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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2001
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware 51-0324332
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of co-registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 788-3000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g) OF THE ACT:
None
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__
As of November 13, 2001, there were 10 shares of common stock of Selkirk Cogen Funding Corporation, $1 par value outstanding.
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TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of September 30, 2001
and December 31, 2000........................................ 1
Consolidated Statements of Operations for the three and
nine months ended September 30, 2001 and 2000................ 2
Consolidated Statements of Cash Flows for the three and
nine months ended September 30, 2001 and 2000................ 3
Notes to Consolidated Financial Statements................... 4
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations........................................ 8
Liquidity and Capital Resources.............................. 13
Item 3. Quantitative and Qualitative Disclosures About Market Risk .. 15
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K.............................. 16
SIGNATURES............................................................... 17
i
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in Thousands)
(unaudited)
September 30, December 31,
2001 2000
------------------ ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,012 $ 3,187
Restricted funds 26,727 5,089
Accounts receivable, net of allowance of $196 and $174 17,630 20,097
Due from affiliates 119 3,882
Fuel inventory and supplies 9,920 6,693
Other current assets 926 436
------------------ ----------------
Total current assets 57,334 39,384
------------------ ----------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 373,222 372,443
Less: Accumulated depreciation 96,443 87,119
------------------ ----------------
Plant and equipment, net 276,779 285,324
------------------ ----------------
LONG-TERM RESTRICTED FUNDS 24,314 25,732
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $8,625 and $7,789, respectively 7,666 8,502
------------------ ----------------
TOTAL ASSETS $ 366,093 $ 358,942
================== ================
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 870 $ 49
Accrued bond interest payable 8,503 368
Accrued expenses 16,687 21,156
Due to affiliates 977 635
Current portion of long-term bonds 11,673 11,062
Current portion of liability for derivative contracts 3,992 ---
------------------ ----------------
Total current liabilities 42,702 33,270
LONG-TERM LIABILITIES:
Deferred revenue 4,774 5,304
Other long-term liabilities 7,891 7,250
Long-term bonds - net of current portion 356,143 362,764
Liability for derivative contracts - net of current portion 5,656 ---
------------------ ----------------
Total liabilities 417,166 408,588
------------------ ----------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (407) (485)
Limited partners' deficits (41,537) (49,161)
Accumulated other comprehensive loss (9,129) ---
------------------ ----------------
Total partners' deficits (51,073) (49,646)
------------------ ----------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 366,093 $ 358,942
================== ================
See notes to consolidated financial statements.
1
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in Thousands)
(unaudited)
For the Three Months Ended For the Nine Months Ended
--------------------------------- ----------------------------------
September 30, September 30, September 30, September 30,
2001 2000 2001 2000
--------------- --------------- ---------------- ---------------
OPERATING REVENUES:
Electric and steam $ 52,433 $ 55,070 $ 159,944 $ 147,810
Fuel revenues 691 1,693 17,330 21,808
--------------- --------------- ---------------- ---------------
Total operating revenues 53,124 56,763 177,274 169,618
--------------- --------------- ---------------- ---------------
COST OF REVENUES:
Fuel and transmission costs 26,541 31,704 99,396 97,103
Other operating and maintenance 3,667 2,901 14,172 9,953
Depreciation 3,125 3,111 9,363 9,369
--------------- --------------- ---------------- ---------------
Total cost of revenues 33,333 37,716 122,931 116,425
--------------- --------------- ---------------- ---------------
GROSS PROFIT 19,791 19,047 54,343 53,193
--------------- --------------- ---------------- ---------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 478 409 1,448 1,762
Other general and administrative 669 567 1,983 1,609
Amortization of deferred financing charges 276 283 836 854
--------------- --------------- ---------------- ---------------
Total other operating expenses 1,423 1,259 4,267 4,225
--------------- --------------- ---------------- ---------------
OPERATING INCOME 18,368 17,788 50,076 48,968
--------------- --------------- ---------------- ---------------
INTEREST (INCOME) EXPENSE:
Interest income (377) (755) (1,682) (2,223)
Interest expense 8,141 8,864 24,678 25,720
--------------- --------------- ---------------- ---------------
Total interest expense, net 7,764 8,109 22,996 23,497
--------------- --------------- ---------------- ---------------
Income before cumulative effect of a change
in accounting principle 10,604 9,679 27,080 25,471
Cumulative effect of a change in
accounting principle (519) --- (519) 7,866
--------------- --------------- ---------------- ---------------
NET INCOME $ 10,085 $ 9,679 $ 26,561 $ 33,337
=============== =============== ================ ===============
NET INCOME ALLOCATION:
General partners $ 101 $ 97 $ 266 $ 334
Limited partners 9,984 9,582 26,295 33,003
--------------- --------------- ---------------- ---------------
TOTAL $ 10,085 $ 9,679 $ 26,561 $ 33,337
=============== =============== ================ ===============
See notes to consolidated financial statements.
