SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
The schedule below summarizes the activities affecting comprehensive income for the three and nine months ended September 30, 2002 and 2001 (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Net income $ 11.9 $ 10.1 $ 24.0 $ 26.6
Cumulative effect of adoption of
SFAS No. 133 --- --- --- (9.0)
Net gain (loss) from current period
hedging transactions in accordance
with SFAS No. 133 (1.2) (1.3) 0.2 (2.4)
Net reclassification to earnings 0.8 0.8 2.5 2.3
------------- ------------- ------------- -------------
Comprehensive income $ 11.5 $ 9.6 $ 26.7 $ 17.5
============= ============= ============= =============
Note 2. Significant Accounting Policies
Except as disclosed, the Partnership is following the same accounting principles discussed in the Partnership’s December 31, 2001 Annual Report on Form 10-K.
Adoption of New Accounting Pronouncements
On April 1, 2002, the Partnership implemented two interpretations issued by the Financial Accounting Standard Board’s (“FASB”) Derivatives Implementation Group (“DIG”). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in SFAS No. 133. Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exemption, and thus were not marked-to-market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis.
DIG Issue C15 changed the definition of normal purchases and sales for certain power contracts. The Partnership determined that all of its power contracts continue to qualify for the normal purchases and sales exemption. DIG Issue C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. The Partnership determined that one of its long-term fuel contracts failed to continue qualifying for the normal purchase exemption under the requirements of DIG Issue C16. However, because the long term fuel contract has market based pricing, the Partnership currently estimates its fair value to always be zero, resulting in no impact to the Partnership’s consolidated financial statements.
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In June 2001, the FASB issued SFAS No. 141, entitled, Business Combinations. This statement 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. This statement was adopted on January 1, 2002, and did not have an impact on the Partnership’s consolidated financial statements.
Also in June 2001, the FASB issued SFAS No. 142, entitled, Goodwill and Other Intangible Assets. This statement eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This statement also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This statement is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on the Partnership’s consolidated balance sheets at that date, regardless of when the assets were initially recognized. This statement was adopted on January 1, 2002, and did not have an impact on the Partnership’s consolidated financial statements.
In August 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. This statement was adopted on January 1, 2002, and did not have an impact on the Partnership’s consolidated financial statements.
Related Party Transactions
JMCS I Management, Inc. (“JMCS I Management”) manages the day-to-day operation of the Partnership and is compensated at agreed-upon billing rates that are adjusted quadrennially in accordance with an administrative services agreement. All officers and directors of JMC Selkirk, Inc., are also officers and directors of JMCS I Management. For the nine months ended September 30, 2002 and 2001, expenses incurred for services provided by JMCS I Management totaled approximately $1.1 million and $1.5 million, respectively. The cost of services provided by JMCS I Management was included in administrative services – affiliates in the accompanying consolidated statements of operations. The total amount due to JMCS I Management for these services at September 30, 2002, was approximately $0.4 million.
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The Partnership purchases from and sells gas to PG&E Energy Trading – Gas Corporation (“PG&E Energy Trading – Gas”), PG&E Energy Trading - Canada Corporation (“PG&E Energy Trading – Canada”), Pittsfield Generating Company, L.P. (“Pittsfield Generating”) and MASSPOWER, affiliates of JMC Selkirk, Inc., at fair value. Gas purchased from PG&E Energy Trading – Gas, Pittsfield and MASSPOWER for the nine months ended September 30, 2002 totaled approximately $7,884.8 thousand, $3.7 thousand and $41.9 thousand, respectively. Gas purchased from PG&E Energy Trading – Gas, Pittsfield and MASSPOWER for the nine months ended September 30, 2001 totaled approximately $2,677.8 thousand, $35.8 thousand and $2,535.5 thousand, respectively. Gas sold to PG&E Energy Trading – Gas, PG&E Energy Trading – Canada, Pittsfield and MASSPOWER for the nine months ended September 30, 2002 totaled approximately $16,223.7 thousand, $204.6 thousand, $0.5 thousand and $58.7 thousand, respectively. Gas sold to PG&E Energy Trading – Gas and Pittsfield for the nine months ended September 30, 2001 totaled approximately $15,209.5 thousand and $79.8 thousand, respectively. Gas purchases were recorded as fuel costs and sales of gas were recorded as fuel revenues in the accompanying consolidated statements of operations. The total amount due to PG&E Energy Trading – Gas for purchases of gas at September 30, 2002 was approximately $15.5 thousand and the total amount due from PG&E Energy Trading – Gas for sales of gas at September 30, 2002 was approximately $140.2 thousand.
