=====================================================================================================
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, 2002
Commission File Number 33-83618
SELKIRK COGEN PARTNERS, L.P.
(Exact name of Registrant (Guarantor) as specified in its charter)
Delaware
51-0324332
(State or other jurisdiction of
(I.R.S. Employer Identification Number)
incorporation or organization)
SELKIRK COGEN FUNDING CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware
51-0354675
(State or other jurisdiction of
(I.R.S. Employer Identification Number)
incorporation or organization)
One Bowdoin Square, Boston, Massachusetts 02114
(Address of principal executive offices, including zip code)
(617) 788-3000
(Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OR 12 (g) OF THE ACT:
None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No __
As of August 12, 2002, there were 10 shares of common stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.
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TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of June 30, 2002
and December 31, 2001....................................... 1
Consolidated Statements of Operations for the three and six
months ended June 30, 2002 and 2001......................... 2
Consolidated Statements of Cash Flows for the three and six
months ended June 30, 2002 and 2001......................... 3
Notes to Consolidated Financial Statements.................. 4
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations....................................... 10
Liquidity and Capital Resources............................. 14
Item 3. Quantitative and Qualitative Disclosures About Market Risk.. 18
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K............................ 19
SIGNATURES............................................................. 20
i
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(In Thousands)
June 30, December 31,
2002 2001
--------------- ---------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,594 $ 4,546
Restricted funds 8,562 7,699
Accounts receivable, net of allowance of $0 and $32, respectively 18,142 17,789
Due from affiliates 996 1,127
Fuel inventory and supplies 5,921 10,228
Other current assets 1,298 511
Asset for derivative contracts --- 446
--------------- ---------------
Total current assets 36,513 42,346
--------------- ---------------
PLANT AND EQUIPMENT:
Plant and equipment, at cost 374,944 373,476
Less: Accumulated depreciation 105,657 99,563
--------------- ---------------
Plant and equipment, net 269,287 273,913
--------------- ---------------
LONG-TERM RESTRICTED FUNDS 26,854 24,314
DEFERRED FINANCING CHARGES, net of accumulated
amortization of $9,445 and $8,901, respectively 6,846 7,390
--------------- ---------------
TOTAL ASSETS $ 339,500 $ 347,963
=============== ===============
LIABILITIES AND PARTNERS' DEFICITS
CURRENT LIABILITIES:
Accounts payable $ 368 $ 1,729
Accrued bond interest payable 351 357
Accrued fuel expenses 9,667 8,689
Accrued property taxes 3,200 2,296
Accrued operating and maintenance expenses 3,574 1,262
Other accrued expenses 3,483 4,173
Due to affiliates 1,109 2,008
Current portion of long-term bonds 15,406 13,529
Current portion of liability for derivative contracts 2,571 3,688
--------------- ---------------
Total current liabilities 39,729 37,731
LONG-TERM LIABILITIES:
Deferred revenue 4,243 4,597
Other long-term liabilities 6,881 7,070
Long-term bonds - net of current portion 340,737 349,235
Liability for derivative contracts - net of current
portion 3,137 5,113
--------------- ---------------
Total liabilities 394,727 403,746
--------------- ---------------
COMMITMENTS AND CONTINGENCIES
PARTNERS' DEFICITS:
General partners' deficits (487) (458)
Limited partners' deficits (49,032) (46,524)
Accumulated other comprehensive loss (5,708) (8,801)
--------------- ---------------
Total partners' deficits (55,227) (55,783)
--------------- ---------------
TOTAL LIABILITIES AND PARTNERS' DEFICITS $ 339,500 $ 347,963
=============== ===============
The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.