2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in Thousands)
(unaudited)
For the Three Months Ended For the Nine Months Ended
----------------------------- -----------------------------
September 30, September 30, September 30, September 30,
2001 2000 2001 2000
-------------- -------------- -------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 10,085 $ 9,679 $ 26,561 $ 33,337
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of a change in accounting principle 519 --- 519 (7,866)
Depreciation and amortization 3,401 3,394 10,199 10,214
Loss on disposal of equipment 59 15 91 15
Increase (decrease) in cash resulting from a change
in:
Restricted funds 558 171 1,450 2,208
Accounts receivable 509 231 2,467 (3,363)
Due from affiliates 528 399 3,763 (507)
Fuel inventory and supplies (1,194) (46) (3,227) 60
Other current assets 330 (219) (490) (257)
Accounts payable 870 (264) 821 (1,997)
Accrued bond interest payable 8,141 8,364 8,135 8,361
Accrued expenses (896) 1,034 (4,469) 3,517
Due to affiliates (1,331) (17) 342 204
Deferred revenue (176) (177) (530) (520)
Other long-term liabilities 730 730 641 2,190
-------------- -------------- -------------- --------------
Net cash provided by operating activities 22,133 23,294 46,273 45,596
-------------- -------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (3) (72) (919) (729)
Proceeds from disposal of plant and equipment --- --- 10 ---
-------------- -------------- -------------- --------------
Net cash used in investing activities (3) (72) (909) (729)
-------------- -------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds (21,670) (22,850) (21,670) (22,850)
Distributions to partners (1,314) --- (18,859) (18,980)
Repayment of long-term debt --- --- (6,010) (3,021)
-------------- -------------- -------------- --------------
Net cash used in financing activities (22,984) (22,850) (46,539) (44,851)
-------------- -------------- -------------- --------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (854) 372 (1,175) 16
-------------- -------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 2,866 1,376 3,187 1,732
-------------- -------------- -------------- --------------
CASH AND CASH EQUIVALENTS,
END OF YEAR $ 2,012 $ 1,748 $ 2,012 $ 1,748
============== ============== ============== ==============
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ --- $ --- $ 16,543 $ 16,859
============== ============== ============== ==============
See notes to consolidated financial statements.
3
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Basis of Presentation
The accompanying unaudited consolidated financial statements include Selkirk Cogen Partners, L.P. and its wholly-owned subsidiary, Selkirk Cogen Funding Corporation, (collectively the “Partnership”). All significant intercompany accounts and transactions have been eliminated.
The consolidated financial statements for the interim periods presented are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to rules and regulations applicable to interim financial statements. The information furnished in the consolidated financial statements reflects all normal recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of such financial statements. Certain reclassifications have been made to the Consolidated Balance Sheet for the year ended December 31, 2000, Consolidated Statement of Operations and Consolidated Statement of Cash Flows for the three and nine months ended September 30, 2000 to conform with the current periods basis of presentation. Operating results for the three and nine months ended September 30, 2001 are not necessarily indicative of the results that may be expected for the year ended December 31, 2001.
These consolidated financial statements should be read in conjunction with the audited consolidated financial statements included in the Partnership’s December 31, 2000 Annual Report on Form 10-K.