In May 1996, the Partnership entered into an enabling agreement with PG&E Energy Trading – Power, L.P. ("PG&E Energy Trading-Power"), an affiliate of JMC Selkirk, Inc., to purchase and sell electric capacity, electric energy, and other electric-related products. For the nine months ended September 30, 2002 and 2001, sales to PG&E Energy Trading – Power totaled approximately $1.6 million and $3.8 million, respectively. Sales to PG&E Energy Trading – Power were recorded as electric revenues in the accompanying consolidated statements of operations. The total amount due from PG&E Energy Trading – Power at September 30, 2002 for sales of electric capacity was approximately $0.1 million.
The Partnership has two agreements with Iroquois Gas Transmission System (“IGTS”), an indirect affiliate of JMC Selkirk, Inc., to provide firm transportation of natural gas from Canada. For the nine months ended September 30, 2002, firm fuel transportation services from IGTS totaled approximately $5.6 million and $5.8 million, respectively. These services were recorded as fuel costs in the accompanying consolidated statements of operations. The total amount due IGTS for firm transportation at September 30, 2002, was approximately $0.6 million.
Note 3. Accounting For Derivative Contracts
The Partnership has two foreign currency exchange contracts to hedge against fluctuations in fuel transportation costs, which are denominated in Canadian dollars. For the three months ended September 30, 2002 and 2001, amounts charged to fuel costs as a result of losses realized from these contracts totaled approximately $0.8 million for each of the periods. For the nine months ended September 30, 2002 and 2001, amounts charged to fuel costs as a result of losses realized from these contracts totaled approximately $2.5 million and $2.3 million, respectively. The Partnership expects that net derivative losses of approximately $2.9 million, included in accumulated other comprehensive loss as of September 30, 2002, will be reclassified into earnings within the next twelve months. The actual amounts reclassified from accumulated other comprehensive loss to earnings will differ as a result of changes in exchange rates.
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The schedule below summarizes the activities affecting accumulated other comprehensive loss from derivative contracts for the three months and nine months ended September 30, 2002 and 2001 (in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Beginning accumulated other
comprehensive loss at July 1 and
January 1, respectively $ (5.7) $ (8.6) $ (8.8) $ (9.0)
Net gain (loss) from current
period hedging transactions (1.2) (1.3) 0.2 (2.4)
Net reclassification to earnings 0.8 0.8 2.5 2.3
------------- ------------- ------------- -------------
Ending accumulated other comprehensive loss $ (6.1) $ (9.1) $ (6.1) $ (9.1)
============= ============= ============= =============
The Partnership enters into peak shaving arrangements whereby it grants to local distribution companies or other purchasers a call on a specified portion of the Partnership’s firm natural gas supply for a specified number of days during the winter season. Revenues from peak shaving arrangements for the nine months ended September 30, 2002 and 2001 were approximately $0.5 million for each of the periods. On July 1, 2001, the Partnership determined peak shaving arrangements were no longer exempt from the requirements of SFAS No. 133 and recorded a loss of approximately $0.5 million reflecting the cumulative effect of a change in accounting principle. Changes in the fair value of peak shaving arrangements are recorded on the consolidated statements of operations as an unrealized gain or loss on derivative contracts. Unrealized loss on derivative contracts for the nine months ended September 30, 2002 and 2001 was approximately $0.4 million and $0, respectively.
