=======================================================================================================
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 June 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 (IRS Employer
incorporation or organization) Identification No.)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 51-0354675
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
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. YesX No __
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of June 30, 2001
and December 31, 2000........................................ 1
Consolidated Statements of Operations for the three and six
months ended June 30, 2001 and 2000.......................... 2
Consolidated Statements of Cash Flows for the three and six
months ended June 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.............................. 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk .. 14
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K............................. 15
SIGNATURES............................................................. 16
i
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(in Thousands)
(unaudited)
June 30, December 31,
2001 2000
------------------ ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,866 $ 3,187
Restricted funds 4,420 2,988
Accounts receivable, net of allowance of $196 and $174 18,139 20,097
Due from affiliates 647 3,882
Fuel inventory and supplies 8,726 6,693
Other current assets 1,256 436
------------------ ----------------
Total current assets 36,054 37,283
------------------ ----------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 373,304 372,443
Less: Accumulated depreciation 93,344 87,119
------------------ ----------------
Plant and equipment, net 279,960 285,324
------------------ ----------------
LONG-TERM RESTRICTED FUNDS 25,509 27,833
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $8,349 and $7,789, respectively 7,942 8,502
------------------ ----------------
TOTAL ASSETS $ 349,465 $ 358,942
================== ================
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ --- $ 49
Accrued bond interest payable 362 368
Accrued expenses 17,583 21,156
Due to affiliates 2,308 635
Current portion of long-term bonds 11,673 11,062
Current portion of liability for foreign exchange contracts 3,035 ---
------------------ ----------------
Total current liabilities 34,961 33,270
LONG-TERM LIABILITIES:
Deferred revenue 4,950 5,304
Other long-term liabilities 7,161 7,250
Long-term bonds - net of current portion 356,143 362,764
Liability for foreign exchange contracts - net of current portion 5,519 ---
------------------ ----------------
Total liabilities 408,734 408,588
------------------ ----------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (494) (485)
Limited partners' deficits (50,221) (49,161)
Accumulated other comprehensive income (8,554) ---
------------------ ----------------
Total partners' deficits (59,269) (49,646)
------------------ ----------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 349,465 $ 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 Six Months Ended
-------------------------------- ------------------------------
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
--------------- -------------- -------------- -------------
OPERATING REVENUES:
Electric and steam $ 45,927 $ 44,659 $ 107,511 $ 92,740
Fuel revenues 11,750 7,611 16,639 20,115
-------------- -------------
--------------- --------------
Total operating revenues 57,677 52,270 124,150 112,855
--------------- -------------- -------------- -------------
COST OF REVENUES:
Fuel and transmission costs 32,401 31,121 72,855 65,399
Other operating and maintenance 7,165 3,674 10,505 7,052
Depreciation 3,124 3,149 6,238 6,258
--------------- -------------- -------------- -------------
Total cost of revenues 42,690 37,944 89,598 78,709
--------------- -------------- -------------- -------------
GROSS PROFIT 14,987 14,326 34,552 34,146
--------------- -------------- -------------- -------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 539 666 970 1,353
Other general and administrative 709 668 1,314 1,042
Amortization of deferred financing charges 280 286 560 571
--------------- -------------- -------------- -------------
Total other operating expenses 1,528 1,620 2,844 2,966
--------------- -------------- -------------- -------------
OPERATING INCOME 13,459 12,706 31,708 31,180
--------------- -------------- -------------- -------------
INTEREST (INCOME) EXPENSE:
Interest income (667) (840) (1,305) (1,468)
Interest expense 8,266 8,427 16,537 16,856
--------------- -------------- -------------- -------------
Total interest expense, net 7,599 7,587 15,232 15,388
--------------- -------------- -------------- -------------
Income before cumulative effect of a change
in accounting principle 5,860 5,119 16,476 15,792
Cumulative effect of a change in
accounting principle --- --- --- 7,866
-------------- -------------
--------------- --------------
NET INCOME $ 5,860 $ 5,119 $ 16,476 $ 23,658
=============== ============== ============== =============
NET INCOME ALLOCATION:
General partners $ 59 $ 51 $ 165 $ 237
Limited partners 5,801 5,068 16,311 23,421
-------------- -------------- -------------- -------------
TOTAL $ 5,860 $ 5,119 $ 16,476 $ 23,658
=============== ============== ============== =============
See notes to consolidated financial statements.