Note 2. Adoption of New Accounting Pronouncement
The Partnership adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 (collectively, the “Statement”), on January 1, 2001. The Statement requires the Partnership to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are recognized in earnings. Effective January 1, 2001, the Partnership recorded on the balance sheet a liability for foreign exchange contracts. The Partnership has foreign exchange swaps accounted for as cash flow hedges that are used to economically hedge foreign currency risk associated with future purchases denominated in foreign currencies. Hedge effectiveness is measured at least quarterly. Any ineffectiveness is recognized in the income statement in the period that the ineffectiveness occurs. If a derivative instrument that has qualified for hedge accounting is liquidated or sold prior to maturity, the gain or loss at the time of termination remains in other comprehensive income until the hedged item impacts earnings.
4
The transition adjustment to implement the Statement was a negative adjustment of approximately $9.0 million to other comprehensive income, a component of partners’ equity and had no affect on net income on January 1, 2001. The ongoing effects will depend on the future market conditions and hedging activities at the Partnership.
The Partnership’s net losses on foreign currency contracts for the three and nine months ended September 30, 2001 were approximately $0.8 million and $2.3 million, respectively. The Partnership expects that net derivative losses of approximately $3.5 million, included in Accumulated other comprehensive loss as of September 30, 2001, will be reclassified into earnings within the next twelve months.
The schedule below summarizes the activities affecting accumulated other comprehensive loss from derivative instruments for the three and nine months ended September 30, 2001.
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2001
----- ----
(in thousands)
Beginning accumulated other comprehensive loss
at July 1, 2001 and January 1, 2001 $ (8,554) $ (8,968)
Net change of current period hedging transactions
gain (loss) (1,390) (2,486)
Net reclassification to earnings 815 2,325
---------- ----------
Ending accumulated other comprehensive loss $ (9,129) $ (9,129)
========== ==========
The Partnership also has certain derivative commodity contracts for the physical delivery of commodities transacted in the normal course of business. In June, 2001 (as revised in October 2001), the Financial Accounting Standards Board (“FASB”) approved an interpretation issued by the Derivatives Implementation Group (“DIG”), Issue No. C-15 that changes the definition of normal purchases and sales for certain power contracts. The Partnership must implement this interpretation on January 1, 2002, and is currently assessing the impact of these new rules. The FASB has also approved DIG Issue Nos. C-10 and C-16 that disallow normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of the Partnership’s derivative commodity contracts may no longer be exempt from the requirements of the Statement. Effective July 1, 2001, the Partnership recorded on the balance sheet a liability for certain gas contracts. The Partnership has determined the contracts no longer meet the definition of normal purchases and sales and are no longer exempt from the requirements of the Statement as a result of the DIG’s interpretative guidance under Issue No. C-10. The cumulative effect of a change in accounting principle was a loss of approximately $0.5 million. Future changes in the fair value of the contracts will be recorded on the income statement as an unrealized gain or loss. With respect to Issue No. C-16, the Partnership is evaluating the impact of this implementation guidance on its financial statements, and will implement this guidance, as appropriate, by the implementation deadline of April 1, 2002.
5
Note 3. New Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, entitled, Business Combinations. This standard prohibits the use of the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. The Partnership does not expect that implementation of this standard will have a significant impact on its financial statements.
Also in June 2001, the FASB issued SFAS No. 142, entitled, Goodwill and Other Intangible Assets. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on the Partnership’s balance sheet at that date, regardless of when the assets were initially recognized. The Partnership does not expect that implementation of this standard will have a significant impact on its financial statements.
In July 2001, the FASB issued SFAS No. 143, entitled, Accounting for Asset Retirement Obligations. This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. The Partnership has not yet determined the effects of this standard on its financial reporting.
In October 2001, the FASB issued SFAS No. 144, entitled, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS No. 144 supercedes SFAS No. 121, entitled, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, but retains its fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used. This Statement also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superceding previous guidance for discontinued operations of business segments. This Statement is effective for fiscal years beginning after December 15, 2001. The Partnership is assessing the impact of this standard on its financial statements.
6
Note 4. Bankruptcy of Affiliated Company
JMC Selkirk, Inc. is the managing general partner of the Partnership. Approximately 90% of the ownership interest in JMC Selkirk, Inc. is held by an indirect subsidiary of the PG&E National Energy Group, Inc.("NEG"). NEG is an indirect, wholly-owned subsidiary of PG&E Corporation, the parent company of Pacific Gas and Electric Company (the "Utility").