Note 4. Concentrations of Credit Risk
Credit risk is the risk of loss the Partnership would incur if counterparties were to fail to perform their contractual obligations (accounts receivable). The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada. This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.
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As of September 30, 2002, the Partnership’s credit risk is primarily concentrated with the following customers: Consolidated Edison Company of New York, Inc., Niagara Mohawk Power Corporation and the New York Independent System Operator, all of whom are considered to be of investment grade. During the three months ended September 30, 2002, the parent company of three of the Partnership’s customers, all of whom are related parties, PG&E Energy Trading – Gas, PG&E Energy Trading – Canada and PG&E Energy Trading – Power was downgraded below investment grade. The Partnership’s net credit exposure to PG&E Energy Trading – Gas and PG&E Energy Trading – Power at September 30, 2002 was approximately $0.1 million and $0.1 million, respectively.
Note 5. Relationship with Affiliated Companies
Bankruptcy of Pacific Gas and Electric 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 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").
In December 2000, and in January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG that involved the use or creation of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries. One of these LLCs is PG&E National Energy Group, LLC, which owns 100% of the stock of NEG. After the restructuring was completed, two independent rating agencies, Standard and Poor’s (“S&P”) and Moody’s Investor Services (“Moody’s”) issued investment grade ratings for NEG and reaffirmed such ratings for certain NEG subsidiaries. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the United States Bankruptcy Court for the Northern District of California (“Bankruptcy Court”). Pursuant to the 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. The Utility and PG&E Corporation have jointly filed a plan of reorganization with the Bankruptcy Court that entails separating the Utility into four distinct businesses. The proposed plan of reorganization does not directly affect NEG or any of its subsidiaries. The Managing General Partner believes that NEG and its direct and indirect subsidiaries, including JMC Selkirk, Inc., Pentagen Investors, L.P. and the Partnership, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.
9
NEG Rating Actions
Currently, NEG is experiencing liquidity problems due to the deterioration in PG&E Corporation’s credit position, the Utility’s bankruptcy and the downturn in the energy industry. On July 31, 2002 and August 5, 2002, S&P and Moody’s, respectively, downgraded NEG’s ratings, as previously reported. On October 8, 2002, October 16, 2002 and October 18, 2002, Moody’s further downgraded the senior unsecured debt rating, issuer rating and syndicated bank credit facilities of NEG. Moody’s current rating of NEG is “B3". On October 11, 2002, S&P further downgraded certain of NEG’s debt facilities. S&P’s current rating of NEG is “B-". The result of these downgrades has left the credit ratings of NEG and its debt instruments below investment grade. Both S&P and Moody’s credit ratings assigned to NEG and its affiliates are under review for possible further downgrade. The credit rating agency action has had no material impact on the financial condition or results of operations of the Partnership.
On October 8, 2002, Moody’s stated that in conjunction with the downgrade of NEG it had placed the Partnership’s debt under review for possible downgrade. On October 15, 2002, S&P stated that the recent downgrade of NEG will not have an affect on the rating of the Partnership’s debt at this time. S&P’s rating of the Partnership’s debt is “BBB-". On November 5, 2002, Moody’s issued an opinion update changing the rating outlook of the Partnership’s debt to “under review for possible downgrade” from “stable” for the Partnership’s debt due in 2007 and “negative outlook” for the Partnership’s debt due in 2012. Moody’s rating of the Partnership’s debt is “Baa3".
