's former partners in the West Lynn Creamery project and $1.475 million was retained by Riverworks. An additional $550,000 related to the Riverworks project was received by the Company from CommElec. The receipt of $2.025 million by the Company was recognized as income during 1996 and is included as other income in the accompanying statements of operations. Avoca Natural Gas Storage Project ("Avoca") Brine disposal problems encountered during construction in 1996 caused the Company to evaluate this project for possible impairment. A write-down of $39,702,000 was required and included the purchase price premium and allocated goodwill resulting from the Beale acquisition, cash invested since the Beale acquisition and a liability reflecting the Company's equity commitments related to the project. The carrying value of the investment is zero at December 31, 1997 and 1996, and $0 and $16,407,000 is included as a liability to reflect future equity commitments at December 31, 1997 and 1996, respectively. This equity commitment was satisfied by a $16,559,000 equity infusion by the Beale shareholders during May 1997. The Company believes it has accrued the full extent of the losses incurred or to be incurred with respect to this project. Avoca and JMC Avoca, Inc. ("JMC Avoca"), a wholly-owned subsidiary of JMC, filed for protection under Chapter 11 of the U.S. Bankruptcy Code on July 29, 1997 (See Note 10). Management believes this action does not have a material impact on the JMC consolidated financial statements at December 31, 1997. 70 71 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other From time to time, the Company enters into cost-sharing arrangements to fund the feasibility and development of various projects, including nonutility generating projects and gas storage facilities throughout North America. As of December 31, 1997 the Company's share of the one outstanding project was 6.6% (see Note 4). On March 1, 1998, the Company dividended to Beale its interest in this project (See Note 13). Details of the Company's projects in operations and development are shown in Table 1. J. MAKOWSKI COMPANY, INC. PROJECTS INVESTMENT SCHEDULE FOR THE YEARS ENDED DECEMBER 31, 1997 AND 1996 (000S) JMC SHARE OF: ------------------- IN- SIZE JMC INVESTMENT (2) PROJECT EARNINGS SERVICE IN JMC ------------------- ------------------- PROJECT LOCATION DATE MW TYPE OWNERSHIP % 12/31/97 12/31/96 12/31/97 12/31/96 - ---------------------- ----------- ------- ------ -------- ----------- -------- -------- -------- -------- DEVELOPMENT: Portland(5)........... ME/NH/ N/A N/A Pipeline 6.60% $ 2,242 $ 222 -- -- VT/MA OPERATIONS: TBG Cogen(3).......... Bethpage, Aug-89 50 Cogen 10.00% 1,266 1,229 $ (4) $ 154 NY OSP(4)................ Burrillville, Dec-90 250 Combined 10.10% 12,336 12,726 1,655 1,707 RI Cycle OSP II(4)............. Burrillville, Oct-91 250 Combined 10.10% 8,393 8,389 1,529 1,565 RI Cycle IGTS.................. NY/CT Dec-91 N/A Pipeline 4.93% 10,053 9,956 2,808 2,231 Selkirk............... Selkirk, NY Sep-94 344.90 Cogen 47.21%(1) 137,161 146,886 8,039 9,688 MASSPOWER............. Springfield, Sep-93 240 Cogen 30.00% 40,406 39,725 3,145 2,468 MA Total operational.......................................................... 209,615 218,911 17,172 17,813 Total equity investments................................................... $211,857 $219,133 $ 17,172 $ 17,813 JMC SHARE OF: ------------------- CASH DISTRIBUTIONS ------------------- PROJECT 12/31/97 12/31/96 - ---------------------- -------- -------- DEVELOPMENT: Portland(5)................ -- -- OPERATIONS: TBG Cogen(3)............... $ -- $ (24) OSP(4)..................... (1,939) (1,878) OSP II(4).................. (1,495) (1,980) IGTS....................... (2,929) (1,774) Selkirk.................... (11,979) (11,075) MASSPOWER.................. (1,382) (2,103) Total operational.......... (19,724) (18,834) Total equity investments... $(19,724) $(18,834) - --------------- (1) Ownership percentage reflects JMC's effective interest in the project. (2) Includes the Company's underlying equity in the net assets of each project and the unamortized portion of the basis difference when Beale purchased the Company (3) Sold in February 1998 (4) Sold in June 1998 (See Note 13) (5) Interest dividended to Beale in March 1998 (See Note 13). 4. RELATED-PARTY TRANSACTIONS The Company provides consulting, managerial and administrative services to several entities in which the Company has an interest. Transactions with these entities represented 84%, 93% and 87% of revenues from service billings for the years ended December 31, 1997, 1996 and 1995, respectively, and 93% and 65% of total accounts receivable at December 31, 1997 and 1996, respectively. During the years ended December 31, 1997 and 1996, Orchard Gas, a wholly-owned subsidiary of the Company, purchased from unrelated third parties approximately $35,565,000 and $35,366,000, respectively, in fuel for sale to its customers. Orchard Gas does not generate a profit on its fuel sales, as all natural gas is sold at a cost equal to that incurred by the Company. Approximately 97% and 94% of this fuel was purchased by MASSPOWER, an affiliate of the Company, during 1997 and 1996, respectively. As of December 31, 1997 71 72 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and 1996, Orchard Gas was due $2,963,223 and $3,031,279, respectively, from MASSPOWER for fuel sales. This amount due is included in accounts receivable in the accompanying consolidated balance sheets. Employees of JMC were merged into U.S. Generating Company's ("USGen"), an affiliated entity, payroll and this payroll cost, for management and administrative services, is billed directly to JMC including a contractual profit margin. JMC also reimburses USGen for other direct costs incurred on their behalf during the year. During 1997 and 1996, labor, benefits and other direct costs incurred by USGen for JMC amounted to $11,778,000 and $11,878,000, respectively. The Company funds development costs of projects in which it has an ownership interest in accordance with certain cost-sharing agreements. For the periods ended December 31, 1997, 1996 and 1995, $258,000, $1,384,000 and $5,216,000, respectively, of such costs were incurred by these projects and is included in feasibility and development expense in the accompanying consolidated statements of operations. Of these balances, $0 and $112,000 is included in accounts payable in the accompanying consolidated balance sheets at December 31, 1997 and 1996, respectively. The Company has demand notes for $10,000,000 and $33,803,800 payable to Beale and Pentagen Investors, L.P. ("Pentagen"), respectively. Pentagen is an affiliated partnership and a former subsidiary of the Company whose sole asset is a 53.02% effective interest in Selkirk. The note to Beale accrues interest at the prime rate (8.50%, 8.25% and 8.50% at December 31, 1997, 1996 and 1995, respectively) and interest expense of approximately $844,000, $827,000 and $879,000 was recorded for the years ended December 31, 1997, 1996 and 1995. The promissory note to Pentagen issued in June 1995, accrues interest at LIBOR plus 0.5% (6.26%, 6.11% and 6.50% at December 31, 1997, 1996 and 1995, respectively) and interest expense of approximately $2,103,000, $2,054,000 and $1,185,000 was recorded for the years ended December 31, 1997, 1996 and 1995, respectively. No interest has been paid as of December 31, 1997 on either demand note. Under certain conditions, including bankruptcy or insolvency of the Company, and notification from the note holder, the unpaid principal may require prepayment in whole or in part, otherwise the entire principal amount shall be due and payable in June 2000. Interest is payable quarterly in arrears commencing September 29, 1995. The note is secured by a pledge of the Company's partnership interests, via a subsidiary and the affiliated partnership, in the Selkirk project. 5. INCOME TAXES For financial reporting purposes, federal income taxes are provided for in accordance with a federal tax-sharing agreement between the Company and its parent, which provides, among other things, that the Company will generally pay the amount required assuming separate Company tax returns were filed. The tax-sharing agreement also provides that a member of the federal consolidated tax group can recognize the tax effects of its separate losses to the extent those losses are used or are expected to be utilized on a consolidated basis. At December 31, 1997 and 1996, the Company was owed by its parent $6,437,000 and $7,125,000, respectively, for current federal income taxes. State income taxes are provided for based on amounts, which the Company anticipates paying separately to various states. The Company is currently not operating under any tax sharing agreements relating to state taxes. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized. A valuation allowance of $10,961,000 has been established. Of this total, $ 4,316,000 was created at the Beale acquisition date as a result of certain restrictions on utilization of tax assets due to ownership change limitations and the Company's uncertainty of its ability to realize the tax benefits on a portion of its net operating loss and credit carryforwards. Any subsequent reversal of the valuation allowance relating to net operating losses existing at the acquisition date will first reduce goodwill related to the Company's acquisition, then other noncurrent intangible assets related to the acquisition, and then income tax expense. 72 73 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 1997, the Company has unused net investment credits, which may be used to offset future federal taxes payable, of approximately $972,000 which expire in year 2004. The Company also has federal net operating loss carryforwards of approximately $7,804,000 that begin to expire in year 2004. Approximately $3,300,000 of those net operating loss carryforwards resulted from the period prior to the Beale acquisition. At December 31, 1997, the Company has Massachusetts net operating loss carryforwards of approximately $27,000,000 which may be used to offset future Massachusetts taxable income and which will expire in years 1997-2000. The significant components of net deferred income tax liabilities as of December 31, 1997 and 1996 are as follows (in thousands): 1997 1996 -------- -------- Deferred income tax liabilities: Partnership differences................................... $ 4,147 $ -- Allocation of premium..................................... 91,301 91,908 -------- -------- Total deferred tax liabilities.................... 95,448 91,908 Deferred income tax assets: Development costs......................................... 1,487 1,723 Partnership differences................................... -- 2,244 Deferred state taxes...................................... 6,173 (302) Other..................................................... 683 510 Net operating losses...................................... 4,425 7,454 Investment tax credit..................................... 972 1,163 Alternative minimum tax credit............................ 524 524 -------- -------- Total deferred tax assets......................... 14,264 13,316 Valuation allowance......................................... (10,961) (11,392) -------- -------- Net deferred tax asset................................. 3,303 1,924 -------- -------- Net deferred tax liability.................................. $ 92,145 $ 89,984 ======== ======== Significant components of the Company's income tax expense (benefit) attributable to continuing operations are as follows: DECEMBER 31, DECEMBER 31, DECEMBER 31, 1997 1996 1995 ------------ ------------ ------------ (000'S) (000'S) (000'S) Current Federal......................................... $(4,588) $ 3,189 $(5,954) State........................................... (127) 59 (20) ------- -------- ------- Total current.............................. (4,715) 3,248 (5,974) Deferred Federal......................................... 2,848 (12,356) 1,888 State........................................... (687) 262 (628) ------- -------- ------- Total deferred............................. 2,161 (12,094) 1,260 Total income tax benefit................... $(2,554) $ (8,846) $(4,714) ======= ======== ======= 73 74 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The reconciliation of the differences between the U.S. statutory rate and the effective tax rate based on income before taxes is as follows: DECEMBER 31, DECEMBER 31, DECEMBER 31, 1997 1996 1995 ------------ ------------ ------------ Federal statutory income tax rate............ (35.00)% (35.00)% (35.00)% Items that affect tax expense: State taxes, net of federal effect......... (16.48) (.55) (5.75) Amortization of goodwill................... 25.71 5.76 4.84 Other permanent differences................ .95 -- -- True-up of prior year taxes.................. (54.74) 3.79 -- ------ ------ ------ Effective tax rate........................... (79.56)% (26.00)% (35.91)% ====== ====== ====== 6. DEBT SENIOR SECURED NOTES PAYABLE In November 1992, a subsidiary of the Company obtained $19,000,000 through the issuance of 12-year senior secured notes to fund its equity commitments to OSP. These notes bear interest, payable quarterly, at a fixed rate of 7.42%. The notes amortize quarterly over the life of the loan and mature on December 31, 2004. The subsidiary entered into a collateral agency agreement whereby all distributions from OSP and OSP II are remitted to a cash collateral account and pledged to the agent bank. All required quarterly principal and interest payments are deducted from the account by the bank and any excess is remitted to the subsidiary. The Company pledged all rights, title and interest in the capital stock of the subsidiary to the security agent and the subsidiary assigned all rights, title and interest in the partnerships. The notes are nonrecourse to the Company. MORTGAGE LOAN PAYABLE In March 1993, BFALP obtained a $10,000,000 mortgage loan in order to refinance the remaining construction costs related to the Feedline. The mortgage loan carries a per annum floating rate of interest equal to the 30-day rate for commercial paper, in effect at the end of the month, plus 6.07% (11.65% and 12.02% at December 31, 1997 and 1996, respectively). Interest was payable monthly on the outstanding balance through December 31, 1995. Subsequent to December 31, 1995, principal and interest are due monthly, with a maturity date of December 31, 2010. The loan is secured by a first mortgage on the Feedline and collateralized by all the outstanding shares of a subsidiary of the Company and the pledge of all partnership interests. In addition, each of the partners has guaranteed $500,000 of the mortgage loan. TERM LOAN PAYABLE Pittsfield has a term loan agreement with GECC. The loan, which expires in 2009, has a fixed interest rate of 10.38%. Principal and interest are payable quarterly in arrears. OTHER The Company is obligated, as a result of one of its equity investments, to fund $1,000,000 in an escrow account in favor of one of the power purchasers, which will be returned in the years 2003 and 2004. These fundings are financed by noninterest-bearing demand notes, are included in accounts receivable on the accompanying consolidated balance sheets and totaled $1,000,000 at both December 31, 1997 and 1996. 