<PAGE> 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)
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, -----------------------
1998 1997 1996
----------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these combined balance sheets.
6
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH PERIODS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- ------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these combined statements.
7
<PAGE> 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)
<TABLE>
<S> <C>
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
========
</TABLE>
The accompanying notes are an integral part of these combined statements.
8
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH PERIODS
ENDED JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- -------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- ---------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== =========
</TABLE>
The accompanying notes are an integral part of these combined statements.
9
<PAGE> 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:
<TABLE>
<S> <C>
GENERAL PARTNERS:
Aspen..................................................... 50%
Eagle..................................................... 49%
LIMITED PARTNER:
Eagle..................................................... 1%
</TABLE>
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:
<TABLE>
<S> <C>
GENERAL PARTNER:
Keystone.................................................. 99%
LIMITED PARTNER:
Granite................................................... 1%
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
Jaeger...................................................... 50%
Poplar...................................................... 50%
</TABLE>
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
<PAGE> 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.
<TABLE>
<CAPTION>
POST PRE
9/20/97 9/20/97
------- -------
<S> <C> <C>
Peregrine.................................................. 50% 45%
Maple...................................................... 10% 15%
TIFD....................................................... 40% 40%
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
GENERAL PARTNERS:
Falcon.................................................... 24.63%
SPC....................................................... 24.87%
Pine...................................................... 20.00%
LIMITED PARTNERS:
Falcon.................................................... 0.50%
DCC....................................................... 30.00%
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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:
<TABLE>
<CAPTION>
1997 1996
-------- ----------
<S> <C> <C>
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
======== ==========
</TABLE>
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):
<TABLE>
<S> <C>
1998..................................................... $ 35,262
1999..................................................... 39,187
2000..................................................... 45,731
2001..................................................... 50,511
2002..................................................... 53,511
Thereafter............................................... 1,020,862
----------
Total.......................................... $1,245,064
==========
</TABLE>
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
<PAGE> 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):
<TABLE>
<S> <C>
1998........................................................ $ 1,208
1999........................................................ 1,218
2000........................................................ 1,079
2001........................................................ 836
2002........................................................ 639
Thereafter.................................................. 13,903
-------
Total............................................. $18,883
=======
</TABLE>
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):
<TABLE>
<S> <C>
1998........................................................ $ 16,602
1999........................................................ 16,857
2000........................................................ 17,581
2001........................................................ 17,317
2002........................................................ 18,673
Thereafter.................................................. 414,489
--------
Total............................................. $501,519
========
</TABLE>
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:
<TABLE>
<S> <C>
Gross investment in lease................................... $501,519
Unearned income............................................. (272,583)
--------
Net investment in lease................................... $228,936
========
</TABLE>
23
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31, DECEMBER 31,
1998 1997 1996
------------ ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
32
<PAGE> 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)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
SIX-MONTH PERIOD -----------------------------
ENDED JUNE 30, 1998 1997 1996 1995
------------------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
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)
======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
33
<PAGE> 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)
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID-IN ACCUMULATED STOCKHOLDER'S
STOCK CAPITAL DEFICIT EQUITY
------ ---------- ----------- -------------
<S> <C> <C> <C> <C>
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
=== ======= ======== =======
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
34
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH
PERIOD
ENDED YEAR ENDED DECEMBER 31,
JUNE 30, ----------------------------
1998 1997 1996 1995
----------- ------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C>
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
======== ======= ======= ========
</TABLE>
The accompanying notes are an integral part of these combined financial
statements.
35
<PAGE> 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
<PAGE> 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:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------
ENTITY AFFILIATE 1997 1996 1995
- ------ --------- ---- ---- ----
<S> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
------------ ------------
1997 1996
------------ ------------
<S> <C> <C>
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
========== ==========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
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)
</TABLE>
37
<PAGE> 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:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
------------ ------------
1997 1996
------------ ------------
<S> <C> <C>
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
======= ========
</TABLE>
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:
<TABLE>
<CAPTION>
NUMBER OF SHARES
------------------------
PAR VALUE ISSUED AND
PER SHARE AUTHORIZED OUTSTANDING
--------- ---------- -----------
<S> <C> <C> <C>
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
</TABLE>
38
<PAGE> 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:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
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
====== ====== ======
</TABLE>
Reconciliations between the federal statutory income tax rate and the
Entities' combined effective tax rates are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1997 1996 1995
---------------- ---------------- ----------------
<S> <C> <C> <C> <C> <C> <C>
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%
====== ===== ====== ===== ====== =====
</TABLE>
Significant components of the Entities' net deferred tax liability as of
December 31, 1997 and 1996 are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
------------ ------------
1997 1996
------------ ------------
<S> <C> <C>
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)
======== ========
</TABLE>
39
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, -----------------------
1998 1997 1996
----------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these combined balance sheets.
42
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH PERIOD ENDED
JUNE 30, FISCAL YEAR ENDED DECEMBER 31,
------------------------- ------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these combined statements.
43
<PAGE> 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)
<TABLE>
<S> <C>
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
========
</TABLE>
The accompanying notes are an integral part of these combined statements.