On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Management believes that the NEG and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with PG&E Corporation or the Utility in any insolvency or bankruptcy proceeding.
On September 20, 2001, the Utility and PG&E Corporation jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the NEG and its direct and indirect subsidiaries.
Note 5. Title V Permit
On November 6, 2001, the Partnership received from the New York State Department of Environmental Conservation (the "DEC") the Facility's final Title V permit dated November 2, 2001 (the "Title V Permit"), issued pursuant to the 1990 amendments to the Federal Clean Air Act. The Title V Permit as received by the Partnership contains conditions that are inconsistent with the Partnership's existing air permits and the laws and regulations underlying the Title V program, are problematic for the Partnership to comply with under certain operating circumstances, and are contrary to the Title V Permits of comparable facilities in New York. By letter dated November 12, 2001, the Partnership has filed with the DEC a request for an adjudicatory hearing to address and resolve the issues presented by the Title V Permit, and the terms and conditions of the Title V Permit will be stayed pending a final DEC decision on the appeal. At this time it is too early for the Partnership to assess the likely outcome of the adjudicatory hearing and the impact on the Facility.
7
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
New Accounting Pronouncements
The Partnership adopted Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138, on January 1, 2001. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion of SFAS No. 133. See Note 3 of the Notes to the Consolidated Financial Statements for a discussion of new accounting pronouncements.
Results of Operations
Three and Nine Months Ended September 30, 2001 Compared to the Three and
Nine Months Ended September 30, 2000
Net income for the quarter ended September 30, 2001 was approximately $10.1 million as compared to approximately $9.7 million in the prior year. The $0.4 million increase in net income is primarily due to higher gross profit, partially offset by the Partnership recording a loss in the quarter ended September 30, 2001 of approximately $0.5 million, reflecting the cumulative effect of a change in accounting principle. Net income for the nine months ended September 30, 2001 was approximately $26.6 million as compared to approximately $33.3 million. The $6.7 million decrease in net income is primarily due to the Partnership recording income in the prior year of approximately $7.9 million, reflecting the cumulative effect of a change in accounting principle.
Effective July 1, 2001, the Partnership determined that certain gas contracts no longer meet the definition of normal purchases and sales and are no longer exempt from the requirements of SFAS No. 133. The cumulative effect of a change in accounting principle was a loss of approximately $0.5 million. Future changes in the fair value of the contracts will be recorded on the income statement as an unrealized gain or loss.
Effective January 1, 2000, the Partnership changed its method of accounting for major maintenance and overhaul costs. Beginning January 1, 2000, the cost of major maintenance and overhauls has been accounted for as incurred. Previously, the estimated cost of major maintenance and overhauls was accrued in advance in a systematic and rational manner over the period between major maintenance and overhauls.
Total operating revenues for the quarter and nine months ended September 30, 2001 were approximately $53.1 million and $177.3 million as compared to approximately $56.8 million and $169.6 million for the corresponding periods in the prior year.