Note 6. Title V Permit
On November 6, 2001, the Partnership received from the New York State Department of Environmental Conservation (the “DEC”) the Facility’s Title V operating permit endorsed by the DEC on November 2, 2001 (the “Title V Permit”). The Title V Permit as received by the Partnership contains conditions that conflict with the Partnership’s existing air permits, and the Facility’s compliance with these conditions under certain operating circumstances would be problematic. Further, the Partnership believes that certain of the conditions contained in the Title V Permit are inconsistent with the laws and regulations underlying the Title V program and Title V operating permits issued by the DEC to comparable electric generating 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. The DEC has confirmed that the terms and conditions of the Title V Permit are stayed pending a final DEC decision on the appeal. Since November 12, 2001, the Partnership and DEC staff have engaged in negotiations regarding the Title V Permit. At this time, the Partnership cannot assess whether a settlement can be achieved, the likely outcome of the adjudicatory hearing if no settlement is achieved, or the impact on the Facility.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
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; the consequences, if any, of a potential downgrade of the credit ratings for the Partnership’s debt, and the renewal of the Partnership’s credit agreement, both as described in “Liquidity and Capital Resources” below; the outcome of the negotiations with the New York State Department of Environmental Conservation regarding the Facility’s Title V operating permit as described in “Regulations and Environmental Matters” below; and whether Consolidated Edison Company of New York, Inc. (“Con Edison”) were to prevail in its claim to Unit 2’s excess natural gas volumes as described in the Partnership's December 31, 2001 Annual Report on Form 10-K.
Results of Operations
Three and Nine Months Ended September 30, 2002 Compared to the Three and
Nine Months Ended September 30, 2001
The Partnership earned net income of approximately $11.9 million for the three months ended September 30, 2002 as compared to approximately $10.1 million for the corresponding period in the prior year. The Partnership earned net income of approximately $24.0 million for the nine months ended September 30, 2002 as compared to approximately $26.6 million for the corresponding period in the prior year. The $1.8 million increase in net income for the three months ended September 30, 2002 was primarily due to higher operating revenues, lower maintenance expenses and the Partnership recording a loss in the prior year of approximately $0.5 million reflecting the cumulative effect of a change in accounting principle. The $2.6 million decrease in net income for the nine months ended September 30, 2002 was primarily due to higher maintenance expenses resulting from differences in the scheduling and scope of planned maintenance, partially offset by lower fuel costs.
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 Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (collectively, 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 on derivative contracts.
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Total operating revenues for the three and nine months ended September 30, 2002 were approximately $58.3 million and $164.7 million as compared to approximately $53.1 million and $177.3 million for the corresponding periods in the prior year.
Electric Revenues (dollars and kWh's in millions):
- --------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
- ------------------------------------------------------------ -------------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 15.3 153.6 87.0% 100.0% 16.0 158.4 89.8% 99.9%
Unit 2 38.1 575.4 98.4% 100.0% 36.8 573.1 97.8% 100.0%
For the Nine Months Ended
September 30, 2002 September 30, 2001
- ------------------------------------------------------------ -------------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 42.9 491.9 94.1% 98.4% 44.3 346.2 66.2% 70.8%
Unit 2 104.8 1,353.3 78.0% 85.2% 115.6 1,483.0 85.4% 89.5%
Unit 1 Electric Revenues (dollars in millions):
- -----------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Niagara Mohawk $ 8.3 $ 8.9 $ 24.7 $ 27.8
ISO 6.8 6.8 17.9 12.7
PG&E Energy Trading - Power 0.2 0.3 0.3 3.8
------------- ------------- ------------- -------------
$ 15.3 $ 16.0 $ 42.9 $ 44.3
============= ============= ============= =============
The $0.7 million decrease in Unit 1 electric revenues for the three months ended September 30, 2002 was primarily due to lower volumes of delivered energy and lower fuel index pricing in the energy component of the Niagara Mohawk Power Corporation (“Niagara Mohawk”) monthly contract payment. The $1.4 million decrease in Unit 1 electric revenues for the nine months ended September 30, 2002 was primarily due to lower fuel index pricing in the energy component of the Niagara Mohawk monthly contract payment and lower market energy prices, partially offset by higher volumes of delivered energy. The lower volume of delivered energy for the nine months ended September 30, 2001 resulted from a seven week scheduled maintenance outage in April and May 2001. Energy and capacity sales to the New York Independent System Operator (“ISO”) were sold at ISO market clearing prices, and energy and capacity sales to PG&E Energy Trading – Power, L.P., an affiliate of JMC Selkirk, Inc. (“PG&E Energy Trading - Power”), were sold at negotiated market prices.