74 75 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of December 31, 1997 and 1996, the Company's long-term debt consisted of the following: 1997 1996 ------- ------- (000'S) (000'S) Senior secured notes payable, interest payable quarterly at 7.42%..................................................... $10,429 $11,949 Mortgage loan payable, interest payable monthly at commercial paper rate plus 6.07%.......................... 9,435 9,745 Term loan payable, interest payable quarterly at 10.38%..... 4,306 4,508 Other....................................................... 1,000 1,047 ------- ------- 25,170 27,249 Less current portion........................................ 3,040 3,054 ------- ------- $22,130 $24,195 ======= ======= Following are maturities of long-term debt for each of the next five years (in thousands): 1998....................................................... 3,040 1999....................................................... 2,109 2000....................................................... 2,181 2001....................................................... 2,262 2002....................................................... 2,354 Thereafter................................................. 13,224 ------- Total............................................ $25,170 ======= 7. DISCLOSURE OF FAIR MARKET VALUE OF FINANCIAL INSTRUMENTS The Company's financial instruments consist of cash, restricted cash, accounts receivable, accounts payable, accrued expenses, notes payable to affiliates and long-term debt. The fair value of these financial instruments, with the exception of the senior secured notes payable and the term loan payable, approximate their carrying value as of December 31, 1997 and 1996. The fair value of the senior secured notes payable and the term loan payable as of December 31, 1997 and 1996 was approximately $13,542,000 and $15,150,000, respectively. The fair value was estimated using discounted cash flows analysis, based on the Company's current incremental borrowing rate. The carrying value of these two notes is $14,735,000 and $16,457,000 at December 31, 1997 and 1996, respectively. 8. STOCKHOLDERS' EQUITY COMMON STOCK The declaration and payment of dividends on the Class A common stock and the amount thereof, are solely at the discretion of the Board of Directors, and holders of such stock are not entitled to any rights of conversion. In December 1997, the Company declared a $10,000,000 dividend. See Note 13 for discussion of subsequent payment of this dividend. 9. COMMITMENTS PITTSFIELD Operating lease The Pittsfield project lease with GECC has been accounted for as an operating lease. The lease has an initial term of 20 years, with two five-year renewal options, exercisable by the Company. Rent is due in quarterly installments of approximately $5,610,000. Supplemental rent is due under certain circumstances and remitted in the form of lessor distributions. The Company has the option to purchase the plant during years 12 75 76 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and 20 of the lease agreement; in year 12, at the higher of its then fair market value or the stipulated loss value (as defined in the lease) and in year 20, at its then fair market value. For the years ended December 31, 1997, 1996 and 1995, rent expense amounted to $24,349,916, $25,196,731 and $22,445,667, respectively (of which $1,911,000, $2,758,000 and $6,389,000, respectively, is related to supplemental rents) all of which is included in rent under operating lease payments-Pittsfield in the accompanying consolidated statements of operations. Future minimum lease payments (in thousands), at December 31, 1997, under the operating lease are as follows: 1998...................................................... 22,439 1999...................................................... 22,439 2000...................................................... 22,439 2001...................................................... 22,439 2002...................................................... 22,439 Thereafter................................................ 173,905 -------- Total........................................... $286,100 ======== In accordance with the lease, GECC provided a funding mechanism for the estimated remaining costs of completing the Pittsfield project (the completion fund). At December 31, 1997 and 1996, approximately $435,000 and $436,000, respectively, was available from GECC in their completion fund for remaining facility costs. These funds are available to the Pittsfield project, subject to GECC approval. The Pittsfield project lease is collateralized by the assignment of the Company's rights, title and interest in all project contracts and the pledge of all Company interests to the trustee and is nonrecourse to the individual partners. Certain operative documents related to the lease contain warranties and covenants including, among others, a restriction on Company distributions and additional indebtedness. In addition, a lease reserve account is required to be maintained due to lease covenants under certain circumstances. On an annual basis, the funding requirement if any is determined based on the terms of the disbursement and security agreement. This account is not currently required. Power sales agreements -- electricity Pittsfield has a power sales agreement, as amended, with New England Power Company ("NEPCO") to sell 65.6% of the net electric output of the project through 2010, subject to one six-year extension. In accordance with the agreement, Pittsfield has agreed to provide NEPCO with a security interest in a specified portion of its electric revenues. Should Pittsfield experience an event of default under the terms of the power sales agreement and NEPCO terminates the agreement, Pittsfield is obligated to pay NEPCO the total amount accumulated as liquidated damages. As of December 31, 1997 and 1996, the amount totaled approximately $34,307,000 and $49,612,000 respectively. In January 1995, the liquidating damages began to decline and will continue until eliminated. In addition, Pittsfield is required to provide an irrevocable letter of credit to NEPCO to secure payment of liquidated damages in the event of nonperformance under the power sales agreement. The letter of credit increases monthly to the extent of 4% of NEPCO electric revenues received by Pittsfield until the letter of credit equals the lesser of the amount of liquidating damages or $18,000,000. At December 31, 1997 and 1996, the letter of credit totaled approximately $18,000,000 and $18,071,000, respectively. Pittsfield has power sales agreements with Cambridge Electric Light Company and Commonwealth Electric Company to sell a total of 34.4% of the net electric output of the Pittsfield project. Delivery of this net 76 77 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) electric output will continue until December 31, 2011. Pittsfield is required to provide irrevocable letters of credit to Cambridge Electric Light Company and Commonwealth Electric Company to secure its performance under these power sales agreements. At December 31, 1997 and 1996, the letters of credit outstanding were approximately $5,737,000 and $5,109,000 for Cambridge Electric Light Company, respectively, and $4,554,000 and $4,209,000 for Commonwealth Electric Company, respectively. The letters of credit reach a maximum of $11,100,000 for calendar year 1998 and expire on December 31, 2002 and December 31, 2001, respectively. Steam sales agreements Pittsfield has a steam sales agreement with General Electric ("GE") through 2008, subject to two five-year extensions. GE has committed to purchase a minimum of 700 million pounds (mmlbs.) of steam per year, up to a maximum of 840 mmlbs. per year. The basic contract price (subject to escalation or renegotiation) of $1,000,000 annually for up to 840 mmlbs. of steam per year will be reduced if steam sales are less than 840 mmlbs. per year, with the total reduction not to exceed $400,000 annually. Total operating revenue from GE was approximately $712,000, $780,000 and $600,000 for steam delivered during the years ended December 31, 1997, 1996 and 1995, respectively. Fuel supply agreements Pittsfield has two new long-term gas purchase and sale agreements with Talisman Energy, Inc. ("Talisman") and Home Oil Company Limited ("Home"). The Talisman agreement, which expires on September 1, 2010, calls for a daily fuel supply of 22,420 Mcf/day. The Home agreement expires on October 31, 2011, and calls for a daily fuel supply of 11,759 Mcf/day. In addition, Pittsfield provides irrevocable letters of credit to Talisman and Home to secure performance under the agreements. At December 31, 1997 and 1996, the total outstanding amount under the letters of credit was $3,300,000. Fuel transportation agreements Pittsfield's Canadian fuel suppliers have contracted for the transportation of fuel from the wellhead in Empress, Alberta on the Nova Pipeline ("Nova") to the TCPL interconnect. Pittsfield has entered into a firm transportation agreement for the delivery of fuel from the Nova/TCPL interconnect to the U.S./Canadian border. In addition, Pittsfield entered into a long-term transportation agreement for firm transportation of fuel from the U.S./Canadian border to the Feedline. In June 1995, Pittsfield entered into a short-term firm service transportation agreement with TCPL to transport fuel of 21,500 Mcf/day from the Nova/TCPL pipeline interconnect at Empress, Alberta to the U.S./ Canadian border at Niagara Falls. This agreement expired on March 31, 1996. In December 1995, the National Energy Board ("NEB") approved Pittsfield's application for long-term transportation service on TCPL. Pittsfield has negotiated to replace the short-term firm service transportation agreement with a firm long-term transportation agreement. The term of the long-term firm transportation agreement commenced on April 1, 1996 and expires on October 31, 2010. Under the terms of this agreement, Pittsfield is required to provide an irrevocable letter of credit to secure performance. At December 31, 1997 and 1996, the total letter of credit outstanding was approximately $1,600,000. In October 1995, Pittsfield entered into a temporary capacity assignment agreement with NEPCO for firm transportation on TCPL. Pittsfield took assignment of 10,000 Mcf/day of TCPL capacity effective November 1, 1995. The capacity assignment allows Pittsfield to transport fuel on TCPL from Empress, Alberta to Waddington, New York. In September 1997, the temporary capacity assignment agreement was 77 78 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) made permanent effective from November 1, 1997 through October 31, 2006. Under the terms of the permanent assignment agreement, Pittsfield is required to provide an irrevocable letter of credit to secure performance. At December 31, 1997, the total letter of credit outstanding was approximately $413,000. In October 1997, Pittsfield entered into two temporary capacity assignment agreements with Renaissance Energy, Ltd. ("Renaissance") for firm transportation on TCPL. These agreements exchange delivery points from Waddington, New York to Niagara Falls, New York to allow Pittsfield to deliver Canadian gas supplies to the interconnect at Niagara Falls to match the downstream firm transportation. Effective November 1, 1997, Pittsfield assigned to Renaissance 10,000 Mcf/day of capacity for fuel transportation on TCPL from Empress, Alberta to Waddington, New York. In return, Pittsfield took assignment from Renaissance for 10,000 Mcf/day of capacity for fuel transportation on TCPL from Empress, Alberta to Niagara Falls, New York. The temporary capacity assignment agreements are effective from November 1, 1997 to November 1, 1998. Renaissance and Pittsfield are in the process of executing permanent assignment agreements to be effective November 1, 1998. NEPCO contingency Pursuant to the rate formula established in the NEPCO power sales agreement, Pittsfield bills NEPCO for reimbursement of transportation charges (including finance charges) related to the Feedline. The NEPCO contingency exists because NEPCO has not acknowledged in writing its obligation to reimburse the Company for such charges using the rate formula or terms set forth in the NEPCO power sales agreement. As of December 31, 1997, NEPCO continued to reimburse the Company for amounts billed for transportation charges related to the Feedline. Transmission agreements Pittsfield has an interconnection agreement whereby Northeast Utilities ("NU") provides the transmission of electricity to NEPCO through 2010. In December 1994, the agreement was amended and Pittsfield provided NU with a $343,388 application deposit, which is refundable upon expiration of certain agreements (December 31, 2011) and is reflected as a long-term transmission deposit, included as power sales and other deposits in the accompanying consolidated balance sheets as of December 31, 1997 and 1996. Pittsfield has agreements with Montaup Electric Company and Boston Edison Company for the transmission of electricity to third-party purchasers terminating on December 31, 2011. Operation and maintenance agreement Pittsfield and GE entered into a six-year, fee-based agreement whereby GE provides ongoing operating and maintenance services. GE is also entitled to an annual bonus based on the performance of the Pittsfield plant. The agreement with GE expired on September 30, 1996. Pittsfield paid GE $375,000 in November 1996 for the bonus earned during the nine months ended September 30, 1996. Pittsfield entered into a new agreement on October 1, 1996 with U.S Operating Services Company ("USOSC"), an affiliated entity, which extends through October 31, 2002 and automatically extends for an additional five years unless terminated by either party. The USOSC agreement provides for ongoing operating and maintenance services similar to those in the GE agreement. Pittsfield paid USOSC $125,000 in February 1997, which was accrued for at December 31, 1996, for the bonus earned during the three months ended December 31, 1996. As of December 31, 1997, Pittsfield has $500,000 in accrued bonuses due to USOSC included in the accompanying consolidated balance sheet and in operating expenses in the accompanying consolidated statement of operations for the year then ended. 78 79 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Site lease Pittsfield has a lease with GE for certain property on which its plant is located. The lease term expires the later of April 2028 or the economic useful life of the plant. The lease may be terminated in the event that the steam sales agreement with GE is terminated for default. The lease provides for rent of $1 for the entire lease term. Office lease In 1989, the Company entered into a ten year operating lease for office space, commencing June 1989, with payments beginning September 1990. The Company provided for the obligation on a straight-line basis over the term of the lease and accrued a deferred lease liability for rent incurred from the commencement date through October 31, 1996. This lease was terminated on October 31, 1996 by the Company and assumed by USGen. The Company's deferred lease liability has been relieved to zero. Total rent expense was approximately $1,272,000 and $938,000 for the years ended December 31, 1996 and 1995, respectively, and is included in general and administrative expense in the accompanying consolidated statement of operations. 