1
SELKIRK COGEN PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands)
For the Three Months Ended For the Six Months Ended
-------------------------------- ------------------------------
June 30, June 30, June 30, June 30,
2002 2001 2002 2001
--------------- -------------- -------------- -------------
OPERATING REVENUES:
Electric and steam $ 44,931 $ 45,927 $ 94,394 $ 107,511
Fuel revenues 8,493 11,750 11,985 16,639
-------------- -------------
--------------- --------------
Total operating revenues 53,424 57,677 106,379 124,150
--------------- -------------- -------------- -------------
COST OF REVENUES:
Fuel and transmission costs 27,784 32,401 51,939 72,855
Unrealized loss on derivative contracts --- --- 446 ---
Other operating and maintenance 10,770 7,197 17,301 10,537
Depreciation 3,139 3,124 6,260 6,238
--------------- -------------- -------------- -------------
Total cost of revenues 41,693 42,722 75,946 89,630
--------------- -------------- -------------- -------------
GROSS PROFIT 11,731 14,955 30,433 34,520
--------------- -------------- -------------- -------------
OTHER OPERATING EXPENSES:
Administrative services, affiliates 187 539 701 970
Other general and administrative 804 677 1,461 1,282
Amortization of deferred financing charges 272 280 544 560
--------------- -------------- -------------- -------------
Total other operating expenses 1,263 1,496 2,706 2,812
--------------- -------------- -------------- -------------
OPERATING INCOME 10,468 13,459 27,727 31,708
--------------- -------------- -------------- -------------
INTEREST (INCOME) EXPENSE:
Interest income (260) (667) (467) (1,305)
Interest expense 8,026 8,266 16,058 16,537
--------------- -------------- -------------- -------------
Total interest expense, net 7,766 7,599 15,591 15,232
--------------- -------------- -------------- -------------
NET INCOME $ 2,702 $ 5,860 $ 12,136 $ 16,476
=============== ============== ============== =============
NET INCOME ALLOCATION:
General partners $ 28 $ 59 $ 122 $ 165
Limited partners 2,674 5,801 12,014 16,311
--------------- -------------- -------------- -------------
TOTAL $ 2,702 $ 5,860 $ 12,136 $ 16,476
=============== ============== ============== =============
The accompanying Notes to the Consolidated Financial Statements are an integral part of these 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,
2002 2001 2002 2001
------------- ------------ ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,702 $ 5,860 $12,136 $ 16,476
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 3,411 3,404 6,804 6,798
Unrealized loss on derivative contracts --- --- 446 ---
Deferred revenue (177) (177) (354) (354)
Loss on disposal of plant and equipment 481 32 481 32
Increase (decrease) in cash resulting from a change
in:
Restricted funds (1,321) 3,353 (3,402) 892
Accounts receivable (597) 922 (353) 1,958
Due from affiliates (604) 1,660 131 3,235
Fuel inventory and supplies 2,585 (1,860) 4,307 (2,033)
Other current assets (889) (911) (787) (820)
Accounts payable 187 (137) (1,361) (49)
Accrued bond interest payable (8,038) (8,277) (6) (6)
Accrued fuel expenses 646 (1,565) 978 (4,667)
Accrued property taxes --- --- 904 100
Accrued operating and maintenance expenses 2,401 138 2,312 (276)
Other accrued expenses (1,389) 443 (690) 1,270
Due to affiliates 312 1,645 (899) 1,673
Other long-term liabilities 730 731 (189) (89)
------------- ------------ ----------- -----------
Net cash provided by operating activities 440 5,261 20,458 24,140
------------- ------------ ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Plant and equipment additions (1,949) (650) (2,115) (916)
Proceeds from disposal of plant and equipment --- 10 --- 10
------------- ------------ ----------- -----------
Net cash used in investing activities (1,949) (640) (2,115) (906)
------------- ------------ ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Restricted funds 22,597 20,103 (1) ---
Distributions to partners (14,673) (17,545) (14,673) (17,545)
Repayment of long-term debt (6,621) (6,010) (6,621) (6,010)
------------- ------------ ----------- -----------
Net cash provided by (used in) financing 1,303 (3,452) (21,295) (23,555)
activities
------------- ------------ ----------- -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (206) 1,169 (2,952) (321)
------------- ------------ ----------- -----------
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 1,800 1,697 4,546 3,187
------------- ------------ ----------- -----------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 1,594 $ 2,866 $ 1,594 $ 2,866
============= ============ =========== ===========
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest $ 16,064 $ 16,543 $16,064 $16,543
============= ============ =========== ===========
The accompanying Notes to the Consolidated Financial Statements are an integral part of these 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 accounting
principles generally accepted in the United States 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, 2001 to conform with the current period’s basis of
presentation. Operating results for the three and six months ended June 30, 2002
are not necessarily indicative of the results that may be expected for the year
ended December 31, 2002.
These consolidated financial statements should be read in conjunction with the
audited consolidated financial statements included in the Partnership’s
December 31, 2001 Annual Report on Form 10-K.
The preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions. These estimates and assumptions affect the reported
amounts of revenue, expenses, assets and liabilities, and the disclosure of
contingencies. Actual results could differ from these estimates.
Comprehensive Income
The Partnership’s comprehensive income consists principally of net income
and changes in the market value of certain financial hedges under 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).