12
Unit 2 Electric Revenues (dollars in millions):
- -----------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Con Edison $ 38.3 $ 36.8 $ 103.6 $ 114.5
ISO (0.2) --- (0.1) 0.7
PG&E Energy Trading - Power --- --- 1.3 ---
Unrelated third party --- --- --- 0.4
------------- ------------- ------------- -------------
$ 38.1 $ 36.8 $ 104.8 $ 115.6
============= ============= ============= =============
The $1.3 million increase in Unit 2 electric revenues for the three months ended September 30, 2002 was primarily due to escalation in the Con Edison contract capacity payment and higher fuel index pricing in the Con Edison contract price for delivered energy. The $10.8 million decrease in Unit 2 electric revenues for the nine months ended September 30, 2002 was primarily due to lower fuel index pricing in the Con Edison contract price for delivered energy and lower volumes of delivered energy resulting from a four week scheduled maintenance outage in January 2002 and a six week scheduled maintenance outage in April and May 2002.
Steam revenues for the three and nine months ended September 30, 2002 of approximately $0.3 million and $0.5 million were reduced by a reserve of approximately $0.3 million and $0.4 million, respectively. Steam revenues for the three and nine months ended September 30, 2001 of approximately $0.1 million and $0.7 million were reduced by a reserve of approximately $0.5 million and $0.7 million, 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 increase in steam revenues for the three and nine months ended September 30, 2002 was primarily due to an increase in steam sales in excess of the Discounted Quantity to General Electric. Delivered steam for the three months ended September 30, 2002 was approximately 383.3 million pounds or 175,524 lbs/hr as compared to approximately 292.6 million pounds or 133,994 lbs/hr for the corresponding period in the prior year. Delivered steam for the nine months ended September 30, 2002 was approximately 1,052.5 million pounds or 161,235 lbs/hr as compared to approximately 1,053.7 million pounds or 160,818 lbs/hr for the corresponding period in the prior year.
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Fuel Revenues (dollars and MMBtu's in millions):
- ------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
--------------------------------- -------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Gas Resales 0.4 0.1 0.4 0.1
Fuel Optimizations 4.4 1.4 0.3 0.1
--------------- ------------- ------------- --------------
4.8 1.5 0.7 0.2
=============== ============= ============= ==============
For the Nine Months Ended
September 30, 2002 September 30, 2001
--------------------------------- -------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Gas Resales 9.1 2.7 15.2 2.7
Fuel Optimizations 7.2 2.3 1.6 0.3
Peak Shaving Arrangements 0.5 --- 0.5 ---
--------------- ------------- ------------- --------------
16.8 5.0 17.3 3.0
=============== ============= ============= ==============
The $4.1 million increase in fuel revenues for the three months ended September 30, 2002 was primarily due to higher volumes of natural gas sold under fuel optimizations. The $0.5 million decrease in fuel revenues for the nine months ended September 30, 2002 was primarily due to lower market natural gas prices, partially offset by higher volumes of natural gas sold under fuel optimizations.
Fuel and Transmission Costs (dollars and MMBtu's in millions):
- --------------------------------------------------------------
For the Three Months Ended
September 30, 2002 September 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 24.4 7.1 23.7 7.1
Fuel Optimizations 4.2 1.4 0.4 0.1
Transmission Costs 2.5 --- 2.4 ---
--------------- -------------- ------------ --------------
31.1 8.5 26.5 7.2
=============== ============== ============ ==============
For the Nine Months Ended
September 30, 2002 September 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 69.8 20.7 91.2 20.9
Fuel Optimizations 6.9 2.3 1.7 0.3
Transmission Costs 6.3 --- 6.5 ---
--------------- -------------- ------------ --------------
83.0 23.0 99.4 21.2
=============== ============== ============ ==============
* Includes the cost of fuel associated with the production of electricity and gas resales.