10. CONTINGENCIES AVOCA During 1997, JMC Avoca was named in several civil suits on behalf of contractors and other vendors seeking damages related to Avoca, an unsuccessful development project. This project, located in Steuben County, New York, was a development project owned by JMC Avoca and two other general partners. In July 1997, Avoca and its partners, including JMC Avoca, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. JMC and the other non-debtor affiliates of JMC named in any such lawsuits are responding to the above claims and undertaking their respective legal defenses. Given the uncertainty associated with this litigation, management cannot predict the outcome or estimate JMC's exposure at this time. 11. CONCENTRATION OF CREDIT RISK The Company provides management and consulting services to, and invests in, projects and entities engaged in the generation of electricity and transportation of natural gas. The majority of the Company's service revenues are from affiliated entities; therefore, the Company does not perform credit evaluations of these entities' financial condition and does not require collateral. Credit losses historically have been small, which is consistent with management's expectations. 12. SALE OF MANAGEMENT SALES AGREEMENTS On January 1, 1998, the Company sold its management sales agreements with Alberta Northeast Gas and Boundary Gas, Inc., and use of the name Northeast Gas Marketing for approximately $2,000,000. Management does not believe the outcome of this will have a material impact on the financial position, results of operations, or cash flows of the Company. 13. EVENTS SUBSEQUENT TO DATE OF AUDITOR'S REPORT (UNAUDITED) On March 1, 1998, JMC distributed the stock of ten subsidiary companies to Beale. The distribution was intended to complete the purchase and sale transaction entered into in September 1997 between PG&E Generating Company ("PGen"), a wholly owned indirect subsidiary of PG&E Enterprises and Bechtel Generating Company ("BGen"), a wholly owned indirect subsidiary of Bechtel Enterprises. Subsequent to this distribution, the stock of the companies was further distributed or sold. 79 80 J. MAKOWSKI COMPANY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In May 1998, PGen's indirect ownership interest in Beale was transferred to U.S. Generating Company, LLC ("USGenLLC") and subsequently contributed by USGenLLC to its subsidiary, USGen Power Group, LLC ("Power"). On June 24, 1998, Power and BGen each contributed cash totaling approximately $1 million in exchange for the stock of Mason Generating Company. The cash contribution and the related allocation of stock was consistent with their ownership ratio of Beale. Immediately following the formation of Mason, it purchased six wholly-owned subsidiaries of JMC for approximately $1 million. The sale resulted in a loss of approximately $3 million to JMC. JMC the distributed the cash proceeds from this sale to Beale, who in turn distributed the cash pro rata to Power and BGen. On October 15, 1998, Beale was merged with and into JMC. JMC was then renamed Beale Generating Company ("New Beale"), indicating a reverse merger. The surviving company, New Beale, consists of all the assets and liabilities previously held by both Beale and JMC and is owned 89.1% by Power and 10.9% by BGen. The transactions described above, except for the transfer of ownership interest in Beale in May 1998, were performed to prepare BGen's 10.9% interest in Beale for sale. Such sale is expected to occur in October 1998 by a subsidiary of Cogentrix Energy, Inc, a North Carolina corporation. In June 1998, JMC sold its interest in the OSP projects which resulted in a nominal gain. On August 31, 1998 Selkirk and NIMO consummated the transactions relating to the amendment and restatement of the existing power purchase agreement between Selkirk and NIMO pursuant to the Master Restructuring Agreement dated as of July 9, 1997, as amended, among NIMO, Selkirk and certain other independent power producers (the "MRA"). As contemplated by the MRA, on that date (i) Selkirk notified NIMO of Selkirk's determination that the requirements of Selkirk's Trust Indenture, dated as of May 1, 1994 (the "Indenture"), with respect to the restructuring of certain project contracts relating to the operation of Unit 1 of the Selkirk facility had been satisfied: (ii) the Amended ad Restated Power Purchased Agreement, dated as of July 1, 1998 between Selkirk and NIMO became effective; and (iii) NIMO made certain payments into Selkirk's Project Revenue Fund maintained at Bankers Trust Company, as Depository Agent under the May 1, 1994 Deposit and Disbursement Agreement. In addition, Selkirk has delivered notices to Paramount Resources Limited ("Paramount") and TransCanada Pipelines Limited ("TransCanada") that the Second Amended and Restated Gas Purchase Contract, dated as of May 6, 1998 between Selkirk and Paramount, and the Amending Agreement to Gas Transportation Contract, dated as of July 20, 1998, between Selkirk and TransCanada have become effective. In June 1998, the $10,000,000 dividend declared in 1997 was paid. 80 81 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Partners of Selkirk Cogen and MASSPOWER: We have audited the accompanying combined balance sheets of Selkirk Cogen Partners L.P. (a Delaware limited partnership) and MASSPOWER (a Massachusetts general partnership) as of December 31, 1997 and 1996, and the related statements of income, changes in partner's capital and cash flows for the years ended December 31, 1997, 1996 and 1995. These financial statements are the responsibility of the Partnerships' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Selkirk Cogen Partners L.P. and MASSPOWER as of December 31, 1997 and 1996, and the results of their operations and their cash flows for the years ended December 31, 1997, 1996 and 1995, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Washington, D.C. January 12, 1998 81 82 SELKIRK COGEN/MASSPOWER COMBINED BALANCE SHEETS AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996 (IN THOUSANDS) JUNE 30, DECEMBER 31, ----------- ------------------- 1998 1997 1996 ----------- -------- -------- (UNAUDITED) ASSETS CURRENT ASSETS: Cash and cash equivalents................................. $ 2,592 $ 8,164 $ 9,022 Restricted funds.......................................... 25,136 19,994 18,374 Accounts receivable....................................... 37,827 34,675 36,253 Inventories............................................... 9,440 9,205 8,635 Due from affiliates....................................... 59 14 40 Other current assets...................................... 711 530 664 -------- -------- -------- Total current assets.............................. 75,765 72,582 72,988 -------- -------- -------- PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION OF $91,995 (unaudited), $81,893 AND $61,627................................................... 493,217 503,304 523,776 DEFERRED CHARGES AND OTHER ASSETS: Deferred financing cost, net of accumulated amortization of $8,980 (unaudited), $8,057 and $6,248............... 14,950 15,873 17,682 Other assets.............................................. 6,949 6,944 5,157 Prepaid rent.............................................. 9,190 8,195 6,010 Long-term restricted funds................................ 24,491 21,494 20,446 -------- -------- -------- Total assets...................................... $624,562 $628,392 $646,059 ======== ======== ======== LIABILITIES AND PARTNERS' CAPITAL CURRENT LIABILITIES: Current portion of long-term debt......................... $ 9,478 $ 8,811 $ 6,630 Short-term debt........................................... 4,700 8,400 13,000 Accounts payable and accrued expenses..................... 19,770 24,678 25,122 Due to affiliated companies............................... 1,405 1,212 1,519 Accrued interest.......................................... 2,480 2,536 1,217 Customer advances......................................... -- -- 17 -------- -------- -------- Total current liabilities......................... 37,833 45,637 47,505 -------- -------- -------- COMMITMENTS AND CONTINGENCIES LONG-TERM DEBT, NET OF CURRENT MATURITIES................... 567,377 574,171 584,516 OTHER LIABILITIES........................................... 22,259 18,665 16,522 PARTNERS' CAPITAL........................................... (2,907) (10,081) (2,484) -------- -------- -------- Total liabilities and partners' capital........... $624,562 $628,392 $646,059 ======== ======== ======== The accompanying notes are an integral part of these financial statements. 82 83 SELKIRK COGEN/MASSPOWER COMBINED STATEMENTS OF INCOME FOR THE SIX MONTHS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS) SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31, --------------------------- ------------------------------ 1998 1997 1997 1996 1995 ------------ ------------ -------- -------- -------- (UNAUDITED) OPERATING REVENUES: Electric and steam.................... $138,404 $140,040 $279,344 $261,810 $244,659 Gas resale............................ 6,097 7,180 14,909 26,313 18,974 -------- -------- -------- -------- -------- Total operating revenues...... 144,501 147,220 294,253 288,123 263,633 -------- -------- -------- -------- -------- COST OF REVENUES: Fuel costs............................ 73,384 79,052 156,847 147,414 143,537 Operating and maintenance expenses.... 13,450 15,561 29,994 30,240 27,405 Ground lease.......................... 1,408 1,408 2,816 4,090 5,000 Depreciation.......................... 10,442 10,447 20,931 20,795 20,604 -------- -------- -------- -------- -------- Total cost of revenues........ 98,684 106,468 210,588 202,539 196,546 -------- -------- -------- -------- -------- GENERAL AND ADMINISTRATIVE EXPENSES.............................. 4,786 5,000 10,336 10,578 11,206 -------- -------- -------- -------- -------- Operating income.............. 41,031 35,752 73,329 75,006 55,881 INTEREST EXPENSE, NET................... 25,669 25,540 51,386 51,598 52,082 -------- -------- -------- -------- -------- Net income.................... $ 15,362 $ 10,212 $ 21,943 $ 23,408 $ 3,799 ======== ======== ======== ======== ======== The accompanying notes are an integral part of these financial statements. 83 84 SELKIRK COGEN/MASSPOWER COMBINED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL FOR THE SIX MONTHS ENDED JUNE 30, 1998 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS) GENERAL LIMITED PARTNERS PARTNERS TOTAL -------- -------- ------- BALANCE, DECEMBER 31, 1994.................................. $14,221 $ 24,539 $38,760 Distributions............................................. (5,599) (20,321) (25,920) Conversion and assignment of JMCSI Investors L.P. interest............................................... 4,411 (4,411) -- Net income................................................ 2,119 1,680 3,799 ------- -------- ------- BALANCE, DECEMBER 31, 1995.................................. 15,152 1,487 16,639 Distributions............................................. (7,379) (35,152) (42,531) Net income................................................ 8,380 15,028 23,408 ------- -------- ------- BALANCE, DECEMBER 31, 1996.................................. 16,153 (18,637) (2,484) Distributions............................................. (4,861) (24,679) (29,540) Net income................................................ 10,598 11,345 21,943 ------- -------- ------- BALANCE, DECEMBER 31, 1997.................................. 21,890 (31,971) (10,081) Distributions............................................. (4,897) (3,291) (8,188) Net income................................................ 8,919 6,443 15,362 ------- -------- ------- BALANCE, JUNE 30, 1998 (UNAUDITED).......................... $25,912 $(28,819) $(2,907) ======= ======== ======= The accompanying notes are an integral part of these financial statements. 84 85 SELKIRK COGEN/MASSPOWER COMBINED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 1998 (UNAUDITED) AND 1997 (UNAUDITED) AND THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995 (IN THOUSANDS) SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31, ------------------------- ------------------------------ 1998 1997 1997 1996 1995 --------- --------- -------- -------- -------- (UNAUDITED) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................... $ 15,362 $ 10,212 $ 21,943 $ 23,408 $ 3,799 Adjustments to reconcile net income to net cash provided by operating activities -- Depreciation............................... 10,442 10,447 20,931 20,795 20,604 Amortization of deferred financing activities............................... 583 586 1,170 1,173 1,130 Other...................................... 890 239 (472) (1,053) (268) Decrease (increase) in accounts receivable............................... (3,152) 414 1,728 1,309 (6,022) Decrease (increase) in inventory........... (236) (333) (570) (2,242) 233 Increase in other current assets........... (1,221) (1,077) (2,019) (5,314) (2) Decrease (increase) in accounts payable and accrued expenses......................... (5,663) (3,471) 1,006 4,232 (3,331) Decrease in other liabilities.............. 3,596 3,035 2,140 3,903 5,158 -------- -------- -------- -------- -------- Net cash provided by operating activities.......................... 20,601 20,052 45,857 46,211 21,301 -------- -------- -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures, net of proceeds........ (14) (101) 28 (2,973) (4,497) Other long-term assets -- escrow deposits.... (3,002) (1,851) (2,802) (424) 15,619 -------- -------- -------- -------- -------- Net cash (used in) provided by investing activities................ (3,016) (1,952) (2,774) (3,397) 11,122 -------- -------- -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Repayment of long-term debt.................. (6,127) (3,801) (8,164) (6,330) (3,998) (Repayment) proceeds from short-term debt, net........................................ (3,700) (4,000) (4,600) 4,900 2,100 Capital distributions........................ (8,188) (16,845) (29,540) (42,531) (25,920) Advances..................................... -- (17) (17) (136) (5,282) Financing costs.............................. -- -- -- -- (217) -------- -------- -------- -------- -------- Net cash used in financing activities.......................... (18,015) (24,663) (42,321) (44,097) (33,317) -------- -------- -------- -------- -------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.................................. (430) (6,563) 762 (1,283) (894) CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR... 28,158 27,396 27,396 28,679 29,573 -------- -------- -------- -------- -------- CASH AND CASH EQUIVALENTS, END OF YEAR......... $ 27,728 $ 20,833 $ 28,158 $ 27,396 $ 28,679 ======== ======== ======== ======== ======== SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid during the year for interest....... $ 26,539 $ 25,160 $ 51,820 $ 52,877 $ 56,555 ======== ======== ======== ======== ======== Purchase of inventory -- noncash............. $ -- $ -- $ -- $ 182 $ 3,800 ======== ======== ======== ======== ======== The accompanying notes are an integral part of these financial statements. 85 86 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 1997 (DOLLARS IN THOUSANDS) 1. ORGANIZATION AND BUSINESS ORGANIZATION Selkirk Cogen Partners, L.P. (Selkirk) was organized on December 15, 1989 as a Delaware limited partnership. Prior to the Partnership Agreement, the partners had a cost-sharing arrangement for costs incurred from the project's inception in October 1987. Selkirk was formed for the purpose of constructing, owning and operating a natural gas-fired combined-cycle cogeneration facility located on General Electric Company's (GE) property in Bethlehem, New York (the Facility). The Facility consists of one unit (Unit 1) with an electric generating capacity of approximately 79.9 megawatts (MW) and a second unit (Unit 2) with an electric generating capacity of approximately 265 MW. Unit 1 and Unit 2 have been designed to operate independently for electrical generation, while thermally integrated for steam generation, thereby optimizing efficiencies in the combined performance of the Facility. Selkirk received construction financing for Unit 1 in June 1990 and commercial operations commenced on April 17, 1992. Unit 2 obtained construction financing in October 1992 and commercial operations commenced September 1, 1994. Both units are fueled by Canadian natural gas purchased under firm 15-year natural gas supply contracts (extendible to 20 years upon satisfaction of certain conditions). Unit 1 is selling at least 79.9 MW of electric capacity and associated energy to Niagara Mohawk Power Corporation (NIMO) under a 20-year contract, and Unit 2 is selling 265 MW of electric capacity and associated energy to Consolidated Edison Company of New York (ConEd) under a 20-year contract. Also, Selkirk makes excess gas layoff sales during periods when Units 1 and 2 are not operating at full capacity (see Note 4). Historical natural gas resale prices have resulted in significant gas resale margins for Selkirk. Unit 1 of Selkirk is currently certified as a qualifying facility (QF) under the Public Utility Regulatory Policy Act of 1978, as amended (PURPA). Accordingly, the prices charged for the sale of electricity and steam are not regulated. When Unit 2 commenced operations, Selkirk was no longer qualified by the State of New York but continues to be certified by the Federal Energy Regulation Commission (FERC) as a QF. However, this is not expected to have a material impact on Selkirk's financial position or operations. Certain fuel transportation agreements entered into by Selkirk are subject to regulation on the federal and provincial levels in Canada. Selkirk has obtained all material Canadian governmental permits and authorizations required for operation. MASSPOWER is a Massachusetts General Partnership formed under the terms of a Joint Venture Agreement dated August 8, 1989 and as amended and restated on August 14, 1991. The partnership consists of five general partners and is managed by a committee comprised of one representative from each general partner. MASSPOWER has no employees, and the administration and operation of the project are arranged under various contractual agreements (see Note 4). MASSPOWER was formed to construct, own and operate a gas-fired combined cycle cogeneration facility located on the property of Solutia Company (Solutia) in Springfield, Massachusetts. The Facility's average net capacity is approximately 240 MW. The Facility is fueled by Canadian natural gas and revaporized liquefied natural gas (LNG), which are both purchased under firm long-term contracts (see Note 5). The Facility's electrical generation is sold to five utility companies under long-term power purchase agreements (see Note 5). The steam generation is sold to Solutia under a 20-year stream purchase agreement (see Note 5). MASSPOWER also enters into short-term (less than six months) contracts for sale of a portion of its electrical generation capability. MASSPOWER is currently certified by the Federal Energy Regulatory Commission as a QF under the PURPA. Accordingly, the prices charged for the sale of electricity and steam are not regulated. However, MASSPOWER and certain agreements entered into by MASSPOWER are subject to regulation by various 86 87 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) federal, state and Canadian authorities. The criteria for QF certification include requirements that a minimum of 5% of the Facility's output be useful thermal energy, that the Facility achieve at least a specified ratio of energy output to energy input, and that the ownership of the Facility by electric utilities be no greater than 50%. Construction and term financing was obtained on August 15, 1991, and commercial operations commenced on September 1, 1993. PARTNERS' CAPITAL The general and limited partners of Selkirk, along with their respective equity interests, are as follows: INTEREST -------------------- GENERAL PARTNERS AFFILIATE OF PREFERRED ORIGINAL - ---------------- ------------ --------- -------- JMC Selkirk, Inc. J. Makowski Company, Inc. .09% 1.00% (JMC) Cogen Technologies Selkirk GP, Inc. Cogen Technologies, Inc. 1.00% --% INTEREST -------------------- LIMITED PARTNERS AFFILIATE OF PREFERRED ORIGINAL - ---------------- ------------ --------- -------- JMC Selkirk, Inc. J. Makowski Company, Inc. 1.95% 21.40% Pentagen Investors, L.P. J. Makowski Company, Inc. 5.25% 57.60% EI Selkirk, Inc. GPU International, Inc. 13.55% 20.00% Cogen Technologies Selkirk L.P., Inc. Cogen Technologies, Inc. 78.16% --% Under the terms of the Selkirk amended partnership agreement, cash available is distributed 99% to the partners in accordance with their respective equity interest (preferred equity) and 1% is allocated based on the original ownership structure between JMC affiliates and GPU International, Inc. (GPUI). Any additional funds available after the preferred distribution are distributed 99% to the initial equity holders and 1% to the preferred equity holders. Subsequent to the eighteenth anniversary of Unit 1's commercial operations or the date on which all the preferred partners achieve a specified return, distributions will be made in accordance with the residual interest: JMC affiliates at 64.8%, GPUI at 17.7% and Cogen Technologies, Inc. at 17.5%. The five general partners of MASSPOWER, along with their respective equity interests, are as follows: EQUITY PARTNER AFFILIATE OF INTEREST - ------- ------------ -------- MASSPOWER, Inc. PG&E Enterprises 30.0% Springfield Generating Company, L.P. PG&E Enterprises 17.5% MP Cogen, Inc. General Electric Company 17.5% Bay State Energy Development, Inc. Energy Investors Funds 17.5% EPEC Independent Power I Company El Paso Energy 17.5% The net profits or losses and cash distributions of MASSPOWER are allocated to the partners based on their respective equity interests. 87 88 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The detail of partners capital, as reflected in the accompanying combined balance sheets as of December 31, 1997 and 1996, is as follows: 1997 1996 -------- -------- Selkirk -- General Partners.......................................... $ (311) $ (173) Limited Partners.......................................... (31,971) (18,637) MASSPOWER -- General Partners.......................................... 22,201 16,326 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The accompanying combined financial statements of Selkirk Cogen Partners, L.P. and MASSPOWER (collectively the Partnerships) are presented on a combined basis due to the common management of the operating facilities of the Partnerships. As such, all interpartnership transactions have been eliminated in combination. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. INTERIM FINANCIAL STATEMENTS The combined financial statements as of June 30, 1998 and for the periods ended June 30, 1998 and 1997 are unaudited and are presented pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the accompanying combined financial statements reflect all adjustments (which are of normal recurring nature) necessary to present fairly the financial position and results of operations and cash flows for the interim periods, but are not necessarily indicative of the results of operations for a full fiscal year. CASH AND CASH EQUIVALENTS For the purpose of reporting cash flows, cash equivalents include short-term investments with maturities of three months or less. RESTRICTED FUNDS AND LONG-TERM RESTRICTED FUNDS The Partnerships are required to maintain cash reserve accounts for maintenance costs and debt service requirements as part of their credit agreement with a bank. Certain of the restricted funds are associated with transactions or events that are applicable to periods beyond the current accounting period and are, therefore, classified as long-term. All other funds are classified as current assets. INVENTORIES Inventories are stated at the lower of cost or market. Costs for materials, supplies and oil inventories are determined using the average unit cost method. 88 89 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment are stated at cost. Depreciation is calculated on a straight-line basis over the estimated useful lives of the assets as follows: Cogeneration facility....................................... 30 years Computer systems............................................ 7 years Office equipment............................................ 5 years Furniture, fixtures and other equipment..................... 10 years DEFERRED FINANCING COSTS Deferred financing costs represent the costs incurred to obtain project financing and are amortized using the effective interest rate method over the estimated life of the loans. OTHER ASSETS Included in other assets is a $525 and $491 long-term deposit with Northeast Utilities Service Company (NUSCO) for long-term firm transmission service as of December 31, 1997 and 1996, respectively, and $6,059 and $4,666 in an escrow account to fulfill a potential repayment obligation under the power purchase agreement with Boston Edison Company (BECo) as of December 31, 1997 and 1996, respectively. REAL ESTATE TAXES Real estate tax payments made under the Partnerships' payment in lieu of taxes (PILOT) agreements are recognized on a straight-line basis over the term of the agreement. INCOME TAXES Income taxes have not been recorded in the accompanying combined financial statements because such taxes, if any, are the responsibility of the partners of Selkirk and MASSPOWER. PLANNED MAJOR OVERHAULS Periodic major overhauls of the gas and steam turbines will be necessary to maintain the Facilities' operating capacity. A maintenance and repairs reserve is recorded by Selkirk based on scheduled major maintenance plans for 20 years. MASSPOWER will be conducting its next major overhaul of a gas turbine engine during 1998 at an estimated cost of $1,500. MASSPOWER follows the direct expensing method for these major overhaul costs. Deterioration in existing parts and required work scope could cause the estimates to change in the near term. CURRENCY AND INTEREST RATE SWAPS In connection with its asset and liability management policies, the Partnerships have entered into foreign currency and interest rate swap agreements. Gains and losses on currency exchange contracts are deferred as hedges of firmly committed transactions and recognized in income in the same period that the hedged transactions are realized. In the unlikely event that the underlying transaction terminates, the deferred gains and losses on the associated swap agreement will be recorded in the income statement. REVENUE RECOGNITION Revenues for the sale of electricity and steam are recorded based on monthly output delivered as specified under contractual terms. Revenues for the sale of excess gas are recorded in the month sold. 89 90 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) 3. DEBT FINANCING SELKIRK On May 9, 1994, the Selkirk Funding Corporation, a wholly owned subsidiary of Selkirk Cogen, issued an aggregate of $392,000 in bonds, of which a portion was used to refinance the outstanding indebtedness of the Partnerships. The bonds consist of $165,000, which matures on December 26, 2007 at an interest rate of 8.65% with principal and interest payable semiannually on June 26 and December 26 of each year with principal payments commencing June 26, 1996, and $227,000, which matures on June 26, 2012 at an interest rate of 8.98% with principal and interest payable semiannually on June 26 and December 26 of each year with principal payments commencing December 26, 2007. The scheduled principal payments on the bonds are as follows: YEAR AMOUNT - ---- -------- 1998........................................................ $ 3,298 1999........................................................ 4,822 2000........................................................ 7,307 2001........................................................ 11,062 2002........................................................ 13,529 Thereafter.................................................. 349,235 The loans are secured by liens on, and security interests in, substantially all of the assets of Selkirk Cogen. These loans are nonrecourse to the individual partners. The trust indenture restricts the ability of Selkirk to make distributions to the partners under certain circumstances. In connection with the bonds, the Partnerships are required to maintain certain restricted funds to finance future debt, interest and maintenance payments. These funds have been included in restricted funds and long-term restricted funds in the accompanying combined balance sheets. In 1994, Selkirk entered into a combined working capital and bank reimbursement agreement (Credit Agreement). The Credit Agreement has a maximum available amount of $23,471 to be used by Selkirk for required letters of credit related to various project contracts and working capital purposes. The maximum amount available under the Credit Agreement for working capital purposes is $5,000. No amounts have been drawn under the Credit Agreement. MASSPOWER The MASSPOWER loan payable represents borrowings under a $240,000 construction and term credit facility from a syndicate of banks (the Banks) dated August 15, 1991. The credit facility consists of $210,000 of original principal term loan, $15,000 available for letters of credit and $15,000 available for working capital loans. TERM LOANS The term loans bear interest at the option of MASSPOWER at either 1% through September 14, 1997 and 1 3/8% thereafter, plus the greater of the prime rate or the Federal Funds rate plus 3/8%; or 1 1/2% through September 14, 1997 and 1 7/8% thereafter over the certificate of deposit rate; or 1 3/8% through September 14, 1997 and 1 3/4% thereafter over the LIBOR rate. The credit facility is secured by substantially all of the assets of the Facility. A commitment fee is payable on the letter of credit facility semiannually based on the daily average unused letter-of-credit commitment amount at a rate of 1/4% per annum, and an issuance fee is payable semiannually on the average daily stated amount of all outstanding letters of credit at a rate of 1 1/4% per annum. 