2
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in Thousands)
For the Three Months Ended For the Six Months Ended
----------------------------- -------------------------
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
------------- ------------ ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 5,860 $ 5,119 $16,476 $ 23,658
Adjustments to reconcile net income to net cash
provided by operating activities:
Cumulative effect of a change in accounting principle --- --- --- (7,866)
Depreciation and amortization 3,404 3,426 6,798 6,820
Loss on sale of equipment 32 --- 32 ---
Increase (decrease) in cash resulting from a change
in:
Restricted funds 3,353 2,836 892 2,037
Accounts receivable 922 1,691 1,958 (3,594)
Due from affiliates 1,660 (784) 3,235 (906)
Fuel inventory and supplies (1,860) (48) (2,033) 106
Other current assets (911) 20 (820) (38)
Accounts payable (137) 216 (49) (1,733)
Accrued bond interest payable (8,277) (8,431) (6) (3)
Accrued expenses (984) (102) (3,573) 2,483
Due to affiliates 1,645 (192) 1,673 221
Deferred revenue (177) (167) (354) (343)
Other long-term liabilities 731 730 (89) 1,460
------------- ------------ ----------- -----------
Net cash provided by operating activities 5,261 4,314 24,140 22,302
------------- ------------ ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (650) (282) (916) (657)
Proceeds from disposal of plant and equipment 10 --- 10 ---
------------- ------------ ----------- -----------
Net cash used in investing activities (640) (282) (906) (657)
------------- ------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds 20,103 18,151 --- ---
Distributions to partners (17,545) (18,980) (17,545) (18,980)
Repayment of long-term debt (6,010) (3,021) (6,010) (3,021)
------------- ------------ ----------- -----------
Net cash used in financing activities (3,452) (3,850) (23,555) (22,001)
------------- ------------ ----------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 1,169 182 (321) (356)
------------- ------------ ----------- -----------
CASH AND CASH EQUIVALENTS,
BEGINNING OF YEAR 1,697 1,194 3,187 1,732
------------- ------------ ----------- -----------
CASH AND CASH EQUIVALENTS,
END OF YEAR $ 2,866 $ 1,376 $ 2,866 $ 1,376
============= ============ =========== ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 16,543 $ 16,859 $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 Statement of Operations for the three and six months ended June 30, 2000 to conform with the current period’s basis of presentation. Operating results for the three and six months ended June 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, on January 1, 2001. This standard requires the Partnership to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Under the standard there are three types of hedges: fair value hedges, cash flow hedges, and foreign currency hedges. A fair value hedge is a hedge of the exposure to changes in the fair value of a recognized asset or liability or of an unrecognized firm commitment, that is attributable to its fixed terms. If the derivative qualifies and is designated as a fair value hedge, the accounting treatment dictates that the changes in the fair value of the hedging instrument will be offset against the changes in fair value of the hedged assets, liabilities, or firm commitments attributable to the hedged risk and reflected in the consolidated statement of operations in the current period. A cash flow hedge is a hedge of the exposure to variability in the cash flows associated with a recognized asset or liability, or a forecasted transaction that is attributable to changes in variable rates or prices. If the derivative qualifies and is designated as a cash flow hedge, the accounting treatment dictates that the effective portions of the changes in the fair value of that derivative will be recognized in other comprehensive income, a separate component of partners’ equity during the hedge period, and will subsequently be recognized in the consolidated statement of operations when the hedged item affects earnings.
4
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.
The transition adjustment to implement this new standard 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.
