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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
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. Yes X No __
As of November 12, 1999, there were 10 shares of common stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.
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<PAGE>
TABLE OF CONTENTS
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of
September 30, 1999 and December 31, 1998................ 3
Condensed Consolidated Statements of Operations
for the three and nine months ended September 30,
1999 and 1998........................................... 4
Condensed Consolidated Statements of Cash Flows
for the three and nine months ended September 30,
1999 and 1998........................................... 5
Notes to Condensed Consolidated Financial Statements.... 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Results of Operations................................... 7
Liquidity and Capital Resources......................... 10
Item 3. Quantitative and Qualitative Disclosures About
Market Risk ............................................ 14
PART II. OTHER INFORMATION
Item 5. Other Items............................................. 15
Item 6. Exhibits and Reports on Form 8-K........................ 15
SIGNATURES........................................................ 16
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SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
(unaudited)
September 30, December 31,
1999 1998
------------- ------------
<S> <C> C>
ASSETS
Current assets:
Cash and cash equivalents................................... $ 1,169 $ 1,839
Current portion of restricted funds......................... 24,519 4,185
Accounts receivable......................................... 15,118 14,281
Due from affiliates......................................... 417 743
Fuel inventory and supplies................................. 5,284 5,033
Other current assets........................................ 466 333
---------- ----------
Total current assets.................................. 46,973 26,414
Plant and equipment, net........................................ 299,965 308,999
Restricted funds, less current portion.......................... 29,667 28,188
Deferred financing charges, net................................. 9,917 10,782
---------- ----------
Total Assets $ 386,522 $ 374,383
---------- ----------
---------- ----------
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable............................................ $ 239 $ 617
Accrued bond interest payable............................... 8,867 379
Accrued expenses............................................ 11,897 12,235
Due to affiliates........................................... 358 639
Current portion of long-term bonds.......................... 5,820 4,822
---------- ----------
Total current liabilities............................. 27,181 18,692
Deferred revenues............................................... 6,046 6,565
Other long-term liabilities..................................... 17,910 14,803
Long-term bonds, less current portion........................... 378,112 381,133
General partners' capital....................................... (416) (457)
Limited partners' capital....................................... (42,311) (46,353)
---------- ----------
Total partners' capital............................... (42,727) (46,810)
---------- ----------
Total Liabilities and Partners' Capital $ 386,522 $ 374,383
---------- ----------
---------- ----------
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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<TABLE>
<CAPTION>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
(unaudited)
For the Three Months Ended For the Nine Months Ended
------------------------------ -------------------------------
<S> <C> <C> <C> <C>
September 30, September 30, September 30, September 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
Operating revenues:
Electric and steam................................. $ 45,564 $ 43,251 $ 124,484 $ 120,599
Gas resale......................................... 939 170 5,306 5,348
------------ ------------- ------------- -------------
Total operating revenues..................... 46,503 43,421 129,790 125,947
Cost of revenue..................................... 29,299 27,435 84,186 84,313
------------ ------------- ------------- -------------
Gross profit........................................ 17,204 15,986 45,604 41,634
Other operating expenses:
Administrative services - affiliates............... 563 17 1,321 1,338
Other general and administrative expenses.......... 323 250 1,205 1,346
Amortization of deferred financing charges......... 287 290 865 873
------------ ------------- ------------- -------------
Total other operating expenses............... 1,173 557 3,391 3,557
------------ ------------- ------------- -------------
Operating income.................................... 16,031 15,429 42,213 38,077
Interest (income) expense:
Interest income.................................... (549) (565) (1,629) (1,639)
Interest expense................................... 8,492 8,564 25,555 25,772
------------ ------------- ------------- -------------
Net interest expense 7,943 7,999 23,926 24,133
------------ ------------- ------------- -------------
Net Income.......................................... $ 8,088 $ 7,430 $ 18,287 $ 13,944
------------ ------------- ------------- -------------
------------ ------------- ------------- -------------
Allocated to:
General partners................................... $ 81 $ 75 $ 183 $ 140
Limited partners................................... 8,007 7,355 18,104 13,804
------------ ------------- ------------- -------------
Total........................................ $ 8,088 $ 7,430 $ 18,287 $ 13,944