90 91 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The term credit facility lenders have no recourse to any general partner and do not benefit from a debt guarantee by any general partner. The credit agreement contains certain covenants, including restrictions on the distribution of cash or property to the partners, the incurrence of additional indebtedness, the creation of liens, the sale of assets, the creation of contingent obligations and the amendment of certain project contracts. At December 31, 1997 and 1996, term loans totaled $193,729 and $199,727, respectively. The effective interest rate on the loans without giving effect to the differences between amounts received and paid under MASSPOWER's interest rate swap agreements was 7.29%, 7.06% and 7.61% for the years ended December 31, 1997, 1996 and 1995, respectively. In addition, approximately $15,000,000 in letters of credit were issued as security deposits under certain power sales agreements and certain other project contracts as of December 31, 1997, 1996 and 1995 (see Note 4). The letters of credit expire at various times through the year 2014. The scheduled principal payments on the term loans are as follows: 1998........................................................ $ 5,513 1999........................................................ 7,350 2000........................................................ 11,025 2001........................................................ 13,125 2002........................................................ 15,750 Thereafter.................................................. 140,966 SHORT-TERM DEBT As part of the credit facility, MASSPOWER has a $15,000 line of credit available for working capital loans. Working capital loans bear interest at the rate of 5/8% plus the greater of the prime rate or the federal funds rate plus 3/8%. A commitment fee is payable semiannually on the daily average unused commitment amount at a rate of 3/8% per annum. At December 31, 1997 and 1996, $8,400 and $13,000, respectively, were outstanding under the working capital line of credit. The effective interest rates on these borrowings were 9.135%, 9.0% and 9.42% for the years ended December 31, 1997, 1996 and 1995, respectively. INTERCREDITOR AND COLLATERAL AGENCY AGREEMENTS In August 1991, MASSPOWER entered into several intercreditor and security arrangements with the Chase Manhattan Bank, N.A. (on behalf of itself as agent for the Banks), State Street Bank and Trust Company (as the collateral agent), Western Massachusetts Electric Company (WMECO), Commonwealth Electric Company (ComElec) (WMECO and ComElec, together, the Secured Power Purchasers) and Solutia. The credit facility is secured by a first priority lien and security interest granted by MASSPOWER in favor of the collateral agent. The intercreditor agreements have created a procedure for restructuring or selling the Facility in the event the Facility is unable to perform in accordance with its contracts and/or the credit facility. The First Intercreditor and Collateral Agency Agreement includes a First Mortgage, a Second Mortgage, an Equipment Security Agreement, and a Power Sales Security Agreement. These agreements subject the leased property, equipment and fixtures on the property, the Power Sales Agreements with the Secured Power Purchasers and related accounts receivable, to liens in favor of the collateral agent to benefit the Banks, and subordinately, to benefit the Secured Power Purchasers. Solutia subordinately benefits under the Equipment Security Agreement. 91 92 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The remaining project contracts and all other assets of MASSPOWER, except equipment, are subject to the lien and security interest granted under the Second Intercreditor and Collateral Agency Agreement in favor of the collateral agent to benefit the Banks and WMECO. 4. INTEREST AND CURRENCY SWAP AGREEMENTS On June 20, 1990 and October 29, 1992, Selkirk entered into currency exchange agreements to hedge against future exchange rate fluctuations, which could result in additional costs incurred under fuel transportation agreements, which are denominated in Canadian dollars. The June 1990 agreement relates to Unit 1 under which Selkirk exchanges approximately $368 U.S. dollars for $458 Canadian dollars on a monthly basis commencing on December 25, 1992 and terminating December 25, 2002. The October 1992 agreement relates to Unit 2 under which Selkirk exchanges approximately $1,044 U.S. dollars for $1,300 Canadian dollars on a monthly basis commencing on May 25, 1995 and terminating on December 25, 2004. On August 22, 1991, MASSPOWER entered into an interest rate exchange agreement, as amended on December 1, 1993, effective from January 18, 1994 to January 15, 2004 at a fixed rate of 8.925% for monthly predetermined notional amounts as scheduled at the time of execution of this agreement. For the years ended December 31, 1997, 1996 and 1995, the weighted average floating rate at which MASSPOWER received interest payments was 5.72%, 5.65% and 6.05%, respectively. The notional amount of debt for which interest rate exchange has been entered into under this agreement is $105,000,000 at December 31, 1997, 1996 and 1995. On January 27, 1994, MASSPOWER entered into an additional interest rate exchange agreement with a bank. The agreement will be effective from January 16, 1996 to January 15, 2002 for predetermined interest rates and notional amounts as scheduled at the time of execution of the agreement. For the years ended December 31, 1997 and 1996, the weighted average floating rate at which MASSPOWER received interest payments was 5.72% and 5.65% respectively. The notional amount of debt for which interest rate exchange agreements have been entered into under this agreement at December 31, 1997 and 1996 is $50,000 and $55,000, respectively. On August 22, 1991, MASSPOWER entered into a currency exchange agreement with a bank to mitigate the currency exchange rate risks associated with MASSPOWER's Canadian fuel transportation costs (see Note 4), which are denominated in Canadian dollars. The currency exchange agreement commenced on February 20, 1994 and terminates on February 20, 2004. MASSPOWER will exchange U.S. dollars for Canadian dollars at an exchange rate of 1.20 Canadian dollars for each U.S. dollar on amounts scheduled at the time of the execution of the agreement. On October 6, 1994, MASSPOWER entered into two other currency exchange agreements with different banks to further mitigate its currency exchange risks associated with its Canadian fuel transportation costs. Both agreements commenced on October 20, 1994 and terminate on February 20, 2004. MASSPOWER will exchange U.S. dollars for Canadian dollars at various exchange rates on $CDN 400 per month as scheduled at the time of the execution of the agreement. Gross deferred unrealized gains from hedging firm purchase commitments were $787, $717 and $579, as of December 31, 1997, 1996 and 1995, respectively, and are expected to be realized by the end of the agreements. The monthly notional amount of transportation costs for which currency exchange agreements have been entered into is $CDN 1,301 at December 31, 1997 and 1996 and $CDN 1,450 at December 31, 1995. In the event of default by any of the bank counterparties to the interest rate and currency exchange agreements, the Partnerships could be exposed to interest rate and currency exchange rate risks. The Partnerships do not anticipate nonperformance by any of the counterparties. 92 93 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) The Partnerships have only the above-mentioned limited involvement with derivative financial instruments and does not use them for trading purposes. They are used to manage well-defined interest rate and commodity price risks (see Note 7 for fair value of financial instruments). 5. COMMITMENTS AND AGREEMENTS Selkirk and MASSPOWER have entered into respective site lease, property tax, fuel supply and transportation, power sales, steam sales, electric interconnection and transmission, operations and maintenance, water supply and project administrative agency agreements. In connection with the construction and operation of these facilities, Selkirk and MASSPOWER are obligated under the following agreements: SITE LEASE Selkirk has entered into an agreement with General Electric to lease the property on which that facility is located. The amended lease term expires on the twentieth anniversary of the commercial operations date of Unit 2 and is renewable for the greater of five years or until termination of any power sales contract, to a maximum of 20 years. The lease may be terminated by Selkirk under certain circumstances with the appropriate written notice during the initial term. Annual rent payments under this agreement are $1,000. MASSPOWER has entered into an operating lease agreement, as amended in July 1991, to lease the property on which the Facility is located from Solutia. The original lease agreement was amended in 1996. The amendment gives MASSPOWER the right to extend the lease an additional 15 years. The amended lease term expires in 2028. At the end of the term, the lease may be renewed, or if not renewed, Solutia has the right to purchase the Facility at a fair market value or require that the site be restored to its original condition at the partnership's expense. The lease provides for annual rent of $5,000. In addition, Solutia has agreed to supply MASSPOWER with wastewater equalization and cooling water supply for 20 years or cancellation of the site lease agreement under a separate services agreement. Lease expense for MASSPOWER has been recorded ratably over the term of the amended lease with the difference between the lease expense and lease payments recorded as prepaid rent. FUEL SUPPLY AND TRANSPORTATION PURCHASE AGREEMENTS Selkirk has entered into a firm natural gas supply agreement, as amended, with Paramount Resources Ltd., a Canadian corporation, for Unit 1. The agreement has an initial term of 15 years, which began in November 1992, with an option to extend for an additional five years upon satisfaction of certain conditions. Selkirk has entered into firm natural gas supply agreements with various suppliers for Unit 2. The agreements have an initial term of 15 years, which began November 1, 1994, and an option to extend for an additional five-year term upon satisfaction of certain conditions. Each Unit 2 gas supply contract requires that Selkirk purchase a minimum of 75% of the maximum annual contract volumes each year. If the partnership fails to take this minimum quantity, then the shortfall amount between the minimum required volumes and the actual nominations must be made up in the following year(s). The partnership is allowed up to two years under these contracts, during which time the partnership may make up any shortfall. If the partnership does not make up the shortfall within these periods, then the suppliers have a right to reduce the maximum daily contract quantity by the shortfall. The partnership purchased approximately $38,279 and $35,191 in gas from these suppliers for the years ended December 31, 1997 and 1996, respectively. Selkirk has entered three 20-year agreements for firm fuel transportation service to supply Unit 1 commencing November 1, 1992. In accordance with one of these agreements, Selkirk posted a letter of credit in the amount of approximately $586 in October 1992. 93 94 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Selkirk has entered into three agreements for firm fuel transportation service for Unit 2. The agreements commenced in November 1994 and have terms of 20 years. Upon the execution of the transportation agreement with one transporter, the various fuel suppliers posted letters of credit totaling approximately $10,007,000 Canadian dollars for the benefit of the transporter on behalf of Selkirk, which was subsequently reduced to approximately $9,814 Canadian dollars in February 1997. Selkirk will reimburse all costs related to obtaining and maintaining the letters of credit. Selkirk also posted two letters of credit related to the remaining two firm fuel transportation agreements for approximately $796 and $2,090. MASSPOWER and Granite State Gas Transmission, Inc. (Granite State), a subsidiary of Bay State Gas Company (Bay State), designated Orchard Gas Corporation (Orchard Gas), an affiliate of J. Makowski Company, Inc. (JMC), as their agent to purchase Canadian natural gas and to enter into gas transportation contracts on their behalf for one half of the Facility's annual fuel supply. Orchard Gas entered into an 18.5-year Gas Purchase Contract with ProGas Limited (ProGas), a Canadian corporation. Orchard Gas also entered into a 20-year Firm Gas Transportation Agreement with Iroquois Gas Transmission System, L.P., and a 20-year Firm Gas Transportation Contract with Tennessee Gas Pipeline Company. Local transportation is provided by Bay State through a 20-year transportation agreement with MASSPOWER. MASSPOWER entered into a gas supply contract for the purchase of revaporized LNG from Distrigas of Massachusetts Corporation for a term of 20 years from the date of commercial operations for the remaining one-half of the Facility's gas supply. Additionally, MASSPOWER entered into two gas supply contracts with Bay State to supply MASSPOWER with natural gas in the event of nonperformance by MASSPOWER's primary gas supplier. Under the first contract, Bay State will provide a 305-day sales service contract. Under the second contract, Bay State will provide an interruptible sales service contract to facilitate the purchase of incremental gas supplies. MASSPOWER also entered into a Gas Peaking Service Agreement with Bay State for any 20 days during the period from November through March. MASSPOWER and Granite State entered into a release gas agreement whereby MASSPOWER agreed to release and Granite State agreed to accept the difference between the daily amount of gas required for use in the facility and 75% of the daily contracted ProGas supply. ENERGY SALES AGREEMENT -- STEAM In February 1990, Selkirk entered into a steam sales agreement for Unit 1, as amended, with GE for an initial term of 20 years, effective from the date of commercial operations. On October 21, 1992, Selkirk and GE entered into a new steam sales agreement, as amended, with a term of 20 years from the commercial operations date of Unit 2 and may be extended under certain circumstances. The Unit 1 steam sales agreement terminated upon the commercial