44
<PAGE> 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
<TABLE>
<CAPTION>
SIX-MONTH PERIOD ENDED
JUNE 30, FISCAL YEAR ENDED DECEMBER 31,
------------------------- -------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- ---------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== =========
</TABLE>
The accompanying notes are an integral part of these combined statements.
45
<PAGE> 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:
<TABLE>
<CAPTION>
FROM SEPTEMBER 20, 1997 UNTIL SEPTEMBER 20, 1997
----------------------- ------------------------
<S> <C> <C>
Toyan............................... 50% 48%
Palm................................ 10% 12%
TIFD................................ 40% 40%
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
CBCI........................................................ 80%
Cedar II.................................................... 20%
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 50
INDIANTOWN COGENERATION, L.P.
CEDAR BAY GENERATING COMPANY, L.P.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
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
======== ========
</TABLE>
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
<PAGE> 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
<PAGE> 52
INDIANTOWN COGENERATION, L.P.
CEDAR BAY GENERATING COMPANY, L.P.
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<S> <C>
1998............................................. $ 20,052
1999............................................. 17,362
2000............................................. 7,928
2001............................................. 13,045
2002............................................. 11,666
Thereafter....................................... 951,233
----------
Total.................................. $1,021,286
==========
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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:
<TABLE>
<S> <C>
1998............................................. $ 267,000
1999............................................. 287,000
2000............................................. 309,000
2001............................................. 332,000
2002............................................. 383,000
Thereafter....................................... 3,560,000
----------
Total $5,138,000
==========
</TABLE>
57
<PAGE> 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
<PAGE> 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.
<TABLE>
<CAPTION>
DECEMBER 31, 1997
FINANCIAL LIABILITIES CARRYING AMOUNT FAIR VALUE
--------------------- ----------------- ------------
<S> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1996
FINANCIAL LIABILITIES CARRYING AMOUNT FAIR VALUE
--------------------- ----------------- ------------
<S> <C> <C>
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
</TABLE>
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
<PAGE> 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
<PAGE> 61
J. MAKOWSKI COMPANY, INC.
CONSOLIDATED BALANCE SHEETS
AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31, DECEMBER 31,
1998 1997 1996
----------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated balance
sheets.
61
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH PERIOD ENDED
JUNE 30, YEAR ENDED DECEMBER 31,
------------------------- ------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- --------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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)
======= ======= ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
62
<PAGE> 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)
<TABLE>
<CAPTION>
CLASS A CLASS B
COMMON STOCK COMMON STOCK
----------------- ---------------- ADDITIONAL
NUMBER PAR NUMBER PAR PAID-IN ACCUMULATED
SHARES VALUE SHARES VALUE CAPITAL DEFICIT TOTAL
--------- ----- -------- ----- ---------- ----------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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
========= === ======== === ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
63
<PAGE> 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)
<TABLE>
<CAPTION>
SIX-MONTH PERIODS
ENDED JUNE 30, YEARS ENDED DECEMBER 31,
------------------------- -------------------------------
1998 1997 1997 1996 1995
----------- ----------- -------- -------- ---------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
64
<PAGE> 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
<PAGE> 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:
<TABLE>
<S> <C>
Feedline facility........................................ 22 years
Critical spare parts..................................... 16 years
Furniture and fixtures................................... 7 years
Office equipment......................................... 5 years
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1997 1996
------------ ------------
(000'S) (000'S)
<S> <C> <C>
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
========== ==========
</TABLE>
67
<PAGE> 68
J. MAKOWSKI COMPANY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1997 1996 1995
------------ ------------ ------------
(000'S) (000'S) (000'S)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
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
- ---------------------- ----------- ------- ------ -------- ----------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
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
<CAPTION>
JMC SHARE OF:
-------------------
CASH DISTRIBUTIONS
-------------------
PROJECT 12/31/97 12/31/96
- ---------------------- -------- --------
<S> <C> <C>
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)
</TABLE>
- ---------------
(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
<PAGE> 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
<PAGE> 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):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
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
======== ========
</TABLE>
Significant components of the Company's income tax expense (benefit)
attributable to continuing operations are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1997 1996 1995
------------ ------------ ------------
(000'S) (000'S) (000'S)
<S> <C> <C> <C>
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)
======= ======== =======
</TABLE>
73
<PAGE> 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:
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31, DECEMBER 31,
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
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)%
====== ====== ======
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
1997 1996
------- -------
(000'S) (000'S)
<S> <C> <C>
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
======= =======
</TABLE>
Following are maturities of long-term debt for each of the next five years
(in thousands):
<TABLE>
<S> <C>
1998....................................................... 3,040
1999....................................................... 2,109
2000....................................................... 2,181
2001....................................................... 2,262
2002....................................................... 2,354
Thereafter................................................. 13,224
-------
Total............................................ $25,170
=======
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
1998...................................................... 22,439
1999...................................................... 22,439
2000...................................................... 22,439
2001...................................................... 22,439
2002...................................................... 22,439
Thereafter................................................ 173,905
--------
Total........................................... $286,100
========
</TABLE>