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The $4.6 million increase in fuel and transmission costs for the three months ended September 30, 2002 was primarily due to higher volumes of natural gas purchased under fuel optimizations. The $16.4 million decrease in fuel and transmission costs for the nine months ended September 30, 2002 was primarily due to the lower price of natural gas under the firm fuel supply contracts, partially offset by higher volumes of natural gas purchased under fuel optimizations. The Partnership has foreign currency swap agreements to hedge against future exchange rate fluctuations under fuel transportation agreements, which are denominated in Canadian dollars. As a result of the currency swap agreements, fuel costs for the three and nine months ended September 30, 2002 were increased by approximately $0.8 million and $2.5 million as compared to approximately $0.8 million and $2.3 million for the corresponding periods in the prior year.
Unrealized loss on derivative contracts for the three and nine months ended September 30, 2002 was approximately $0 and $0.4 million as compared to $0 for the corresponding periods in the prior year. The unrealized loss reflects the change in fair value of peak shaving arrangements recorded in the first quarter of 2002.
Other operating and maintenance expenses for the three and nine months ended September 30, 2002 were approximately $3.0 million and $20.3 million as compared to approximately $3.7 million and $14.3 million for the corresponding periods in the prior year. The $6.0 million increase for the nine months ended September 30, 2002 in other operating and maintenance expenses were primarily due to differences in the scheduling and scope of planned maintenance. The first and second quarters of 2002 each included a scheduled maintenance outage on Unit 2, whereas the second quarter of 2001 included a scheduled maintenance outage on Unit 1.
Liquidity and Capital Resources
Net cash provided by operating activities for the three and nine months ended September 30, 2002 was approximately $23.0 million and $43.5 million as compared to approximately $22.1 million and $46.3 million for the corresponding periods in the prior year. Net cash provided by operating activities primarily represents net income, adjusted by non-cash expenses and income, plus the net effect of changes within the Partnership's operating assets and liability accounts.
Net cash provided by (used in) investing activities for the three and nine months ended September 30, 2002 was approximately $14.0 thousand and $(2.1) million as compared to approximately $(3.0) thousand and $(909.0) thousand for the corresponding periods in the prior year. Net cash provided by (used in) investing activities primarily represents additions to plant and equipment.
15
Net cash used in financing activities for the three and nine months ended September 30, 2002 was approximately $23.2 million and $44.5 million as compared to approximately $23.0 million and $46.5 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 three months ended September 30, 2002 and 2001 primarily represent deposits of monies into the Interest, Principal and Debt Service Reserve Funds. Net cash flows used in financing activities during the nine months ended September 30, 2002 and 2001 primarily represent deposits of monies into the Interest, Principal and Debt Service Reserve Funds, distributions to partners and the semi-annual payment of principal and interest on long-term debt.
On October 8, 2002, Moody's Investors Services ("Moody's") stated that in conjunction with the downgrade of PG&E National Energy Group, Inc. ("NEG"), it had placed the Partnership's debt under review for possible downgrade. On October 15, 2002, Standard and Poor's ("S&P") stated that the recent downgrade of NEG will not have an affect on the rating of the Partnership's debt at this time. S&P's rating of the Partnership's debt is "BBB-". On November 5, 2002, Moody's issued an opinion update changing the rating outlook of the Partnership's debt to "under review for possible downgrade" from "stable" for the Partnership's debt due in 2007 and "negative outlook" for the Partnership's debt due in 2012. Moody's rating of the Partnership's debt is "Baa3". The Partnership is currently undertaking a review of its significant contractual obligations in order to assess the consequences, if any, of a potential downgrade of the credit ratings for the Partnership's debt.
The Partnership has available for its use a credit agreement, as amended ("Credit Agreement"), with a maximum available credit of approximately $7.5 million through August 8, 2003. Outstanding balances bear interest at prime rate plus .375% per annum with principal and interest payable monthly in arrears. The Credit Agreement is available to the Partnership for the purposes of meeting letters of credit requirements under various project contracts and for meeting working capital requirements. The maximum amount available under the Credit Agreement for working capital purposes is $5.0 million. As of September 30, 2002, there were no amounts drawn or balances outstanding under either the letters of credit or the working capital arrangement.