8
Electric Revenues (dollars and kWh's in millions):
For the Three Months Ended
September 30, 2001 September 30, 2000
---------------------------------------- ----------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 16.0 158.4 89.84% 99.97% 16.6 153.3 86.89% 97.60%
Unit 2 36.8 573.1 97.79% 100.00% 38.3 541.7 92.59% 100.00%
For the Nine Months Ended
September 30, 2001 September 30, 2000
------------------------------------------ -----------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 44.3 346.2 66.15% 70.83% 39.5 442.5 85.11% 94.22%
Unit 2 115.6 1,483.0 85.35% 89.50% 106.5 1,404.2 80.58% 91.89%
Unit 1 revenues decreased approximately $0.6 for the quarter ended September 30, 2001 as compared to the corresponding period in the prior year and increased approximately $4.8 million for the nine months ended September 30, 2001 as compared to the corresponding period in the prior year. During the quarter ended September 30, 2001, Unit 1 revenues from Niagara Mohawk Power Corporation (“Niagara Mohawk”), PG&E Energy Trading - Power, L.P. (“PG&E Energy Trading”) and the New York Independent System Operator (“ISO”) were approximately $8.9 million, $0.3 million and $6.8 million, respectively as compared to approximately $13.8 million, $2.8 million and $0.0 million, respectively, for the corresponding period in the prior year. During the nine months ended September 30, 2001, Unit 1 revenues from Niagara Mohawk, PG&E Energy Trading and the ISO were approximately $27.8 million, $3.8 million and $12.7 million, respectively as compared to approximately $32.2 million, $7.3 million and $0.0 million, respectively, for the corresponding period in the prior year. The decrease in Unit 1 revenues for the three months ended September 30, 2001 was primarily due to a decrease in market energy prices. The increase in Unit 1 revenues for the nine months ended September 30, 2001 was primarily due to an increase in Monthly Contract Payments, partially offset by a decrease in volume of delivered energy resulting from a seven week scheduled maintenance outage. During the nine months ended September 30, 2001 and 2000, with the exception of the month of April in each period, the Partnership received Monthly Contract Payments from Niagara Mohawk. Effective with the termination of certain transitional provisions on October 31, 2000, Niagara Mohawk is no longer obligated to purchase energy up to the monthly contract quantity (“Contract Energy”) or capacity associated with Contract Energy (“Contract Capacity”) from the Partnership.
During the quarter and nine months ended September 30, 2001, the Partnership did not deliver any Contract Energy to Niagara Mohawk. During the nine months ended September 30, 2001, with the exception of January, March and April, the Partnership sold all of the energy produced by Unit 1 to the ISO. During the month of January 2001, the Partnership sold all of the energy produced by Unit 1 to PG&E Energy Trading and no sales of energy were made from Unit 1 during the months of March and April 2001. During the nine months ended September 30, 2000, with the exception of the month of April, the Partnership delivered Contract Energy to Niagara Mohawk. During the nine months ended September 30, 2000, with the exception of January, February and March, the Partnership sold all of the energy produced by Unit 1 in excess of the Contract Energy (“Unit 1 Excess Energy”) to PG&E Energy Trading. During the months of January and March 2000, the Partnership sold the Unit 1 Excess Energy to both Niagara Mohawk and PG&E Energy Trading and during the month of February 2000, the Partnership sold all of the Unit 1 Excess Energy to Niagara Mohawk.
9
During the nine months ended September 30, 2001, the Partnership did not sell any Contract Capacity to Niagara Mohawk. During the nine months ended September 30, 2001, with the exception of January, February, March and April, the Partnership sold all of the capacity associated with Unit 1 to both PG&E Energy Trading and the ISO. During the months of January, February, March and April 2001, the Partnership sold all of the capacity associated with Unit 1 to the ISO. During the nine months ended September 30, 2000, the Partnership sold Contract Capacity to Niagara Mohawk and capacity in excess of Contract Capacity (“Unit 1 Excess Capacity”) to PG&E Energy Trading.
Contract Energy sales to Niagara Mohawk, Contract Capacity sales to Niagara Mohawk, energy sales to the ISO and capacity sales to the ISO were sold at ISO market clearing prices. Unit 1 Excess Energy sales to PG&E Energy Trading and Niagara Mohawk, Unit 1 Excess Capacity sales to PG&E Energy Trading, and energy and capacity sales to PG&E Energy Trading were sold at negotiated market prices. Amortized deferred revenues of approximately $0.5 million are also included in revenues from Niagara Mohawk for the nine months ended September 30, 2001 and 2000.
Unit 2 revenues decreased approximately $1.5 million for the quarter ended September 30, 2001 as compared to the corresponding period in the prior year and increased approximately $9.1 million for the nine months ended September 30, 2001 as compared to the corresponding period in the prior year. During the quarter ended September 30, 2001, all of the Unit 2 revenues were from Consolidated Edison Company of New York, Inc. (“Con Edison”). During the nine months ended September 30, 2001, Unit 2 revenues from Con Edison, the ISO and unrelated third parties were approximately $114.5 million, $0.7 million and $0.4 million, respectively. During the quarter and nine months ended September 30, 2000, all of the Unit 2 revenues were from Con Edison. The decrease in Unit 2 revenues for the three months ended September 30, 2001 was primarily due to a decrease in the Con Edison contract price for delivered energy resulting from lower index fuel prices, partially offset by an increase in volume of delivered energy. The increase in revenues from Unit 2 for the nine months ended September 30, 2001 was primarily due to the increase in the Con Edison contract price for delivered energy resulting from higher index fuel prices and the sale of other energy related products to the ISO and unrelated third parties.