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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 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
<PAGE> 82
SELKIRK COGEN/MASSPOWER
COMBINED BALANCE SHEETS
AS OF JUNE 30, 1998 (UNAUDITED), DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
----------- -------------------
1998 1997 1996
----------- -------- --------
(UNAUDITED)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
82
<PAGE> 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)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
--------------------------- ------------------------------
1998 1997 1997 1996 1995
------------ ------------ -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
83
<PAGE> 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)
<TABLE>
<CAPTION>
GENERAL LIMITED
PARTNERS PARTNERS TOTAL
-------- -------- -------
<S> <C> <C> <C>
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)
======= ======== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
84
<PAGE> 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)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31,
------------------------- ------------------------------
1998 1997 1997 1996 1995
--------- --------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
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
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
85
<PAGE> 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
<PAGE> 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:
<TABLE>
<CAPTION>
INTEREST
--------------------
GENERAL PARTNERS AFFILIATE OF PREFERRED ORIGINAL
- ---------------- ------------ --------- --------
<S> <C> <C> <C>
JMC Selkirk, Inc. J. Makowski Company, Inc. .09% 1.00%
(JMC)
Cogen Technologies Selkirk GP, Inc. Cogen Technologies, Inc. 1.00% --%
</TABLE>
<TABLE>
<CAPTION>
INTEREST
--------------------
LIMITED PARTNERS AFFILIATE OF PREFERRED ORIGINAL
- ---------------- ------------ --------- --------
<S> <C> <C> <C>
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% --%
</TABLE>
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:
<TABLE>
<CAPTION>
EQUITY
PARTNER AFFILIATE OF INTEREST
- ------- ------------ --------
<S> <C> <C>
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%
</TABLE>
The net profits or losses and cash distributions of MASSPOWER are allocated
to the partners based on their respective equity interests.
87
<PAGE> 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:
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Selkirk --
General Partners.......................................... $ (311) $ (173)
Limited Partners.......................................... (31,971) (18,637)
MASSPOWER --
General Partners.......................................... 22,201 16,326
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
Cogeneration facility....................................... 30 years
Computer systems............................................ 7 years
Office equipment............................................ 5 years
Furniture, fixtures and other equipment..................... 10 years
</TABLE>
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
<PAGE> 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:
<TABLE>
<CAPTION>
YEAR AMOUNT
- ---- --------
<S> <C>
1998........................................................ $ 3,298
1999........................................................ 4,822
2000........................................................ 7,307
2001........................................................ 11,062
2002........................................................ 13,529
Thereafter.................................................. 349,235
</TABLE>
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
<PAGE> 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:
<TABLE>
<S> <C>
1998........................................................ $ 5,513
1999........................................................ 7,350
2000........................................................ 11,025
2001........................................................ 13,125
2002........................................................ 15,750
Thereafter.................................................. 140,966
</TABLE>
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
<PAGE> 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.
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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.
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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
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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
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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
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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
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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:
<TABLE>
<S> <C>
1998........................................................ $3,766
1999........................................................ 3,960
2000........................................................ 4,173
2001........................................................ 4,387
2002........................................................ 4,601
Thereafter.................................................. 55,832
</TABLE>
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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.
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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.
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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
<PAGE> 102
COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
UNAUDITED PRO FORMA CONSOLIDATED CONDENSED BALANCE SHEET
AS OF JUNE 30, 1998
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ADJUSTMENTS FOR ADJUSTMENTS FOR
THE BGCI THE SALE OF
ACTUAL (1) ACQUISITION SENIOR NOTES PRO FORMA
---------- --------------- --------------- ----------
<S> <C> <C> <C> <C>
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
========== ========= ======== ==========
</TABLE>
The accompanying notes are an integral part of this unaudited pro forma
consolidated condensed balance sheet.
102
<PAGE> 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
<PAGE> 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)
<TABLE>
<CAPTION>
ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR
LS POWER BGCI SALE OF
ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA
-------- --------------- --------------- --------------- ---------
<S> <C> <C> <C> <C> <C>
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
======== ========
</TABLE>
The accompanying notes are an integral part of this unaudited pro forma
consolidated condensed statement of operations.
104
<PAGE> 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)
<TABLE>
<CAPTION>
ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR
LS POWER BGCI SALE OF
ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA
-------- --------------- --------------- --------------- ---------
<S> <C> <C> <C> <C> <C>
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
======== ========
</TABLE>
The accompanying notes are an integral part of this unaudited pro forma
consolidated condensed statement of operations.
105
<PAGE> 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)
<TABLE>
<CAPTION>
ADJUSTMENTS FOR ADJUSTMENTS FOR ADJUSTMENTS FOR
LS POWER BGCI SALE OF
ACTUAL ACQUISITION(1) ACQUISITION SENIOR NOTES PRO FORMA
-------- --------------- --------------- --------------- ---------
<S> <C> <C> <C> <C> <C>
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
======== =========
</TABLE>
The accompanying notes are an integral part of this unaudited pro forma
consolidated condensed statement of operations.
106
<PAGE> 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
<PAGE> 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