4
The schedule below summarizes the activities affecting comprehensive income for
the three and six months ended June 30, 2002 and 2001 (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
------------- ------------- ------------- -------------
Net income $ 2.7 $ 5.9 $ 12.1 $ 16.5
Cumulative effect of adoption of
SFAS No. 133 --- --- --- (9.0)
Net gain (loss) from current period
hedging transactions in accordance
with SFAS No. 133 1.4 0.7 1.4 (1.1)
Net reclassification to earnings 0.8 0.7 1.7 1.5
------------- ------------- ------------- -------------
Comprehensive income $ 4.9 $ 7.3 $ 15.2 $ 7.9
============= ============= ============= =============
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.
5
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 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 six months ended June 30, 2002 and 2001, expenses incurred for services
provided by JMCS I Management totaled approximately $0.7 million and $1.0
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 JMCS I Management
for these services at June 30, 2002, was approximately $0.3 million.
6
The Partnership purchases and sells gas to PG&E Energy Trading – Gas
Corporation, Pittsfield Generating Company, L.P. and MASSPOWER, affiliates of
JMC Selkirk, Inc., at fair value. Gas purchased from affiliates of JMC Selkirk,
Inc. for the six months ended June 30, 2002 and 2001, totaled approximately $3.5
million and $4.0 million respectively, and gas sold to affiliates of JMC
Selkirk, Inc. totaled approximately $11.5 million and $14.7 million
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 affiliates of JMC Selkirk, Inc. for
purchases of gas at June 30, 2002 was approximately $0.8 million and the total
amount due from affiliates of JMC Selkirk, Inc. for sales of gas at June 30,
2002 was approximately $1.0 million.
In May 1996, the Partnership entered into an enabling agreement with PG&E
Energy Trading – Power, L.P., an affiliate of JMC Selkirk, Inc., to
purchase and sell electric capacity, electric energy, and other electric-related
products. For the six months ended June 30, 2002 and 2001, sales to PG&E
Energy Trading – Power, L.P. totaled approximately $1.4 million and $3.5
million, respectively. Sales to PG&E Energy Trading – Power, L.P. were
recorded as electric revenues in the accompanying consolidated statements of
operations. The total amount due from PG&E Energy Trading – Power, L.P.
at June 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 six months ended June 30,
2002, firm fuel transportation services from IGTS totaled approximately $3.7
million and $3.8 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 June 30, 2002, was approximately $0.7
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 June 30, 2002 and 2001, amounts charged to
fuel costs as a result of losses realized from these contracts totaled
approximately $0.8 million and $0.7 million, respectively. For the six months
ended June 30, 2002 and 2001, amounts charged to fuel costs as a result of
losses realized from these contracts totaled approximately $1.7 million and $1.5
million, respectively. The Partnership expects that net derivative losses of
approximately $2.6 million, included in accumulated other comprehensive loss as
of June 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.
7
The schedule below summarizes the activities affecting accumulated other
comprehensive loss from derivative contracts for the three months and six months
ended June 30, 2002 and 2001 (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
2002 2001 2002 2001
------------- ------------- ------------- -------------
Beginning accumulated other comprehensive $ (7.9) $ (10.0) $ (8.8) $ (9.0)
loss at April 1 and January 1,
respectively
Net gain (loss) from current period hedging
transactions 1.4 0.7 1.4 (1.1)
Net reclassification to earnings 0.8 0.7 1.7 1.5
------------- ------------- ------------- -------------
Ending accumulated other comprehensive loss $ (5.7) $ (8.6) $ (5.7) $ (8.6)
============= ============= ============= =============
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.
As of June 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.
Note 5. 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 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").
8
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. Subsequent to the bankruptcy filing, the investment
grade ratings of NEG were reaffirmed on April 6 and 9, 2001. On July 31, 2002,
S&P downgraded NEG to BB+ with CreditWatch with negative implications from
BBB with a stable outlook. On August 5, 2002, Moody’s downgraded NEG to Ba2
from Baa2 and maintained its negative rating outlook. Neither agency took any
ratings action with respect to the rating of the Partnership’s debt.
The Managing General Partner believes that the credit rating agency action will
have no impact on the financial condition or results of operations of the
Partnership. In addition, 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.
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, it is too early for the
Partnership to 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.
9
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 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 Six Months Ended June 30, 2002 Compared to the Three and Six Months
Ended June 30, 2001
The Partnership earned net income of approximately $2.7 million for the three
months ended June 30, 2002 as compared to approximately $5.9 million for the
corresponding period in the prior year. The Partnership earned net income of
approximately $12.1 million for the six months ended June 30, 2002 as compared
to approximately $16.5 million for the corresponding period in the prior year.