operations of Unit 2. Until Unit 2 achieved commercial operations, GE had agreed to forego (subject to later repayment plus interest) the discount on a certain quantity of steam supplied by Selkirk during a quarter to the extent necessary for Selkirk to maintain a quarterly debt service coverage ratio of 1.2 to 1, and the advances, with interest, are repayable to the extent Selkirk's quarterly debt service coverage ratio exceeds 1.3 to 1. Under this agreement, Selkirk had invoiced and received from GE approximately $5,022. In April 1995, the partnership paid off the outstanding principal amount and approximately 75% of the associated accrued interest. The partnership paid the remaining accrued interest in January 1996 and February 1997. GE is obligated under the steam sales agreement to purchase the minimum quantities of steam necessary for the Facility to maintain its QF status. In the event that GE were to fail to purchase and take this minimum 94 95 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) quantity, the partnership could acquire title to the Facility site, terminating the lease agreement, at no cost to the partnership. The agreement provides GE the right of first refusal to purchase the Facility, subject to certain pricing considerations. Additionally, GE has the right to purchase the boiler facility that produces the steam at a mutually agreed-upon price if and when the steam sales agreement is terminated. The steam sales agreement may be terminated by Selkirk with one year's written notice if either the NIMO or ConEd power sales agreement is terminated. It may also be terminated by GE with two years' written notice if GE's plant no longer has a requirement for steam. In July 1990, MASSPOWER entered into an Energy Purchase Agreement (EPA) with Solutia. Under the terms of the EPA, MASSPOWER is obligated to sell Solutia steam for the period of 20 years from the date of commercial operations. ENERGY/POWER SALES AGREEMENTS -- ELECTRICITY In December 1987, Selkirk entered into a power sales agreement, as amended, with NIMO for the sale of electricity for an initial term of 20 years commencing on the date of commercial operations, April 17, 1992. The agreement may be terminated upon two years' written notice to NIMO and payment of a termination fee or upon the loss of Selkirk's status as a QF. In April 1994, the power sales agreement with NIMO was amended and pursuant to this amended agreement Selkirk paid NIMO $1,250,000 as a consent fee from the proceeds of the bond offering. In addition, Selkirk posted a letter of credit for approximately $15,000 under the Credit Agreement. On October 6, 1996, NIMO filed its "PowerChoice" proposal with the New York State Public Service Commission (NYPSC). On October 12, 1995, NIMO filed a Report on Form 8-K with the Securities and Exchange Commission (the Commission) explaining the PowerChoice proposal (the PowerChoice Statement). In the PowerChoice Statement, NIMO describes a number of related proposals to restructure the utility's business, including the reorganization of its assets and the renegotiation of its contracts with generators which, like Selkirk, are not regulated as utilities (nonutility generators). On July 10, 1997, NIMO filed a Report on Form 8-K with the Commission stating that NIMO had entered into a Master Restructuring Agreement (MRA) pursuant to which it and the 29 independent power producers that had signed the MRA proposed to terminate, restate or amend their respective power sales agreements. On October 17, 1997, NIMO filed a Report on Form 8-K with the Commission stating that on October 11, 1997, NIMO filed its Power Choice settlement with the NYPSC which incorporates the terms of the MRA. On February 24, 1998, the NYPSC approved NIMO's Power Choice settlement proposal, which includes the implementation of the MRA. The consideration for the independent power sellers' agreement varies by party and may consist of cash, short term notes, shares of NIMO's common stock or certain swap contracts. Among the contracts proposed to be restructured is the NIMO power sales agreement for the electric output of Unit 1. Pursuant to the MRA and subject to implementation as described below, the parties proposed to restructure the NIMO power sales agreement to provide for the sale of electricity by Selkirk pursuant to a predetermined schedule of output at a price based on certain indices for a period of 10 years in lieu of the delivery and price provisions of the NIMO power sales agreement as currently in effect. Selkirk anticipates that if and when a restructured power sales agreement goes into effect, NIMO will relinquish its right to direct dispatch of Unit 1, the electrical output of Unit 1 will be sold to NIMO and other purchasers based on market conditions then in effect, and Selkirk will receive certain fixed payments from NIMO under the restructured power sales agreement and other payments under the MRA. The details of the physical delivery and pricing arrangements are subject to final agreement with NIMO, and possible modifications to other Selkirk contracts for Unit 1 continue to be the subject of extensive 95 96 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) negotiations. Implementation of the MRA is subject to a number of significant conditions, including, without limitation, NIMO and Selkirk negotiating the restructured Unit 1 power sales agreement, the receipt of all regulatory approvals, the receipt of all consents by third parties necessary for the transaction contemplated by the MRA (including satisfying certain standards under Selkirk's trust indenture relating to the absence of material adverse changes or receiving any required approval of bondholders or other creditors), Selkirk's entering into new third-party arrangements that will enable Selkirk to restructure its project on a reasonably satisfactory economic basis, and the receipt by NIMO and Selkirk of all necessary approvals from their respective boards of directors, shareholders and partners. Should NIMO and Selkirk satisfy all of the conditions to effectuating the transactions contemplated by the MRA with respect to Selkirk, NIMO may nevertheless terminate the MRA if NIMO determines that as a result of the failure to satisfy the conditions of the MRA by other independent power producers the benefits anticipated to be received by NIMO pursuant to the MRA have been materially and adversely affected. Further, final implementation of the MRA is conditioned upon NIMO's successful completion of financing required to fund certain of its payment obligations under agreements to implement the MRA. Selkirk, as a party to the MRA, is committed to negotiate with NIMO and other parties to reach agreement on contractual arrangements required to restructure the NIMO power sales agreement pursuant to the MRA; however, Selkirk expresses no opinion with respect to the likelihood that all of the conditions to implementation of the MRA will be met. Further, Selkirk expresses no opinion with respect to the viability of NIMO's proposed alternatives should the implementation of the MRA not be completed, such as NIMO's proposal in the context of the Power Choice Statement to take possession of independent power projects through the power of eminent domain and to thereafter sell such projects or NIMO's position that it has not ruled out the ultimate possibility of a filing for restructuring under Chapter 11 of the U.S. Bankruptcy Code as set forth in the Power Choice Statement. Nevertheless, in the absence of agreement on a definitive restructured power sales agreement, Selkirk continues to believe that the NIMO power sales agreement is a valid and binding contract with NIMO. Given the uncertainties with respect to such implementation, Selkirk is unable to determine what effect, if any, the restructured power sales agreement or the Power Choice proposal will have on Selkirk, its business or net operating revenues. For the year ended December 31, 1997, electric sales to NIMO accounted for approximately 19.3% of total project revenues. Previously, in connection with NIMO's March 10, 1997 announcement of the agreement in principle, Standard & Poor's placed the bonds on creditwatch "with negative implications," based in part on its analysis of the current reports on Form 8-K filed in March 1997 by NIMO and Selkirk, respectively, and its belief that the restructuring has the potential to erode cash flow coverage derived from long-term contracts supporting the bonds. To date, Standard & Poor's has not changed its outlook on the bonds. Additionally, as of the date of this report, Moody's Investors Service has not changed its rating or its previous "negative outlook" on the bonds as a result of the developments. Selkirk has also entered into a power sales agreement with ConEd for the sale of electricity for an initial term of 20 years commencing on September 1, 1994, the date of Unit 2 commercial operations. The contract is extendible under certain circumstances. The power sales agreements with NIMO and ConEd each provide the purchasing utility with the contractual right to schedule the related Unit for dispatch on a daily basis at full capability, partial capability or off-line. Each purchasing utility's scheduling decisions are required to be based in part on economic criteria which, pursuant to the governing rules of the New York Power Pool, take into account the variable cost of the electricity to be delivered. Certain payments under these agreements are unaffected by levels of dispatch. However, certain payments may be rebated or reduced to NIMO and ConEd if Selkirk does not maintain a minimum availability level. ConEd, by a letter dated September 19, 1994, claimed the right to acquire that portion of Unit 2's natural gas supply not used in operating Unit 2 (the excess gas), when Unit 2 is dispatched off-line or at less than full 96 97 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) capability. The ConEd power sales agreement contains no express language granting ConEd any rights to such excess gas and the partnership has stated to ConEd that claims to excess gas are without merit. To date, ConEd has paid all amounts invoiced by the partnership in accordance with the ConEd power purchase agreement. If ConEd were to prevail in its claim to Unit 2's excess natural gas volumes, Selkirk would lose its ability to engage in layoff sales of such volumes at favorable prices relative to their costs, and thus Selkirk's cash flows from gas resale activities would also be materially and adversely affected. Selkirk is unable to determine the outcome of this uncertainty. In August 1992, NIMO filed a petition requesting the NYPSC to authorize NIMO to curtail purchases from, and avoid payment obligations to, nonutility generators, including QFs such as the Facility, during certain periods. NIMO claimed that such curtailment would be consistent with PURPA, and the regulations promulgated thereunder, which contemplate utilities' curtailing purchases from QFs under certain circumstances. In October 1992, the NYPSC initiated a proceeding to investigate whether conditions existed justifying the exercise of the PURPA curtailment rights and, if so, to determine the procedures for implementing PURPA curtailment rights. ConEd also filed a petition in this proceeding seeking to implement PURPA curtailment rights during certain periods. An administrative law judge appointed by the NYPSC held hearings during the spring of 1993; however, his opinion was never released. On August 30, 1996, the NYPSC reopened the curtailment proceedings and directed an administrative law judge to prepare a recommended decision under an abbreviated deadline. On March 18, 1998, the NYPSC announced that an order instituting a curtailment policy would be forthcoming; however, a written order has not yet been issued. Selkirk expects that any agreement that it enters into with NIMO to implement the MRA will waive NIMO's right, if any, to curtail purchases from Selkirk. In any event, Selkirk has taken the position in this proceeding that it should not be subject to curtailment as a result of this proceeding, even if the NYPSC grants NIMO and ConEd some measure of generic curtailment rights. Selkirk's position is based in part on the fact that neither NIMO nor ConEd bargained for an express curtailment right in its power sales agreement and Selkirk agreed to permit NIMO and ConEd to direct the dispatch of the relevant Unit. Nevertheless, both NIMO and ConEd have refused to expressly waive their claimed curtailment rights against dispatchable facilities and have not agreed to exempt the Facility from curtailment, notwithstanding the absence of contractual language in the power sales agreements granting the utilities this right. If NIMO and ConEd were to receive NYPSC authorization to curtail power purchases from QFs, including dispatchable facilities, they may seek to implement curtailment with respect to Selkirk by avoiding not only energy payments but also capacity payments during periods in which the Facility is curtailed. Such a reduction in energy payments and capacity payments could materially and adversely affect Selkirk's net operating revenues. MASSPOWER has entered into long-term "take-and-pay" capacity and energy sales contracts with Massachusetts Municipal Wholesale Electric Company for 20 years, ComElec (Commonwealth I) for 15 years, ComElec (Commonwealth II) for 20 years, WMECO for 15 years and BECo for 20 years. These contracts account for 98% and 95% of the Facility's net stated capacity for the Summer and Winter period, respectively. The pricing methods for these contracts vary, but in general, are based on variable costs with inflation and other escalators, plus fixed amounts with annual escalation adjustments. In addition, MASSPOWER has entered into a 20-year energy-only contract with Consolidated Edison Company of New York, Inc. MASSPOWER has also entered into short-term sales agreements with various other parties. ELECTRIC TRANSMISSION AND INTERCONNECTION AGREEMENTS Selkirk constructed an interconnection facility to transfer power from Unit 1 to NIMO and transferred title of the facility to NIMO. Selkirk has agreed to reimburse NIMO $150 annually for the operation and 97 98 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) maintenance of the facility. The term of the agreement is for 20 years from the commercial operations date of Unit 1 and may be extended if the power sales agreement with NIMO is extended. In December 1990, Selkirk entered into a 20-year firm interruptible transmission agreement with NIMO, as amended, to transmit power from Unit 2 to ConEd, beginning with commercial operations. In connection with this agreement, Selkirk constructed an interconnection facility and transferred title to NIMO in 1995. Under the terms of this agreement, Selkirk will reimburse NIMO $450 annually for the maintenance of the facility. There are three transmission service agreements associated with transmitting power from the MASSPOWER facility. MASSPOWER entered into a firm service agreement with NUSCO to allow transmission of energy through the NUSCO system to all power purchasers and a non-firm