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; fuel deliveries and prices; the consequences, if any, of a potential downgrade of the credit ratings for the Partnership's debt; and the renewal of the Partnership's credit agreement. A significant change in any of these factors could have a material adverse effect on the results of operations for the Partnership.
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 during 2002.
16
Market Risk
Interest Rates
Interest rate risk is the risk that changes in the interest rates could adversely affect earnings and cash flow. The Partnership’s cash and restricted cash are sensitive to changes in interest rates. Interest rate changes would result in a change in interest income due to the difference between the current interest rates on cash and restricted cash and the variable rate that these financial instruments may adjust to in the future. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. As of September 30, 2002, if interest rates change by 10 percent, the change would be immaterial to the Partnership’s consolidated financial statements.
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
Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. The Partnership uses currency swap agreements to partially hedge foreign currency exposure under fuel transportation agreements that are denominated in Canadian dollars. In the event a counterparty fails to meet the terms of the currency swap agreements, the Partnership would be exposed to the risk that fluctuating currency exchange rates may adversely impact its financial results.
The Partnership uses sensitivity analysis to measure its foreign currency exchange rate exposure not covered by the currency swap agreements. Based upon a sensitivity analysis at September 30, 2002, a 10 percent devaluation of the Canadian dollar would be immaterial to the Partnership’s consolidated financial statements.
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.
17
Credit Risk
Credit risk is the risk of loss the Partnership would incur if counterparties were to fail to perform their contractual obligations. The Partnership primarily conducts business with customers in the energy industry, such as investor-owned utilities, energy trading companies, financial institutions, gas production companies and gas transportation companies located in the United States and Canada. This concentration of counterparties may impact the Partnership’s overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory or other conditions. The Partnership mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with counterparties it considers to be of investment grade.
As of September 30, 2002, the Partnership’s credit risk is primarily concentrated with the following customers: Con Edison, Niagara Mohawk and ISO, all of whom are considered to be of investment grade. During the three months ended September 30, 2002, the parent company of three of the Partnership’s customers, all of whom are related parties, PG&E Energy Trading – Gas Corporation (“PG&E Energy Trading – Gas”), PG&E Energy Trading – Canada Corporation and PG&E Energy Trading – Power, was downgraded below investment grade. The Partnership’s net credit exposure to PG&E Energy Trading – Gas and PG&E Energy Trading – Power at September 30, 2002 was approximately $0.1 million and $0.1 million, respectively.
Accounting Principles Issued But Not Yet Adopted
In August 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Statements (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” This statement is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related asset. The Partnership is currently evaluating the impact of SFAS No. 143 on its consolidated financial statements.
In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” This statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. The statement also contains other 46 nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. The Partnership does not expect that implementation of this statement will have a significant impact on its consolidated financial statements.
18In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force (“EITF”) Issue No. 94-3. This statement is to be applied prospectively to exit or disposal activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of a company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. The Partnership does not expect that implementation of this statement will have a significant impact on its consolidated financial statements.
Critical Accounting Policies
Effective January 1, 2001, the Partnership adopted SFAS No. 133. This statement requires the Partnership to recognize all derivatives, as defined in the statement, on the consolidated balance sheets at fair value.
Legal Matters
The Partnership is a party in various legal proceedings and potential claims arising in the ordinary course of its business. Management does not believe that the resolution of these matters will have a material adverse effect on the Partnership’s consolidated financial position or results of operations. See Part I, Item 3 of the Partnership’s December 31, 2001 Annual Report on Form 10-K for further discussion of significant pending litigation.