------------ ------------- ------------- -------------
------------ ------------- ------------- -------------
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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<PAGE>
<TABLE>
<CAPTION>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
For the Three Months Ended For the Nine Months Ended
------------------------------- -------------------------------
September 30, September 30, September 30, September 30,
1999 1998 1999 1998
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Net cash provided by operating activities.................... $ 20,387 $ 27,074 $ 35,777 $ 39,120
Cash flows provided by (used in) investing activities:
Plant and equipment additions............................ --- --- (310) (14)
-------- --------- ---------- -----------
Net cash used in investing activities................. --- --- (310) (14)
Cash flows provided by (used in) financing activities:
Cash distributions....................................... (970) (5,665) (14,204) (8,992)
Payments of principal on long-term debt.................. --- --- (2,023) (1,881)
Restricted funds......................................... (19,910) (21,851) (19,910) (28,646)
-------- --------- ---------- -----------
Net cash used in financing activities............... (20,880) (27,516) (36,137) (39,519)
Net decrease in cash and equivalents......................... (493) (442) (670) (413)
Cash and cash equivalents at beginning of period............. 1,662 1,366 1,839 1,337
-------- --------- ---------- -----------
Cash and cash equivalents at end of period................... $ 1,169 $ 924 $ 1,169 $ 924
-------- --------- ---------- -----------
-------- --------- ---------- -----------
Supplemental disclosures of cash flow information:
Cash paid for interest................................... $ --- $ --- $ 17,067 $ 17,210
-------- --------- ---------- -----------
-------- --------- ---------- -----------
The accompanying notes are an integral part of these condensed
consolidated financial statements.
</TABLE>
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SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Basis of Presentation
The accompanying unaudited condensed 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 condensed 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. The information furnished
in the condensed 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 information and footnote
disclosures normally included in financial statements prepared in accordance
with generally accepted accounting principles have been condensed or omitted
pursuant to rules and regulations applicable to interim financial statements.
These condensed consolidated financial statements should be read in conjunction
with the audited consolidated financial statements included in the Partnership's
December 31, 1998 Annual Report on Form 10-K.
Note 2. New Accounting Pronouncements
In June 1998, the FASB issued SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 133 establishes accounting and
reporting standards for derivative instruments. It requires that all derivative
instruments be recognized in the balance sheets as assets or liabilities
measured at fair value. Changes in the fair value of derivative instruments are
recognized as gains or losses in the statement of operations or as a component
of other comprehensive income. SFAS No. 133 is effective for fiscal years
beginning after June 15, 2000. Management has not yet evaluated the impact
adopting SFAS No. 133 may have on the Partnership's financial statements.
6
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Results of Operations
- ---------------------
Three and Nine Months Ended September 30, 1999 Compared to the Three and Nine
Months Ended September 30, 1998
- --------------------------------------------------------------------------------
Net income for the quarter ended September 30, 1999 was approximately $8.1
million as compared to approximately $7.4 million for the corresponding period
in the prior year. The $0.7 million increase in net income is primarily due to
an increase in gross profit (offset in part by an increase in other operating
expenses). Net income for the nine months ended September 30, 1999 was
approximately $18.3 million as compared to approximately $13.9 million for the
corresponding period in the prior year. The $4.4 million increase in net income
is primarily due to an increase in Unit 1 operating revenues.
Total revenues for the quarter and nine months ended September 30, 1999 were
approximately $46.5 million and $129.8 million as compared to approximately
$43.4 million and $125.9 million for the corresponding periods in the prior
year, respectively.
Electric Revenues (dollars and kWh's in millions):
<TABLE>
<CAPTION>
For the Three Months Ended
September 30, 1999 September 30, 1998
------------------------------------ -------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 12.4 144.5 84.19% 99.28% 11.7 152.2 86.36% 100.00%
Unit 2 33.3 539.5 92.20% 96.65% 31.5 575.2 98.30% 98.87%
For the Nine Months Ended
September 30, 1999 September 30, 1998
------------------------------------- --------------------------------------
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 32.2 423.0 82.84% 96.64% 27.0 313.4 59.77% 67.98%
Unit 2 91.9 1,402.5 80.78% 86.40% 93.5 1,599.4 92.12% 95.88%
</TABLE>
Revenues from Unit 1 increased approximately $0.7 million and $5.2 million for
the quarter and nine months ended September 30, 1999 as compared to the
corresponding periods in the prior year, respectively. During the quarter and
nine months ended September 30, 1999 revenues from Niagara Mohawk Power
Corporation ("Niagara Mohawk") were approximately $9.3 million and $27.5
million, respectively, and revenues from PG&E Energy Trading - Power, L.P.