transmission agreement to provide additional transmission capabilities. MASSPOWER also entered into an agreement with Montaup Electric Company (Montaup) to allow for transmission of energy from Montaup's interconnection with NUSCO to BECo, Commonwealth I and Commonwealth II. In March of 1997, MASSPOWER signed a Memorandum of Understanding and Settlement Agreement (Agreement) with Northeast Utilities Service Company (NU) and with Montaup. The Agreements are intended to provide for certain rights and obligations of the parties with respect to the Transmission Service Agreements with NU and Montaup under and in light of the Restated New England Power Pool Agreement (NEPOOL Agreement), filed with the Federal Energy Regulatory Commission on December 31, 1996, which filing includes a NEPOOL Open Access Transmission Tariff. These Agreements provide for firm transmission rates to be set as $14 per kilowatt-year and $8 per kilowatt-year for NU and Montaup, respectively. These Agreements are awaiting FERC approval, which is anticipated to occur in early 1998. MASSPOWER agreed to construct certain interconnection facilities to enable the Facility to interconnect with the NUSCO system. The costs of these facilities are included in property, plant and equipment in the accompanying combined financial statements. Under the terms of the interconnection agreement with WMECO, ownership of these facilities was transferred, without consideration, to WMECO after energization of the Facility. During 1997, 1996 and 1995, MASSPOWER reimbursed WMECO $133, $122 and $133, respectively, for the operation and maintenance costs of these facilities under a service agreement. PROPERTY TAXES In October 1992, Selkirk entered into a PILOT agreement with the Town of Bethlehem Industrial Development Agency, a corporate governmental agency, which exempts Selkirk from all property taxes, except for special assessments. The agreement commenced on January 1, 1993 and terminates on December 31, 2012. MASSPOWER has entered into an agreement with the City of Springfield, Massachusetts, providing for payments in lieu of property taxes. Payments are due twice per year in equal installments. The combined PILOT payments of Selkirk and MASSPOWER scheduled for fiscal years are as follows: 1998........................................................ $3,766 1999........................................................ 3,960 2000........................................................ 4,173 2001........................................................ 4,387 2002........................................................ 4,601 Thereafter.................................................. 55,832 98 99 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) OTHER AGREEMENTS Selkirk has an operations and maintenance services agreement with GE whereby GE will provide certain operation and maintenance services during the operations of Unit 1 and the construction of Unit 2 and for seven years after the Unit 2 commercial operations date on a cost plus fixed fee basis. In addition, Selkirk has entered into a 20-year take or pay water supply agreement with the Town of Bethlehem under which Selkirk is committed to make minimum annual purchases of approximately $1,000, subject to adjustment for changes in market rates beginning in the tenth year. 6. RELATED PARTIES An affiliate of JMC Selkirk, Inc. has been appointed project administrative agent to manage the day-to-day affairs of Selkirk. This affiliate is compensated at agreed-upon billing rates, which are adjusted quadrennially in accordance with an administrative services agreement. For the years ended December 31, 1997 and 1996, approximately $2,852 and $2,715, respectively, were incurred for services rendered and are reflected in general and administrative expenses in the accompanying combined statements of operations. During the years ended December 31, 1997 and 1996, Selkirk purchased approximately $346 and $16, respectively, and sold approximately $26 and $238, respectively, in fuel at its fair market value in transactions with affiliates of JMC Selkirk, Inc. Purchases are included in fuel costs and sales are included in gas resales in the accompanying combined statements of operations. During the year ended December 31, 1996, Selkirk entered into an Enabling Agreement with US Gen Power Services, L.P. (USGEN PS), an affiliate of JMC Selkirk Inc., to enter into certain transactions for the purchase and sale of energy and other services. During the years ended December 31, 1997 and 1996, Selkirk entered into energy and capacity sales transactions with USGEN PS totaling approximately $100 and $45, respectively. Selkirk has two agreements with Iroquois Gas Transmission System (IGTS) to provide firm transportation of natural gas from Canada. An affiliate of JMC Selkirk, Inc. has a partnership interest in IGTS. MASSPOWER entered into an agreement with GE whereby GE provided certain operations and maintenance services for the one-year period prior to commercial operations (mobilization/start-up) and will continue to provide services for the seven-year period commencing on the date of commercial operations. For the years ended December 31, 1997, 1996 and 1995, respectively, MASSPOWER paid GE approximately $4,448, $4,519 and $4,222 for services rendered under this contract. In addition, certain plant equipment was purchased from GE through the construction contractor. An affiliate of JMC was appointed the project administrator to manage the day-to-day affairs of MASSPOWER. This affiliate is compensated at agreed-upon billing rates, which are adjusted annually. JMC's affiliate was paid approximately $1,729, $1,647 and $1,708 for the years ended 1997, 1996 and 1995, respectively. Orchard Gas, an affiliate of JMC, was reimbursed by MASSPOWER for fuel purchases it made acting in its capacity as agent for MASSPOWER. Orchard Gas was compensated $47, $52 and $62 for services performed during the years ended December 31, 1997, 1996 and 1995, respectively. 7. DISCLOSURE OF FAIR MARKET VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used by the Partnerships in estimating their fair value disclosures for financial instruments as of December 31, 1997 and 1996: Cash -- The carrying amount reported in the accompanying combined balance sheets for cash approximates its fair value of $8,164 and $9,022 at December 31, 1997 and 1996, respectively. 99 100 SELKIRK COGEN/MASSPOWER COMBINED NOTES TO FINANCIAL STATEMENTS -- (CONTINUED) Restricted funds -- The carrying amount reported in the accompanying combined balance sheets for restricted funds approximates its fair value of $41,488 and $38,820 at December 31, 1997 and 1996, respectively. Due from affiliates -- Management believes that the fair market value of these advances approximates market value. Due to affiliates -- The carrying amount reported in the accompanying combined balance sheets for amounts due to affiliates approximates its fair value due to the short-term maturities of these amounts. Long-term bonds -- The fair value of the long-term bonds is based on the current market rates for the bonds. The fair value of the long-term bonds (including the current portion) at December 31, 1997 and 1996 is approximately $598,010 and $591,451, respectively. The recorded value of these bonds is $574,171 and $584,516 at December 31, 1997 and 1996, respectively. Currency swap agreements -- The fair value of the currency exchange arrangements represents the termination value (liability) of approximately $(18,554) and $(8,433) at December 31, 1997 and 1996, respectively, estimated using current exchange rates. Interest rate swap agreements -- The fair value of the interest rate swap arrangements represents the termination value (liability) of approximately $14,680 at December 31, 1997 and 1996, respectively. The carrying amounts of other short-term liabilities (short-term debt, accrued interest and accounts payable and accrued expenses) reported in the accompanying combined balance sheet approximate market due to their short-term nature. 100 101 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA The following unaudited pro forma consolidated condensed balance sheet as of June 30, 1998 gives effect to the following transactions as if such transactions had occurred on June 30, 1998: (i) the BGCI Acquisition and (ii) the sale of the Senior Notes and the application of the net proceeds therefrom. The following unaudited pro forma consolidated condensed statements of operations for the six-month periods ended June 30, 1998 and December 31, 1997 and for the twelve-month period ended June 30, 1997 give effect to the following transactions as if such transactions had occurred on July 1, 1996: (i) the LS Power Acquisition, (ii) the BGCI Acquisition and (iii) the sale of the Senior Notes and the application of the net proceeds therefrom. The pro forma consolidated financial data and accompanying notes should be read in conjunction with the Company's consolidated financial statements and related notes thereto contained in the Company's Report on Form 10-K for the six-month transition period ended December 31, 1997. The pro forma adjustments are based upon available information and certain assumptions that management believes are reasonable and are described in the notes accompanying the pro forma consolidated financial data. The pro forma consolidated financial data is presented for informational purposes only and does not purport to represent what the Company's consolidated results of operations or financial position would actually have been had such transactions in fact occurred at such dates, or to project the Company's consolidated results of operations or financial position at any future date or for any future period. In the opinion of management, all adjustments necessary to present fairly such pro forma consolidated financial data have been made. References to the "Partnerships" in the notes accompanying the pro forma consolidated financial data mean Logan Generating Company, L.P., Northampton Generating Company, L.P., Chambers Cogeneration Limited Partnership and Scrubgrass Generating Company, L.P., collectively. References to the "Holding Companies" mean Palm Power Corporation, Hickory Power Corporation, Birch Power Corporation and Panther Creek Leasing, Inc., collectively. References to "Beale" mean Beale Generating Company (formerly J. Makowski Company, Inc.). For further information regarding specific projects that are referenced in the notes, see "Business -- BGCI Acquisition." 101 102 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET AS OF JUNE 30, 1998 (DOLLARS IN THOUSANDS) ADJUSTMENTS FOR ADJUSTMENTS FOR THE BGCI THE SALE OF ACTUAL (1) ACQUISITION SENIOR NOTES PRO FORMA ---------- --------------- --------------- ---------- ASSETS CURRENT ASSETS: Cash and cash equivalents................ $ 31,611 $(191,103)(2) $193,858(7) $ 34,366 Restricted cash.......................... 50,840 -- -- 50,840 Accounts receivable...................... 62,247 144(3) -- 62,391 Other current assets..................... 22,519 -- -- 22,519 ---------- --------- -------- ---------- Total current assets............. 167,217 (190,959) 193,858 170,116 PROPERTY, PLANT AND EQUIPMENT, NET......... 488,186 -- -- 488,186 LAND AND IMPROVEMENTS...................... 2,540 -- -- 2,540 DEFERRED FINANCING, START-UP AND ORGANIZATION COSTS, NET.................. 31,414 -- 4,575(8) 35,989 NET INVESTMENT IN LEASE.................... 497,332 -- -- 497,332 NATURAL GAS RESERVES....................... 1,958 -- -- 1,958 INVESTMENTS IN UNCONSOLIDATED AFFILIATES... 77,503 183,115(4) -- 260,618 OTHER ASSETS............................... 21,555 25,093(5) -- 46,648 ---------- --------- -------- ---------- $1,287,705 $ 17,249 $198,433 $1,503,387 ========== ========= ======== ========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current portion of long-term debt........ $ 84,493 $ -- $ -- $ 84,493 Other current liabilities................ 47,585 -- -- 47,585 ---------- --------- -------- ---------- Total current liabilities........ 132,078 -- -- 132,078 LONG-TERM DEBT............................. 964,820 198,433(9) 1,163,253 DEFERRED INCOME TAXES...................... 32,064 10,663(6) -- 42,727 MINORITY INTERESTS......................... 56,752 -- -- 56,752 OTHER LONG-TERM LIABILITIES................ 24,231 6,586(3) -- 30,817 ---------- --------- -------- ---------- 1,209,945 17,249 198,433 1,425,627 SHAREHOLDERS' EQUITY: Common stock, no par value, 300,000 shares authorized; 282,000 shares issued and outstanding................ 130 -- -- 130 Accumulated earnings..................... 77,630 -- -- 77,630 ---------- --------- -------- ---------- 77,760 -- -- 77,760 ---------- --------- -------- ---------- $1,287,705.. $ 17,249 $198,433 $1,503,387 ========== ========= ======== ========== The accompanying notes are an integral part of this unaudited pro forma consolidated condensed balance sheet. 102 103 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET The Company is accounting for the BGCI Acquisition using the purchase method of accounting. (1) This column represents the Company's historical consolidated condensed balance sheet as of June 30, 1998 which reflects the LS Power Acquisition as such acquisition was consummated on March 20, 1998. (2) Represents cash outflows used to fund (i) the BGCI Acquisition purchase price, which is subject to adjustment either upward or downward based on the final determination of the "Net Unrestricted Cash Differential" as defined in the Purchase Agreement, dated as of March 6, 1998, between Cogentrix Energy and BGCI and (ii) related transaction costs. (3) Represents the historical assets and liabilities of the Holding Companies, which hold BGCI's ownership interests in the Indiantown, Morgantown and Gilberton project partnerships and the undivided lessor interest in Panther Creek. The Company will acquire 100% of the outstanding common stock of the Holding Companies in connection with the BGCI Acquisition. Cash balances and current liability balances as of June 30, 1998 of certain of the Holding Companies have not been reflected in the accompanying pro forma balance sheet due to the expected distribution of such cash and satisfaction of such liabilities prior to consummation of the BGCI Acquisition. (4) Represents the Company's equity investment in the Partnerships and Beale as well as equity investments of the Holding Companies. Investments in affiliates include purchase price premiums or discounts resulting from the difference between the BGCI Acquisition purchase price inclusive of the related acquisition costs and the net assets acquired and, in certain circumstances, related deferred tax effects. (5) Represents a receivable related to the Company's investment in Cedar Bay and an investment in a leveraged lease. (6) Reflects the deferred tax effects of the BGCI Acquisition. (7) Represents cash proceeds from the sale of $220 million aggregate principal amount of Senior Notes by Cogentrix Energy, net of (i) the original issue discount on the Senior Notes, (ii) issuance costs associated with the offering of the Senior Notes and (iii) settlement costs for an interest rate hedge agreement related to the offering of the Senior Notes. (8) Represents issuance costs associated with the Senior Notes. (9) Represents the issuance of $220 million aggregate principal amount of Senior Notes by Cogentrix Energy, net of the original issue discount and net of deferred settlement costs for an interest rate hedge agreement associated with the Senior Notes. 