Below is a table summarizing the quantitative information associated with the cash flow hedges associated with foreign currency contracts for the three and six months ended June 30, 2001.
Three Months Ended Six Months Ended
June 30, 2001 June 30, 2001
------------- -------------
(in thousands)
Net gain (loss) recognized in earnings --- ---
Amount of the hedge's ineffectiveness --- ---
Component of the derivative instrument's gain or loss
excluded from assessment of hedge's ineffectiveness --- ---
Net loss to be reclassified into earnings within 12 months $ (3,035) $ (3,035)
Net gain (loss) reclassified into earnings
because the original transaction will not occur --- ---
The schedule below summarizes the activities affecting accumulated other comprehensive income from derivative instruments for the three and six months ended June 30, 2001.
Three Months Ended Six Months Ended
June 30, 2001 June 30, 2001
------------- -------------
(in thousands)
Beginning accumulated derivative loss $ (10,042)
from SFAS133 transition adjustments at January 1, 2001 --- $ (8,968)
Net change of current period hedging transactions gain (loss) 731 (1,097)
Net reclassification to earnings 757 1,511
------------------- ----------- -----
Ending accumulated other comprehensive income(loss) $ (8,554) $ (8,554)
=========== ==========
5
The Partnership has certain derivative commodity contracts with optionality that result in the physical delivery of commodities used in the normal course of business. On June 29, 2001, the Derivatives Implementation Group of the Financial Accounting Standards Board (“FASB”, collectively the “DIG”) reached final conclusions that modified the definition of normal purchases and sales. As such, certain derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. The Partnership is currently evaluating the impact of the implementation guidance on the financial statements. Under the implementation guidance the effects of the recent conclusions of the DIG will be recorded on July 1, 2001.
Note 3. New Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, entitled, Business Combinations. This standard prohibits the use of 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.
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").
6
On April 6, 2001, the Utility filed a voluntary petition for relief under the provision of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court. 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.
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 Six Months Ended June 30, 2001 Compared to the Three and Six Months
Ended June 30, 2000
Net income for the quarter ended June 30, 2001 was approximately $6.3 million as compared to approximately $5.1 million in the prior year. The $1.2 million increase in net income is primarily due to higher operating revenues partially offset by higher maintenance expenses. Net income for the six months ended June 30, 2001 was approximately $16.9 million as compared to approximately $23.7 million. The $6.8 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 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 six months ended June 30, 2001 were approximately $57.7 million and $124.1 million as compared to approximately $52.3 million and $112.9 million for the corresponding periods in the prior year.
Electric Revenues (dollars and kWh's in millions):
For the Three Months Ended
June 30, 2001 June 30, 2000
------------------------------------ -----------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 10.4 84.8 48.60% 51.51% 10.4 137.7 79.15% 89.79%
Unit 2 35.7 391.1 67.59% 73.26% 33.8 390.3 67.44% 80.63%
8
For the Six Months Ended
June 30, 2001 June 30, 2000
------------------------------------- -------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 28.3 187.8 54.12% 56.03% 22.9 289.2 84.21% 92.51%
Unit 2 78.7 909.8 79.04% 84.16% 68.2 862.5 74.51% 87.80%
Unit 1 revenues for the quarter ended June 30, 2001 were comparable to the corresponding period in the prior year and increased approximately $5.4 million for the six months ended June 30, 2001 as compared to the corresponding period in the prior year. During the quarter ended June 30, 2001, 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 $6.6 million, $0.2 million and $3.6 million, respectively as compared to approximately $7.1 million, $3.3 million and $0.0 million, respectively, for the corresponding period in the prior year. During the six months ended June 30, 2001, revenues from Niagara Mohawk, PG&E Energy Trading and the ISO were approximately $19.0 million, $3.5 million and $5.8 million, respectively as compared to approximately $18.4 million, $4.5 million and $0.0 million, respectively, for the corresponding period in the prior year. The increase in Unit 1 revenues for the six months ended June 30, 2001 was primarily due to increases in Monthly Contract Payments and market energy prices, partially offset by a decrease in volume of delivered energy resulting from a seven week scheduled maintenance outage. During the six months ended June 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 six months ended June 30, 2001, the Partnership did not deliver any Contract Energy to Niagara Mohawk. During the month of January 2001, the Partnership sold all of the energy produced by Unit 1 to PG&E Energy Trading. During the months of February, May and June 2001, the Partnership sold all of the energy produced by Unit 1 to the ISO. No sales of energy were made from Unit 1 during the months of March and April 2001. During the six months ended June 30, 2000, with the exception of the month of April, the Partnership delivered Contract Energy to Niagara Mohawk. During the six months ended June 30, 2000, with the exception of February and April, the Partnership sold the energy produced by Unit 1 in excess of the Contract Energy (“Unit 1 Excess Energy”) to both Niagara Mohawk and PG&E Energy Trading. During the month of February 2000 all of the Unit 1 Excess Energy was sold to Niagara Mohawk. During the month of April 2000 all of the Unit 1 Excess Energy was sold to PG&E Energy Trading.