The $3.2 million and $4.4 million decreases in net income for the three and six
months ended June 30, 2002, respectively were primarily due to lower gross
profit resulting from differences in the scheduling and scope of planned
maintenance.
Total operating revenues for the three and six months ended June 30, 2002 were
approximately $53.4 million and $106.4 million as compared to approximately
$57.7 million and $124.1 million for the corresponding periods in the prior
year.
Electric Revenues (dollars and kWh's in millions):
For the Three Months Ended June 30, 2002 June 30, 2001 ----------------------------------------- ---------------------------------------- Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch ------- ----- -------- -------- ------- ------ -------- -------- Unit 1 12.7 159.9 91.7% 95.2% 10.4 84.8 48.6% 51.5% Unit 2 32.3 325.0 56.2% 57.8% 35.7 391.1 67.6% 73.3%
10
Electric Revenues (dollars and kWh's in millions) (continued):
- --------------------------------------------------------------
For the Six Months Ended
June 30, 2002 June 30, 2001
------------------------------------- -------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ------ -------- --------
Unit 1 27.6 338.4 97.8% 97.6% 28.3 187.8 54.1% 56.0%
Unit 2 66.8 777.9 67.6% 77.7% 78.7 909.8 79.0% 84.2%
Unit 1 Electric Revenues (dollars in millions):
- -----------------------------------------------
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Niagara Mohawk $ 6.5 $ 6.6 $ 16.4 $ 19.0
ISO 6.1 3.6 11.1 5.8
PG&E Energy Trading 0.1 0.2 0.1 3.5
------------- ------------- ------------- -------------
$ 12.7 $ 10.4 $ 27.6 $ 28.3
============= ============= ============= =============
The $2.3 million increase in Unit 1 electric revenues for the three months ended
June 30, 2002 was primarily due to higher volumes of delivered energy, partially
offset by lower market energy prices. The lower volume of delivered energy for
the three months ended June 30, 2001 resulted from a seven week scheduled
maintenance outage. The $0.7 million decrease in Unit 1 electric revenues for
the six months ended June 30, 2002 was primarily due to lower fuel index pricing
in the energy component of the Niagara Mohawk Power Corporation (“Niagara
Mohawk”) monthly contract payment and lower market energy prices, partially
offset by higher volumes of delivered energy. 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”), were sold at negotiated market prices.
Unit 2 Electric Revenues (dollars in millions):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------------ ----------------------------
2002 2001 2002 2001
------------- ------------- ------------- -------------
Con Edison $ 32.3 $ 34.6 $ 65.4 $ 77.6
ISO --- 0.7 0.1 0.7
PG&E Energy Trading --- --- 1.3 ---
Unrelated third party --- 0.4 --- 0.4
------------- ------------- ------------- -------------
$ 32.3 $ 35.7 $ 66.8 $ 78.7
============= ============= ============= =============
11
The $3.4 million and $11.9 million decreases in Unit 2 electric for the three
and six months ended June 30, 2002, respectively were 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 six months ended June 30, 2002 of approximately
$0 and $0.2 million were reduced by a reserve of approximately $0.1 million and
$0.2 million, respectively. Steam revenues for the three and six months ended
June 30, 2001 of approximately $0 and $0.6 million were reduced by a reserve of
approximately $0.2 million. 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 three and six months ended June 30, 2002 was primarily due to a decrease in
steam sales in excess of the Discounted Quantity to General Electric. Delivered
steam for the three months ended June 30, 2002 was approximately 301.5 million
pounds or 138,048 lbs/hr as compared to approximately 328.2 million pounds or
150,267 lbs/hr for the corresponding period in the prior year. Delivered steam
for the six months ended June 30, 2002 was approximately 669.2 million pounds or
154,051 lbs/hr as compared to approximately 761.0 million pounds or 174,229
lbs/hr for the corresponding period in the prior year.
Fuel Revenues (dollars and MMBtu's in millions):
For the Three Months Ended June 30, 2002 June 30, 2001 --------------------------------- ------------------------------- Dollars MMBtu's Dollars MMBtu's ------- ------- ------- ------- Gas Resales 7.2 2.0 11.3 2.0 Fuel Optimizations 1.3 0.3 0.4 0.1 Peak Shaving Arrangements --- --- --- --- --------------- ------------- ------------- -------------- 8.5 2.3 11.7 2.1 =============== ============= ============= ============== For the Six Months Ended June 30, 2002 June 30, 2001 --------------------------------- ------------------------------- Dollars MMBtu's Dollars MMBtu's ------- ------- ------- ------- Gas Resales 8.7 2.6 14.8 2.6 Fuel Optimizations 2.8 0.9 1.3 0.2 Peak Shaving Arrangements 0.5 --- 0.5 --- --------------- ------------- ------------- -------------- 12.0 3.5 16.6 2.8 =============== ============= ============= ==============
The $3.2 million and $4.6 million decreases in fuel revenues for the three and
six months ended June 30, 2002, respectively were primarily due to lower market
natural gas prices, partially offset by higher volumes of natural gas sold under
fuel optimizations.