("PG&E Energy Trading") were approximately $3.1 million and $4.7 million,
respectively. During the nine months ended September 30, 1998 all revenues from
Unit 1 were from Niagara Mohawk. The increase in revenues from Unit 1 for the
quarter ended September 30, 1999 was primarily due to
7
<PAGE>
higher market energy prices. The increase in revenues from Unit 1 for the nine
months ended September 30, 1999 was primarily due to the increase in delivered
energy as evidenced by the increase in the capacity factor for the period and
improved contract pricing resulting from the execution of the Amended and
Restated Niagara Mohawk Power Purchase Agreement on August 31, 1998. In
conjunction with the execution of the Amended and Restated Niagara Mohawk Power
Purchase Agreement, Niagara Mohawk no longer has the right to direct the
dispatch of Unit 1. During the nine months ended September 30, 1999, with the
exception of April 1999, the Partnership received Monthly Contract Payments and
delivered energy up to the monthly contract quantity to Niagara Mohawk. During
the month of January 1999 the Partnership sold all of the Excess Energy
generated from Unit 1 to Niagara Mohawk. During the months of February, March,
June and September 1999 the Partnership sold all of the Excess Energy generated
from Unit 1 to PG&E Energy Trading. During the months of April, May, July and
August 1999 the Partnership sold Excess Energy from Unit 1 to both Niagara
Mohawk and PG&E Energy Trading. Excess Energy delivered to Niagara Mohawk and
PG&E Energy Trading was sold at negotiated market prices. Amortized deferred
revenues of approximately $0.5 million are also included in revenues from
Niagara Mohawk during the nine months ended September 30, 1999.
During the nine months ended September 30, 1998, with the exception of March and
April, Niagara Mohawk dispatched Unit 1 on-line. Energy delivered during most of
January and the entire months of February, July, August and September was sold
at full contract rates. Energy delivered during the first four days of January
and the entire months of May and June was sold under special dispatch
arrangements which called for the pricing of delivered energy at variable rates
which were less than full contract rates. If the Partnership had not entered
into special dispatch arrangements, the Unit would have otherwise been
dispatched off-line during the relevant periods.
Revenues from Unit 2 increased approximately $1.8 million and decreased
approximately $1.6 million for the quarter and nine months ended September 30,
1999 as compared to the corresponding periods in the prior year, respectively.
During the quarter and nine months ended September 30, 1999, revenues from
Consolidated Edison Company of New York, Inc. ("Con Edison") were $33.3 million
and $91.6 million, respectively, and revenues from PG&E Energy Trading was
approximately $0.3 million for the nine months ended September 30, 1999. During
the quarter and nine months ended September 30, 1998, revenues from Con Edison
were $31.5 million and $93.5 million, respectively, and revenues from PG&E
Energy Trading were approximately $73,500 and $148,500, respectively. The
increase in revenues from Unit 2 for the quarter ended September 30, 1999 was
primarily due to the increase in the Con Edison contract price for delivered
energy resulting from higher index fuel prices. The decrease in revenues from
Unit 2 for the nine months ended September 30, 1999 was primarily due to the
decrease in delivered energy as evidenced by the decrease in the capacity factor
for the period. During the nine months ended September 30, 1999, revenue from
PG&E Energy Trading was the result of the sale of other energy-related products.
During the nine months ended September 30, 1998, revenue from PG&E Energy
Trading was the result of the sales of generated
8
<PAGE>
capacity and energy in excess of the contract amount due under the Con Edison
Power Purchase Agreement.