Steam revenues for the quarter and nine months ended September 30, 2001 of approximately $81.5 thousand and $709.6 thousand were reduced by a reserve of approximately $510.4 thousand and $670.6 thousand, respectively. Steam revenues for the quarter and nine months ended September 30, 2000 of approximately $251.2 thousand and $1.8 million were reduced by a reserve of approximately $1.3 thousand and $47.6 thousand, respectively. The Partnership charges General Electric a nominal price for steam delivered in an amount up to the annual equivalent of 160,000 lbs/hr (the “Discounted Quantity”). The decrease in steam revenues for the quarter and nine months ended September 30, 2001 was primarily due to a decrease in steam sales in excess of the Discounted Quantity to General Electric. Delivered steam for the quarter ended September 30, 2001 was approximately 292.6 million pounds or 133,994 lbs/hr as compared to approximately 382.8 million pounds or 175,277 lbs/hr for the corresponding period in the prior year. Delivered steam for the nine months ended September 30, 2001 was approximately 1,053.7 million pounds or 160,817 lbs/hr as compared to approximately 1,350.1 million pounds or 204,568 lbs/hr for the corresponding period in the prior year.
10
Fuel revenues for the quarter and nine months ended September 30, 2001 were approximately $0.7 million and $17.3 million as compared to approximately $1.7 million and $21.8 million for the corresponding periods in the prior year. Gas resale revenues for the quarter ended September 30, 2001 were approximately $0.4 million on sales of approximately 0.1 million MMBtu’s as compared to approximately $1.1 million on sales of approximately 0.2 million MMBtu’s for the corresponding period in the prior year. Gas resale revenues for the nine months ended September 30, 2001 were approximately $15.2 million on sales of approximately 2.8 million MMBtu’s as compared to approximately $9.2 million on sales of approximately 2.5 million MMBtu’s for the corresponding period in the prior year. The decrease in gas resales revenues for the quarter ended September 30, 2001 is primarily due to higher load dispatch of Units 1 and 2 and lower natural gas prices, which resulted in lower volumes of natural gas becoming available for resale at lower prices. The increase in gas resale revenues during the nine months ended September 30, 2001 is primarily due to higher natural gas resale prices and lower dispatch of Unit 1, which resulted in higher volumes of natural gas becoming available for resale at higher prices. The increase in natural gas resale prices during the nine months ended September 30, 2001 generally resulted from higher market pricing for gas as well as increased demand for electric generation. Gas resales occur during periods when Units 1 or 2 are not operating at full capacity. Gas optimization revenues for the quarter ended September 30, 2001 were approximately $0.3 million on sales of approximately 0.1 million MMBtu’s as compared to approximately $0.6 million on sales of approximately 0.1 million MMBtu’s for the corresponding period in the prior year. Gas optimization revenues for the nine months ended September 30, 2001 were approximately $1.7 million on sales of approximately 0.3 million MMBtu’s as compared to approximately $10.8 million on sales of approximately 3.5 million MMBtu’s for the corresponding period in the prior year. Gas optimizations occur when the Partnership is able to optimize the long-term supply and transportation contracts and lower the cost of natural gas delivered to the Facility by purchasing and/or selling natural gas at favorable prices along the transportation route. There were no revenues from peak shaving arrangements during the quarters ended September 30, 2001 and 2000. Revenues from peak shaving arrangements for the nine months ended September 30, 2001 were approximately $0.4 million on sales of 0.0 thousand MMBtu’s as compared to approximately $1.8 million on sales of approximately 0.2 million MMBtu’s for the corresponding period in the prior year. Peak shaving arrangements occur when the Partnership enters into contracts with third party purchasers which allow purchasers to buy a specified portion of the Partnership’s firm natural gas supply for a specified number of days during the winter season.