During the six months ended June 30, 2001, the Partnership did not sell any Contract Capacity to Niagara Mohawk. 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 months of May and June 2001 the Partnership sold all of the capacity associated with Unit 1 to both PG&E Energy Trading and the ISO. During the six months ended June 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.
9
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 were sold at negotiated market prices. Amortized deferred revenues of approximately $0.4 million are also included in revenues from Niagara Mohawk for the six months ended June 30, 2001 and 2000.
Unit 2 revenues increased approximately $2.0 million and $10.5 million for the quarter ended and six months ended June 30, 2001 as compared to the corresponding periods in the prior year. During the quarter ended June 30, 2001, revenues from Consolidated Edison Company of New York, Inc. (“Con Edison”), the ISO and unrelated third parties were approximately $34.6 million, $0.7 million and $0.4 million, respectively. During the six months ended June 30, 2001, revenues from Con Edison, the ISO and unrelated third parties were approximately $77.6 million, $0.7 million and $0.4 million, respectively. During the quarter and six months ended June 30, 2000, all of the Unit 2 revenues were from Con Edison. The increase in revenues from Unit 2 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 six months ended June 30, 2001 of approximately $0 and $0.6 million were reduced by a reserve of approximately $160 thousand. Steam revenues for the quarter and six months ended June 30, 2000 of approximately $0.4 million and $1.6 million were reduced by a reserve of approximately $46.3 thousand. 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 six months ended June 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 June 30, 2001 was approximately 328.2 million pounds or 150,267 lbs/hr as compared to approximately 411.4 million pounds or 188,393 lbs/hr for the corresponding period in the prior year. Delivered steam for the six months ended June 30, 2001 was approximately 761.0 million pounds or 174,229 lbs/hr as compared to approximately 967.3 million pounds or 219,055 lbs/hr for the corresponding period in the prior year.
10
Fuel revenues for the quarter and six months ended June 30, 2001 were approximately $11.8 million and $16.6 million as compared to approximately $7.6 million and $20.1 million for the corresponding periods in the prior year. Gas resale revenues for the quarter ended June 30, 2001 were approximately $11.3 million on sales of approximately 2.0 million MMBtu’s as compared to approximately $5.7 million on sales of approximately 1.5 million MMBtu’s for the corresponding period in the prior year. Gas resale revenues for the six months ended June 30, 2001 were approximately $14.8 million on sales of approximately 2.6 million MMBtu’s as compared to approximately $8.0 million on sales of approximately 2.2 million MMBtu’s for the corresponding period in the prior year. The increase in gas resale revenues during the quarter and six months ended June 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 quarter and six months ended June 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 June 30, 2001 were approximately $0.5 million on sales of approximately 0.1 million MMBtu’s as compared to approximately $1.9 million on sales of approximately 0.6 million MMBtu’s for the corresponding period in the prior year. Gas optimization revenues for the six months ended June 30, 2001 were approximately $1.4 million on sales of approximately 0.2 million MMBtu’s as compared to approximately $10.3 million on sales of approximately 3.4 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 June 30, 2001 and 2000. Revenues from peak shaving arrangements for the six months ended June 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.