There were no steam revenues for the quarter ended September 30, 1999 however, a
reserve of approximately $144,000 was recorded to reflect the estimated annual
true-up so that General Electric would be charged a nominal amount which is the
annual equivalent of 160,000 lbs/hr. Steam revenues for the nine months ended
September 30, 1999 of $0.6 million were reduced by a reserve of approximately
$0.2 million to reflect the estimated annual true-up. There were no steam
revenues for the quarter ended September 30, 1998. Steam revenues for the nine
months ended September 30, 1998 of approximately $0.2 million were reduced by a
reserve of the same amount to reflect the estimated annual true-up. Delivered
steam for the quarter and nine months ended September 30, 1999 was approximately
313.6 million pounds and 1,126.8 million pounds as compared to approximately
285.5 million pounds and 969.0 million pounds for the corresponding periods in
the prior year, respectively. The increase in steam revenues for the quarter and
nine months ended September 30, 1999 was primarily due to the increase in
delivered steam.
Gas resale revenues for the quarter ended September 30, 1999 were approximately
$0.9 million on sales of approximately 0.4 million MMBtu's as compared to
approximately $0.2 million on sales of approximately 0.1 million MMBtu's for the
corresponding period in the prior year. The $0.7 million increase in gas resale
revenues during the quarter ended September 30, 1999 is primarily due to higher
natural gas resale prices and the lower dispatch of Unit 2, 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 ended September 30,
1999 generally resulted from higher market pricing for both gas and oil as well
as increased demands for electric generation. The increased market activity was
also in direct response to the extremely active hurricane season and warmer than
normal temperatures. Gas resale revenues for the nine months ended September 30,
1999 and 1998 were approximately $5.3 million on sales of approximately 2.3
million MMBtu's. Gas resales occur during periods when Units 1 and 2 were not
operating at full capacity.
Cost of revenues for the quarter ended September 30, 1999 was approximately
$29.3 million on gas purchases of approximately 7.1 million MMBtu's as compared
to $27.4 million on gas purchases of approximately the same number of units
during the corresponding period in the prior year. The largest component of the
increase for the quarter ended September 30, 1999 was fuel costs, which
increased approximately $2.0 million from the corresponding period in the prior
year. The increase in the cost of fuel was primarily due to the higher price of
gas under the firm fuel contracts. Cost of revenues for the nine months ended
September 30, 1999 was approximately $84.2 million on gas purchases of
approximately 21.0 million MMBtu's as compared $84.3 million on gas purchases of
approximately 21.1 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 nine months ended September 30, 1999
and
9
<PAGE>
1998, fuel costs were increased by approximately $1.8 million and $1.7 million,
respectively, as a result of the currency swap agreements.
Total other operating expenses for the quarter and nine months ended September
30, 1999 were approximately $1.2 million and $3.4 million as compared to
approximately $0.6 million and $3.6 million for the corresponding periods in the
prior year, respectively. The increase in other operating expenses for the
quarter ended September 30, 1999 was primarily due to higher affiliate
administrative services. The decrease in other operating expenses for the nine
months ended September 30, 1999 was primarily due to lower other general and
administrative expenses.
Net interest expense for the quarter and nine months ended September 30, 1999 of
approximately $7.9 million and $23.9 million was comparable to the corresponding
periods in the prior year.
Liquidity and Capital Resources
- -------------------------------
Net cash provided by operating activities for the quarter ended September 30,
1999 was approximately $20.4 million as compared to approximately $27.1 million
for the corresponding period in the prior year. Net cash provided by operating
activities for the nine months ended September 30, 1999 was approximately $35.8
million as compared to approximately $39.1 million for the corresponding period
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 provided by operating activities for the quarter ended
September 30, 1998 included the net activity of approximately $6.9 million which
resulted from the execution of the Amended and Restated Niagara Mohawk Power
Purchase Agreement on August 31, 1998.
No cash was used in investing activities for the quarters ended September 30,
1999 and 1998. Net cash used in investing activities for the nine months ended
September 30, 1999 was approximately $310,000 as compared to approximately
$14,000 for the corresponding period in the prior year. Net cash used in
investing activities primarily represents additions to plant and equipment.
Net cash used in financing activities for the quarter ended September 30, 1999
was approximately $20.9 million as compared to approximately $27.5 million for
the corresponding period in the prior year. Net cash used in financing
activities for the nine months ended September 30, 1999 was approximately $36.1
million as compared to approximately $39.5 million for the corresponding period
in the prior year. The decrease in net cash used in financing activities for the
quarter ended September 30, 1999 was primarily due to the decrease in cash
distributions to the Partners. The decrease in net cash used in financing
activities for the nine months ended September 30, 1999 was primarily due to
decreases in cash deposited into the Partnership Distribution Fund and
10
<PAGE>
Debt Service Reserve Fund (offset in part by an increase in cash distributions
to the Partners).