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Fuel and transmission costs for the quarter and nine months ended September 30, 2001 were approximately $26.5 million and $99.4 million as compared to approximately $31.7 million and $97.1 million for the corresponding periods in the prior year. Fuel costs, excluding the cost of fuel associated with gas optimizations and transmission costs, for the quarter ended September 30, 2001 were approximately $23.7 million on purchases of approximately 7.1 million MMBtu’s as compared to approximately $29.2 million on purchases of approximately 7.1 million MMBtu’s for the corresponding period in the prior year. The decrease in the cost of fuel for the quarter ended September 30, 2001 was primarily due to the lower price of gas under the firm fuel supply contracts. Fuel costs, excluding the cost of fuel associated with gas optimizations, the cost of fuel associated with peak shaving arrangements, and transmission costs, for the nine months ended September 30, 2001 were approximately $91.2 million on purchases of approximately 20.9 million MMBtu’s as compared to approximately $80.8 million on purchases of approximately 21.3 million MMBtu’s for the corresponding period in the prior year. The increase in the cost of fuel for the nine months ended September 30, 2001 was primarily due to the higher price of gas under the firm fuel supply contracts. Fuel costs associated with gas optimizations for the quarter ended September 30, 2001 were approximately $0.3 million on purchases of approximately 0.1 million MMBtu’s as compared to approximately $0.6 million on purchases of approximately 0.1 million MMBtu’s for the corresponding period in the prior year. Fuel costs associated with gas optimizations for the nine months ended September 30, 2001 were approximately $1.7 million on purchases of approximately 0.3 million MMBtu’s as compared to approximately $10.0 million on purchases of approximately 3.5 million MMBtu’s for the corresponding period in the prior year. There were no fuel costs associated with peak shaving arrangements during the quarters ended September 30, 2001 and 2000. Fuel costs associated with peak shaving arrangements for the nine months ended September 30, 2001 were $0.0 million on purchases of 0.0 thousand MMBtu’s as compared to $0.8 million on purchases of 0.2 million MMBtu’s for the corresponding period in the prior year. The Partnership has foreign currency swap agreements to hedge against future exchange rate fluctuations under fuel transportation agreements, which are denominated in Canadian dollars. During the quarter ended September 30, 2001 and 2000, fuel costs increased by approximately $0.8 million and $0.7 million, respectively, as a result of the currency swap agreements. During the nine months ended September 30, 2001 and 2000, fuel costs increased by approximately $2.3 million and $1.8 million, respectively, as a result of the currency swap agreements. Transmission costs for the quarter and nine months ended September 30, 2001 and 2000, were approximately $2.5 million and $6.5 million as compared to approximately $1.9 million and $5.5 million for the corresponding periods in the prior year.
Other operating and maintenance expenses for the quarter and nine months ended September 30, 2001 were approximately $3.7 million and $14.2 million as compared to approximately $2.9 million and $10.0 million for the corresponding periods in the prior year. The increases are primarily due to differences in the scheduling of planned maintenance.
Total other operating expenses, excluding amortization of deferred financing charges, for the quarter and nine months ended September 30, 2001 of approximately $1.1 million and $3.4 million were comparable to the corresponding periods in the prior year.
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Amortization of deferred financing charges for the quarter and nine months ended September 30, 2001 of approximately $0.3 million and $0.8 million were comparable to the corresponding periods in the prior year. Deferred financing charges are amortized using the effective interest method.
Net interest expense for the quarter and nine months ended September 30, 2001 were approximately $7.8 million and $23.0 million as compared to $8.1 million and $23.5 million for the corresponding periods in the prior year. The decreases in net interest expense are primarily due to lower interest expense resulting from the lower principal balances outstanding, partially offset by lower interest income resulting from lower interest rates.
Liquidity and Capital Resources
Net cash provided by operating activities for the quarter and nine months ended September 30, 2001 was approximately $22.1 million and $46.3 million as compared to approximately $23.3 million and $45.6 million for the corresponding periods in the prior year. Net cash provided by operating activities primarily represents net income plus the net effect of recurring changes in cash receipts and disbursements within the Partnership’s operating assets and liability accounts.