103 104 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS FOR THE SIX-MONTH PERIOD ENDED JUNE 30, 1998 (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS PER COMMON SHARE) ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR LS POWER BGCI SALE OF ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA -------- --------------- --------------- --------------- --------- OPERATING REVENUE: Electric............................ $146,368 $ -- $ -- $ -- $146,368 Steam............................... 13,705 -- -- -- 13,705 Lease revenue....................... 12,433 9,793 -- -- 22,226 Service revenue under sales-type capital leases.................... 13,252 8,561 -- -- 21,813 Income from unconsolidated investments in power projects..... 1,797 -- 9,725(4) -- 11,522 Other............................... 7,301 1,056 791(5) -- 9,148 -------- ------- ------- ------- -------- 194,856 19,410 10,516 -- 224,782 -------- ------- ------- ------- -------- OPERATING EXPENSES: Fuel expense........................ 38,924 -- -- -- 38,924 Operations and maintenance.......... 32,272 149 -- -- 32,421 General, administrative and development expenses.............. 19,152 -- 308(5) -- 19,460 Depreciation and amortization....... 20,615 72 (118)(5) 229(6) 20,798 Cost of services under sales-type capital leases.................... 15,339 10,601 -- -- 25,940 -------- ------- ------- ------- -------- 126,302 10,822 190 229 137,543 -------- ------- ------- ------- -------- OPERATING INCOME...................... 68,554 8,588 10,326 (229) 87,239 OTHER INCOME (EXPENSE): Interest expense.................... (33,085) (6,790)(2) -- (10,607)(8) (50,482) Investment and other income, net.... 3,865 (738)(3) 396(5) -- 3,523 Equity in net loss of affiliates, net............................... (85) -- -- -- (85) -------- ------- ------- ------- -------- INCOME BEFORE MINORITY INTERESTS IN INCOME, INCOME TAXES AND EXTRAORDINARY LOSS.................. 39,249 1,060 10,722 (10,836) 40,195 MINORITY INTERESTS IN INCOME BEFORE EXTRAORDINARY LOSS.................. (5,613) (890) -- -- (6,503) -------- ------- ------- ------- -------- INCOME BEFORE INCOME TAXES AND EXTRAORDINARY LOSS.................. 33,636 170 10,722 (10,836) 33,692 PROVISION FOR INCOME TAXES............ (13,405) (66) (7) (4,279)(7) 4,323(7) (13,427) -------- ------- ------- ------- -------- INCOME BEFORE EXTRAORDINARY LOSS...... 20,231 104 6,443 (6,513) 20,265 EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT, net of minority interest and income tax benefit............................. (743) -- -- -- (743) -------- ------- ------- ------- -------- NET INCOME............................ $ 19,488 $ 104 $ 6,443 $(6,513) $ 19,522 ======== ======= ======= ======= ======== EARNINGS PER COMMON SHARE: Income before extraordinary loss.... $ 71.74 $ 71.86 Extraordinary loss.................. (2.63) (2.63) -------- -------- $ 69.11 $ 69.23 ======== ======== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING......................... 282,000 282,000 ======== ======== The accompanying notes are an integral part of this unaudited pro forma consolidated condensed statement of operations. 104 105 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS FOR THE SIX-MONTH PERIOD ENDED DECEMBER 31, 1997 (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS PER COMMON SHARE) ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR LS POWER BGCI SALE OF ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA -------- --------------- --------------- --------------- --------- OPERATING REVENUE: Electric............................. $154,810 $ -- $ -- $ -- $154,810 Steam................................ 12,721.. -- -- -- 12,721 Lease revenue........................ -- 11,844 -- -- 11,844 Service revenue under sales-type capital leases..................... -- 10,823 -- -- 10,823 Income from unconsolidated investments in power projects...... 1,186 -- 5,450(4) -- 6,636 Other................................ 9,229 1,419 1,225(5) -- 11,873 -------- ------- ------- ------- -------- 177,946 24,086 6,675 -- 208,707 -------- ------- ------- ------- -------- OPERATING EXPENSES: Fuel expense......................... 60,500 -- -- -- 60,500 Operations and maintenance........... 33,189 799 -- -- 33,988 General, administrative and development expenses............... 18,242.. -- 439(5) -- 18,681 Depreciation and amortization........ 20,407 93 (118)(5) 229(6) 20,611 Cost of services under sales-type capital leases..................... -- 12,799 -- -- 12,799 -------- ------- ------- ------- -------- 132,338.. 13,691 321 229 146,579 -------- ------- ------- ------- -------- OPERATING INCOME....................... 45,608 10,395 6,354 (229) 62,128 OTHER INCOME (EXPENSE): Interest expense..................... (25,680) (9,356)(2) -- (10,607)(8) (45,643) Investment and other income, net..... 4,334 (2,322)(3) 881(5) -- 2,893 Equity in net loss of affiliates, net................................ (1,813) -- -- -- (1,813) -------- ------- ------- ------- -------- INCOME BEFORE MINORITY INTERESTS IN INCOME, INCOME TAXES AND EXTRAORDINARY LOSS................... 22,449 (1,283) 7,235 (10,836) 17,565 MINORITY INTERESTS IN INCOME BEFORE EXTRAORDINARY LOSS................... (2,273) (1,085) -- -- (3,358) -------- ------- ------- ------- -------- INCOME BEFORE INCOME TAXES AND EXTRAORDINARY LOSS................... 20,176 (2,368) 7,235 (10,836) 14,207 PROVISION FOR INCOME TAXES............. (7,971) 936(7) (2,886)(7) 4,291(7) (5,610) -------- ------- ------- ------- -------- INCOME BEFORE EXTRAORDINARY LOSS....... 12,205 (1,432) 4,369 (6,545) 8,597 EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT, net of minority interest and income tax benefit.............................. (1,502) -- -- -- (1,502) -------- ------- ------- ------- -------- NET INCOME............................. $ 10,703 $(1,432) $ 4,369 $(6,545) $ 7,095 ======== ======= ======= ======= ======== EARNINGS PER COMMON SHARE: Loss before extraordinary loss....... $ 43.28 $ 30.49 Extraordinary loss................... (5.33) (5.33) -------- -------- $ 37.95 $ 25.16 ======== ======== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING.......................... 282,000 282,000 ======== ======== The accompanying notes are an integral part of this unaudited pro forma consolidated condensed statement of operations. 105 106 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS FOR THE TWELVE-MONTH PERIOD ENDED JUNE 30, 1997 (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS PER COMMON SHARE) ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR LS POWER BGCI SALE OF ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA -------- --------------- --------------- --------------- --------- OPERATING REVENUE: Electric............................. $315,203 $ -- $ -- $ -- $ 315,203 Steam................................ 26,686.. -- -- -- 26,686 Lease revenue........................ -- -- -- -- -- Service revenue under sales-type capital leases..................... -- -- -- -- -- Income from unconsolidated investments in power projects...... 574 -- 15,031(4) -- 15,605 Other................................ 10,343 -- 2,490(5) -- 12,833 -------- ------- ------- -------- --------- 352,806 -- 17,521 -- 370,327 -------- ------- ------- -------- --------- OPERATING EXPENSES: Fuel expense......................... 131,405 -- -- -- 131,405 Operations and maintenance........... 73,041 -- -- -- 73,041 General, administrative and development expenses............... 39,425.. -- 640(5) -- 40,065 Depreciation and amortization........ 40,047 -- (236)(5) 458(6) 40,269 Cost of services under sales-type capital leases..................... -- -- -- -- -- Loss on impairment and cost of removal............................ 65,628 -- -- -- 65,628 -------- ------- ------- -------- --------- 349,546.. -- 404 458 350,408 -------- ------- ------- -------- --------- OPERATING INCOME....................... 3,260 -- 17,117 (458) 19,919 OTHER INCOME (EXPENSE): Interest expense..................... (56,328) (4,347)(9) -- (21,215)(8) (81,890) Investment and other income, net..... 13,184 (5,585)(10) 327(5) -- 7,926 Equity in net loss of affiliates, net................................ (813) -- -- -- (813) -------- ------- ------- -------- --------- LOSS BEFORE MINORITY INTERESTS IN INCOME, INCOME TAXES AND EXTRAORDINARY LOSS................... (40,697) (9,932) 17,444 (21,673) (54,858) MINORITY INTERESTS IN INCOME BEFORE EXTRAORDINARY LOSS................... (4,013) -- -- -- (4,013) -------- ------- ------- -------- --------- LOSS BEFORE INCOME TAXES AND EXTRAORDINARY LOSS................... (44,710) (9,932) 17,444 (21,673) (58,871) BENEFIT FOR INCOME TAXES............... 17,112 3,923(7) (6,681)(7) 8,301(7) 22,655 -------- ------- ------- -------- --------- LOSS BEFORE EXTRAORDINARY LOSS......... (27,598) (6,009) 10,763 (13,372) (36,216) EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT, net of minority interest and income tax benefit.............................. (703) -- -- -- (703) -------- ------- ------- -------- --------- NET LOSS............................... $(28,301) $(6,009) $10,763 $(13,372) $ (36,919) ======== ======= ======= ======== ========= EARNINGS PER COMMON SHARE: Loss before extraordinary loss....... $ (97.87) $ (128.43) Extraordinary loss................... (2.49) (2.49) -------- --------- $(100.36) $ (130.92) ======== ========= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING.......................... 282,000 282,000 ======== ========= The accompanying notes are an integral part of this unaudited pro forma consolidated condensed statement of operations. 106 107 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS The Company is accounting for the BGCI Acquisition using the purchase method of accounting. (1) The pro forma adjustments for the LS Power Acquisition consist of (i) recognition of the operating results of the LSP-Cottage Grove, L.P. and LSP-Whitewater Limited Partnership (the "LS Power Partnerships") for the respective periods, (ii) the minority partner's interest in the net income of the LS Power Partnerships for the respective periods, (iii) the Company's cost of funds utilized to fund the purchase price of the LS Power Acquisition, (iv) amortization of goodwill resulting from the LS Power Acquisition and (v) the tax effect of the pro forma adjustments using the Company's effective tax rate for the respective period. The pro forma consolidated condensed statement of operations for the six-month period ended December 31, 1997 and the twelve-month period ended June 30, 1997 do not give effect to a full period of operating results of the acquired facilities since the Whitewater Facility and the Cottage Grove Facility did not commence commercial operations until September 18, 1997 and October 1, 1997, respectively. In addition, the pro forma adjustments for the six-month period ended December 31, 1997 do not include a gain on sales-type capital leases recorded for the Whitewater and Cottage Grove Facilities at their respective commercial operation dates. These gains are non-recurring items which will not have a continuing impact on the statement of operations. (2) Reflects the recognition of interest expense on Cottage Grove and Whitewater's non-recourse project financing debt in addition to the recognition of interest expense on the additional borrowings of the Company used to finance a portion of the LS Power Acquisition purchase price and related acquisition costs. These additional borrowings included $50,000,000 of indebtedness incurred by the Company under the Corporate Credit Facility and $20,000,000 of indebtedness incurred under the CVLC Revolving Credit Facility. Interest expense on the additional borrowings is computed using a blended interest rate of approximately 6.4%. The Whitewater and Cottage Grove Facilities capitalized interest costs through the commercial operation dates of the facilities on September 18, 1997 and October 1, 1997, respectively. (3) Reflects a reduction in the Company's investment income for the period as a result of the utilization of cash and marketable securities to fund a portion of the LS Power Acquisition purchase price and related acquisition costs, partially offset by other income recognized by Cottage Grove and Whitewater. The reduction in investment income is computed using an investment yield of approximately 5.7%. (4) Represents the Company's equity earnings from (i) the Partnerships, (ii) Beale and (iii) Indiantown, Gilberton and Morgantown (the equity investees of the Holding Companies). Equity earnings from affiliates is shown net of amortization of purchase price premiums or discounts resulting from the difference between the Company's purchase price inclusive of the related acquisition costs and the net assets acquired and, in certain circumstances, related deferred tax effects. These premiums or discounts will be amortized over the remaining life of the facilities or over the remaining term of the PPA using July 1, 1996 as the measurement date for estimated remaining life or remaining term. (5) Represents operating results of the Holding Companies. (6) Represents amortization of issuance costs associated with the issuance of the Senior Notes that are capitalized and amortized over the ten-year life of the Senior Notes. (7) Represents the income tax effect of the pro forma adjustments using the Company's historical effective tax rate for the periods presented. (8) Represents the recognition of interest expense on the issuance of the Senior Notes and the amortization of deferred settlement costs on an interest rate hedge agreement related to the Senior Notes. Interest expense is only recognized on the portion of the proceeds of the Senior Notes used to fund the BGCI Acquisition purchase price, related acquisition costs, issuance costs associated with the Senior Notes and settlement costs for an interest rate hedge agreement related to the Senior Notes. The settlement costs related to the interest rate hedge agreement are deferred and amortized over the term of the Senior Notes. 107 108 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES NOTES TO UNAUDITED PRO FORMA CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS -- (CONTINUED) (9) Reflects the recognition of interest expense on the additional borrowings of the Company used to fund the LS Power Acquisition purchase price and related acquisition costs at a blended interest rate of approximately 6.2%. (See Note 2.) (10) Reflects a reduction in the Company's investment income for the period as a result of the utilization of cash and marketable securities to fund a portion of the LS Power Acquisition purchase price and related acquisition costs. The reduction in investment income is computed using an investment yield of approximately 5.3%. 108