12
Fuel and Transmission Costs (dollars and MMBtu's in millions):
- --------------------------------------------------------------
For the Three Months Ended
June 30, 2002 June 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 24.6 6.9 29.8 6.8
Fuel Optimizations 1.2 0.3 0.4 0.1
Transmission Costs 1.9 --- 2.2 ---
--------------- -------------- ------------ --------------
27.7 7.2 32.4 6.9
=============== ============== ============ ==============
For the Six Months Ended
June 30, 2002 June 30, 2001
---------------------------------- ------------------------------
Dollars MMBtu's Dollars MMBtu's
------- ------- ------- -------
Fuel Supply and
Transportation* 45.4 13.6 67.5 13.8
Fuel Optimizations 2.7 0.9 1.3 0.2
Transmission Costs 3.8 --- 4.1 ---
--------------- -------------- ------------ --------------
51.9 14.5 72.9 14.0
=============== ============== ============ ==============
* Includes the cost of fuel associated with the production of electricity and gas resales.
The $4.7 million and $21.0 million decreases in fuel and transmission costs for
the three and six months ended June 30, 2002, respectively were primarily due to
the lower price of natural gas under the firm fuel supply contracts. 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 six months ended June 30, 2002 were increased by
approximately $0.8 million and $1.7 million as compared to approximately $0.7
million and $1.5 million for the corresponding periods in the prior year.
Unrealized loss on derivative contracts for the three and six months ended June
30, 2002 was approximately zero and $0.4 million as compared to zero 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 six months ended June
30, 2002 were approximately $10.8 million and $17.3 million as compared to
approximately $7.2 million and $10.5 million for the corresponding periods in
the prior year. The $3.6 million and $6.8 million increases in other operating
and maintenance expenses for the three and six months ended June 30, 2002,
respectively, 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.
13
Liquidity and Capital Resources
Net cash provided by operating activities for the three and six months ended
June 30, 2002 was approximately $0.4 million and $20.5 million as compared to
approximately $5.3 million and $24.1 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 used in investing activities for the three and six months ended June
30, 2002 was approximately $1.9 million and $2.1 million as compared to
approximately $0.6 million and $0.9 million for the corresponding periods in the
prior year. Net cash used in investing activities primarily represents additions
to plant and equipment.
Net cash provided by (used in) financing activities for the three and six months
ended June 30, 2002 was approximately $1.3 million and $(21.3) million as
compared to approximately $(3.5) million and $(23.6) 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 provided by (used in) financing activities during the
three and six months ended June 30, 2002 and 2001 primarily represent
distributions to partners and the semi-annual payment of principal and interest
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 during 2002.
Market Risk
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 three and six
months ended June 30, 2002 would have resulted in a negative impact of
approximately $26.0 thousand and $46.7 thousand on the Partnership’s net
income.
14
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 three and six months ended June 30, 2002, the currency
exchange rate differential resulted in a negative impact of approximately $0.8
million and $1.7 million 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.
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 June 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.
15
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.
In 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.
16
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.
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, it is too early for the
Partnership to 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.
17
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.)
18
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) Exhibits
Exhibit No. Description
----------- -----------
10.6.20 Firm Transportation Negotiated Rate Letter Agreement, dated as of
June 18, 2002, between Tennessee Gas Pipeline Company and
Selkirk Cogen Partners, L.P.
10.6.21 Agreement under FT-a Rate Schedule, dated as of June 19, 2002,
between Tennessee Gas Pipeline Company and Selkirk Cogen
Partners, L.P.
10.6.22 Gas Transportation Agreement, dated as of August 1, 2002,
between Tennessee Gas Pipeline Company and Selkirk Cogen
Partners, L.P.
99.5 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated August 14, 2002.
99.6 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated August 14, 2002.
99.7 Certification of P. Chrisman Iribe pursuant to 18 U.S.C. Section
1350 dated August 14, 2002.
99.8 Certification of John R. Cooper pursuant to 18 U.S.C. Section
1350 dated August 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.
19
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: August 14, 2002 /s/ JOHN R. COOPER
-------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
20
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 14, 2002 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President,
Chief Financial Officer and
Treasurer
21