Fuel and transmission costs for the quarter and six months ended June 30, 2001 were approximately $32.0 million and $72.4 million as compared to approximately $31.1 million and $65.4 million for the corresponding periods in the prior year. 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 quarter ended June 30, 2001 were approximately $29.4 million on purchases of approximately 6.8 million MMBtu’s as compared to approximately $27.0 million on purchases of approximately 7.1 million MMBtu’s for the corresponding period in the prior year. 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 six months ended June 30, 2001 were approximately $67.0 million on purchases of approximately 13.8 million MMBtu’s as compared to approximately $51.6 million on purchases of approximately 14.2 million MMBtu’s for the corresponding period in the prior year. The increase in the cost of fuel for the quarter and six months ended June 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 June 30, 2001 were approximately $0.4 million on purchases of approximately 0.1 million MMBtu’s as compared to approximately $1.9 million on purchases of approximately 0.6 million MMBtu’s for the corresponding period in the prior year. Fuel costs associated with gas optimizations for the six months ended June 30, 2001 were approximately $1.3 million on purchases of approximately 0.2 million MMBtu’s as compared to approximately $9.4 million on purchases of approximately 3.4 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 June 30, 2001 and 2000. Fuel costs associated with peak shaving arrangements for the six months ended June 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 June 30, 2001 and 2000, fuel costs were increased by approximately $0.7 million and $0.6 million, respectively, as a result of the currency swap agreements. During the six months ended June 30, 2001 and 2000, fuel costs were increased by approximately $1.5 million and $1.2 million, respectively, as a result of the currency swap agreements. Transmission costs for the quarter and six month ended June 30, 2001 and 2000, were approximately $2.2 million and $4.1 million as compared to approximately $2.2 million and $3.6 million for the corresponding periods in the prior year.
11
Other operating and maintenance expenses for the quarter and six months ended June 30, 2001 were approximately $7.2 million and $10.5 million as compared to approximately $3.7 million and $7.0 million for the corresponding periods in the prior year. The increase is primarily due to differences in the scheduling of planned maintenance.
Total other operating expenses, excluding amortization of deferred financing charges, for the quarter and six months ended June 30, 2001 of approximately $1.3 million and $2.3 million were comparable to the corresponding periods in the prior year.
Amortization of deferred financing charges for the quarter and six months ended June 30, 2001 of approximately $0.3 million and $0.6 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 six months ended June 30, 2001 of approximately $7.6 million and $15.2 million were comparable to the corresponding periods in the prior year.
Liquidity and Capital Resources
Net cash provided by operating activities for the quarter and six months ended June 30, 2001 was approximately $5.3 million and $24.1 million as compared to approximately $4.3 million and $22.3 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 six months ended June 30, 2001 was approximately $0.6 million and $0.9 million as compared to approximately $0.3 million and $0.7 million for the corresponding periods in the prior year. Net cash used in investing activities primarily represents additions to plant and equipment.
12
Net cash used in financing activities for the quarter and six months ended June 30, 2001 was approximately $3.5 million and $23.6 million as compared to approximately $3.9 million and $22.0 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 quarter and six months ended June 30, 2001 and 2000 primarily represent 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.
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.
13
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 six months ended June 30, 2001 would have resulted in a negative impact of approximately $66.7 thousand and 130.5 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 six months ended June 30, 2001, the currency exchange rate differential resulted in a negative impact of approximately $0.7 million and $1.5 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.
14
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.
15
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: August 8, 2001 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
16
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: August 8, 2001 /s/ JOHN R. COOPER
-----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
17