In 1994 and 1995 Con Edison claimed the right to acquire that portion of Unit
2's firm natural gas supply not used in operating Unit 2, when Unit 2 is
dispatched off-line or at less than full capability ("non-plant gas"), or
alternatively to be compensated for 100% of the margins derived from non-plant
gas sales. The Con Edison Power Purchase Agreement contains no express language
granting Con Edison any rights with respect to such excess natural gas.
Nevertheless, Con Edison argued that, since payments under the contract include
fixed fuel charges which are payable whether or not Unit 2 is dispatched
on-line, Con Edison is entitled to exercise such rights. The Partnership
vigorously disputes the position adopted by Con Edison, and since the
commencement of Unit 2's operation in 1994 has made and continues to make, from
time to time, non-plant gas sales from Unit 2's gas supply. Although
representatives of Con Edison have expressly reserved all rights that Con Edison
may have to pursue its asserted claim with respect to non-plant gas sales, the
Partnership has received no further formal communication from Con Edison on this
subject since 1995. In the event Con Edison were to pursue its asserted claim,
the Partnership would expect to pursue all available legal remedies, but there
can be no certainty that the outcome of such remedial action would be favorable
to the Partnership or, if favorable, would provide for the Partnership's full
recovery of its damages. The Partnership's cash flows from the sale of electric
output would be materially and adversely affected if Con Edison were to prevail
in its claim to Unit 2's excess natural gas volumes and the related margins.
On July 21, 1998 the New York Public Service Commission ("NYPSC") approved a
plan submitted by Con Edison for the divestiture of certain of its generating
assets (the "Con Edison Divestiture Plan"). Although the Con Edison Divestiture
Plan does not include any proposal by Con Edison for the sale or other
disposition of its contractual obligations for purchasing power from non-utility
generators, like the Partnership, the NYPSC has ordered Con Edison to submit a
report regarding the feasibility of divesting its non-utility generator
entitlements. At this time, the Partnership has insufficient information to
determine whether, in the course of these proceedings at the NYPSC, Con Edison
may seek to assign its rights and obligations under the Con Edison Power
Purchase Agreement with the Partnership to a third party or to take some other
action for the purpose of divesting itself of the power purchase obligations
under such contract; nor can the Partnership evaluate the impact which any such
assignment or other action, if proposed, may ultimately have on the Con Edison
Power Purchase Agreement.
Future operating results and cash flows from operations are also dependent on,
among other things, the performance of equipment; levels of dispatch; the
receipt of certain capacity and other fixed payments; electricity prices;
natural gas resale prices; and fuel deliveries and prices. A significant change
in any of these factors could have a material adverse effect on the results of
operations for the Partnership.
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The Partnership believes based on current conditions and circumstances, that it
will have sufficient cash flows from operations to fund existing debt
obligations and operating costs.
Year 2000
- ---------
The Year 2000 issue exists because many computer programs use only two digits to
indicate the year in a date, and was developed without considering the impact of
the upcoming change in the century. The Partnership has a program in place to
address its exposure to the Year 2000 issue. This program is designed to
minimize the possibility of significant Year 2000 interruptions.
In 1998, the Partnership established the program to address its software and
hardware product and customer concerns, its internal business systems, including
technology infrastructure and embedded technology systems, and the compliance of
its suppliers. This program includes the following phases: inventory and
assessment, remediation, testing, and certification. Certification occurs when
mission-critical software and hardware products are determined to be "Year 2000
Ready." The "Year 2000 Ready" category indicates that the Partnership has
determined that the product, when used in its designated manner, will not
terminate abnormally or give incorrect results with respect to date data before,
during or after December 31, 1999. Once Year 2000 Ready, additional standards
and processes are imposed to prevent systems from being compromised.