Net cash used in investing activities for the quarter and nine months ended September 30, 2001 was approximately $3.0 thousand and $909.0 thousand as compared to approximately $72.0 thousand and $729.0 thousand for the corresponding periods in the prior year. Net cash used in investing activities primarily represents additions to plant and equipment.
Net cash used in financing activities for the quarter and nine months ended September 30, 2001 was approximately $23.0 million and $46.5 million as compared to approximately $22.9 million and $44.9 million for the corresponding periods in the prior year. Pursuant to the Partnership’s Depositary and Disbursement Agreement, administered by Bankers Trust Company, as depositary agent, the Partnership is required to maintain certain Restricted Funds. Net cash flows used in financing activities during the quarters ended September 30, 2001 and 2000 primarily represent deposits of monies into the Interest and Principal Funds. Net cash flows used in financing activities during the nine months ended September 30, 2001 and 2000 primarily represent deposits of monies into the Interest and Principal Funds, distributions to partners and the semi-annual payment of principal on long-term debt.
Future operating results and cash flows from operations are dependent on, among other things, the performance of equipment; levels of dispatch; the receipt of certain capacity and other fixed payments; electricity prices; natural gas resale prices; and fuel deliveries and prices. A significant change in any of these factors could have a material adverse effect on the results of operations for the Partnership.
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The Partnership believes, based on current conditions and circumstances, it will have sufficient cash flows from operations to fund existing debt obligations and operating costs.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements included herein are forward-looking statements concerning the Partnership’s operations, economic performance and financial condition. Such statements are subject to various risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors, including general business and economic conditions; the performance of equipment; levels of dispatch; the receipt of certain capacity and other fixed payments; electricity prices; natural gas resale prices; fuel deliveries and prices and whether Con Edison were to prevail in its claim to Unit 2‘s excess natural gas volumes described in the Partnership’s December 31, 2000 Annual Report on Form 10-K.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The Partnership is exposed to market risk from changes in interest rates, foreign currency exchange rates and energy commodity prices, which could affect its future results of operations and financial condition. The Partnership manages its exposure to these risks through its regular operating and financing activities.
Interest Rates
The Partnership’s cash and restricted cash are sensitive to changes in interest rates. Interest rate changes would result in a change in interest income due to the difference between the current interest rates on cash and restricted cash and the variable rate that these financial instruments may adjust to in the future. A 10% decrease in interest rates for the quarter and nine months ended September 30, 2001 would have resulted in a negative impact of approximately $37.7 thousand and $168.2 thousand, respectively, on the Partnership’s net income.
The Partnership’s long-term bonds have fixed interest rates. Changes in the current market rates for the bonds would not result in a change in interest expense due to the fixed coupon rate of the bonds.
Foreign Currency Exchange Rates
The Partnership’s currency swap agreements hedge against future exchange rate fluctuations which could result in additional costs incurred under fuel transportation agreements which are denominated in a foreign currency. In the event a counterparty fails to meet the terms of the agreements, the Partnership’s exposure is limited to the currency exchange rate differential. During the quarter and nine months ended September 30, 2001, the currency exchange rate differential resulted in a negative impact of approximately $0.8 million and $2.3 million, respectively, on the Partnership’s net income.
Energy Commodity Prices
The Partnership seeks to reduce its exposure to market risk associated with energy commodities such as electric power and natural gas through the use of long-term purchase and sale contracts. As part of its fuel management activities, the Partnership also enters into agreements to resell its long-term natural gas volumes, when it is feasible to do so, at favorable prices relative to the cost of contract volumes and the cost of substitute fuels. To the extent the Partnership has open positions, it is exposed to the risk that fluctuating market prices may adversely impact its financial results.
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PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) Exhibits
Not applicable.
(B) Reports on Form 8-K
Not applicable.
Omitted from this Part II are items which are not applicable or to which the answer is negative for the periods covered.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
SELKIRK COGEN PARTNERS, L.P.
JMC SELKIRK, INC.
General Partner
Date: November 14, 2001 /s/ JOHN R. COOPER
-----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
SELKIRK COGEN FUNDING
CORPORATION
Date: November 14, 2001 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
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