19
Regulations and Environmental Matters
On November 6, 2001, the Partnership received from the New York State Department of Environmental Conservation (the “DEC”) the Facility’s Title V operating permit endorsed by the DEC on November 2, 2001 (the “Title V Permit”). The Title V Permit as received by the Partnership contains conditions that conflict with the Partnership’s existing air permits, and the Facility’s compliance with these conditions under certain operating circumstances would be problematic. Further, the Partnership believes that certain of the conditions contained in the Title V Permit are inconsistent with the laws and regulations underlying the Title V program and Title V operating permits issued by the DEC to comparable electric generating 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. The DEC has confirmed that the terms and conditions of the Title V Permit are stayed pending a final DEC decision on the appeal. Since November 12, 2001, the Partnership and DEC staff have engaged in negotiations regarding the Title V Permit. At this time, the Partnership cannot assess whether a settlement can be achieved, the likely outcome of the adjudicatory hearing if no settlement is achieved, or the impact on the Facility.
20
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to market risk from changes in interest rates, foreign currency exchange rates, energy commodity prices and credit risk, which could affect its future results of operations and financial condition. The Partnership manages its exposure to these risks through its regular operating and financing activities. (See “Market Risk”, included in Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations above.)
21
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Based on an evaluation of the Partnership’s disclosure controls and procedures conducted on October 21, 2002, the principal executive officers and principal financial officers of JMC Selkirk, Inc., as Managing General Partner of Selkirk Cogen Partners, L.P., and Selkirk Cogen Funding Corporation have concluded that such controls and procedures effectively ensure that information required to be disclosed by the Partnership in reports the Partnership files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the SEC’s rules and forms.
Changes in Internal Controls
There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
22
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) Exhibits
Exhibit No. Description
----------- -----------
10.5.16 First Amending Agreement dated as of the 1st day of November
2002, to the Second Amended and Restated Gas Purchase Contract
dated as of May 6, 1998 between Paramount Resources Ltd. and
Selkirk Cogen Partners, L.P.
99.9 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.10 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.11 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
99.12 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated November 14, 2002.
(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.
23
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.
By: JMC SELKIRK, INC.
Managing General Partner
Date: November 14, 2002 /s/ JOHN R. COOPER
-------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
24SIGNATURES
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, 2002 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
25
CERTIFICATION OF P. CHRISMAN IRIBE, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3 Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date
of this quarterly report (the “Evaluation Date”);
and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant’s ability to record, process, summarize and
report financial data and have identified for the
registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002 /s/ P. CHRISMAN IRIBE
---------------------
P. Chrisman Iribe
President
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen
Partners, L.P.
26
CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBINES-OXLEY ACT OF 2002
I, John R. Cooper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen
Partners, L.P.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant’s ability to
record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses
in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002
/s/ JOHN R. COOPER
-------------------------------------------
John R. Cooper
Senior Vice President, Chief Financial Officer
and Treasurer
JMC Selkirk, Inc.
Managing General Partner of Selkirk Cogen
Partners, L.P.
27
CERTIFICATION OF p. CHRISMAN IRIBE, PRINICPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, P. Chrisman Iribe, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant’s auditors and the
audit committee of registrant’s board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant’s ability to
record, process, summarize and report financial data and have
identified for the registrant’s auditors any material weaknesses
in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesse.
Date: November 14, 2002
/s/ P. CHRISMAN IRIBE
---------------------------------
P. Chrisman Iribe
President
Selkirk Cogen Funding Corporation
28
CERTIFICATION OF JOHN R. COOPER, PRINCIPAL FINANCIAL OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John R. Cooper, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Selkirk Cogen Funding
Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant’s other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure
controls and procedures within 90 days prior to the filing date of
this quarterly report (the “Evaluation Date”); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant’s other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant’s auditors
and the audit committee of registrant’s board of directors (or
persons performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant’s ability to record, process, summarize and
report financial data and have identified for the
registrant’s auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant’s other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.
Date: November 14, 2002
/s/ JOHN R. COOPER
--------------------------------------------------
John R. Cooper
Senior Vice President, Chief Financial Officer and
Treasurer
Selkirk Cogen Funding Corporation
29