The Partnership's Year 2000 certification phase was completed in April 1999. The
Partnership will continue to perform work associated with contingency planning
implementation, and the assessment and remediation of non-mission critical items
through the end of 1999. The Partnership determined that its only
mission-critical software was vendor software. As to mission-critical vendor
software, Year 2000 ready upgrades have been obtained from the vendors, tested
as appropriate and deemed Year 2000 Ready.
The Partnership has tested remediated software and embedded systems both for
ability to handle Year 2000 dates, including appropriate leap year calculations,
and to assure that code repair has not affected the base functionality of the
code. Software and embedded systems were tested on an integrated and unit basis.
The integrated system test was intended to replicate the Partnership's typical
processes with dates and data advanced and aged to simulate Year 2000
operations. Unit tests supplement the integrated testing to evaluate remaining
functions that were not part of the integrated test. Testing, by its nature,
however, cannot comprehensively address all future combinations of dates and
events. Because some uncertainty remains after testing as to the ability of code
to process future dates, as well as the ability of remediated systems to work in
an integrated fashion with other systems, failure of such systems, should they
occur, could have a material adverse impact on future results.
12
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In addition to internal systems, the Partnership depends upon external parties,
including customers, suppliers, business partners, gas and electric system
operators, government agencies, and financial institutions to support the
functioning of its business. To the extent that any of these parties are
considered mission-critical to the Partnership's business and experience Year
2000 problems in their systems, the Partnership's mission-critical business
functions may be adversely affected. To deal with this vulnerability, the
Partnership has another phased approach. The primary phases for dealing with
external parties are: (1) inventory, (2) action planning, (3) risk assessment,
and (4) contingency planning.
In April 1999, the Partnership completed its inventory, action planning, risk
assessment and contingency planning phases for mission-critical external
parties.
Although the Partnership expects its efforts and those of its external parties
to be largely successful, the Partnership recognizes that with the complex
interaction of today's computing and communication systems, it cannot be certain
the Partnership will be completely successful. Therefore, contingency plans have
been developed and tested through April 1999 to address its external
dependencies as well as exposure that could result from failures in our own
essential business functions. These plans have taken into account possible
interruptions of power, computing, financial, and communications
infrastructures. Contingency plans will be revised throughout 1999 as necessary.
Due to the uncertainty inherent in the contingencies for which plans are being
prepared, however, it is uncertain whether these plans will be sufficient to
remove the risk of material impacts on the Partnerships operations resulting
from Year 2000 problems.
Through October 1999, the Partnership spent approximately $520,000 to assess,
remediate and test Year 2000 problems for both mission critical and non-mission
critical items. This amount includes $148,000 of affiliate related labor costs
whereas, these costs were not included in previous reports. The Partnership's
estimate of future costs to address Year 2000 issues is approximately $20,000 to
implement contingency plans and to address remaining non-mission critical items;
all of which will be expensed.
The Partnership has concluded that the most reasonably likely worst case Year
2000 scenarios that could affect its business include localized telephone
problems due to congestion and small isolated malfunctions in the Partnership's
computer systems that would be immediately repaired. The Partnership has
developed contingency plans to address these scenarios.
If third parties with whom the Partnership has significant business
relationships, fail to achieve Year 2000 readiness of mission-critical systems,
there could be a material adverse impact on the Partnership's financial
position, results of operations, and cash flows.
13
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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; whether Con Edison were to prevail in its claim to Unit 2's excess
natural gas volumes, and the related margins and issues related to Year 2000
compliance.
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Partnership is exposed to market risk from changes in interest rates and
foreign currency exchange rates, which could affect its future results of
operations and financial condition. The Partnership manages its exposure to
these risks through its regular operating and financing activities.
Interest Rates
The Partnership's cash and restricted cash are sensitive to changes in interest
rates. Interest rate changes would result in a change in interest income due to
the difference between the current interest rates on cash and restricted cash
and the variable rate that these financial instruments may adjust to in the
future. A 10% decrease in interest rates for the quarter and nine months ended
September 30, 1999 would have resulted in a negative impact of approximately
$55,000 and $163,000, respectively on the Partnership's net income for that
period.
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 the Canadian currency. In the
event a counterparty fails to meet the terms of the agreements, the
Partnership's exposure is limited to the currency exchange rate differential.
During the quarter and nine months ended September 30, 1999 the exchange rate
differential had a negative impact of approximately $0.6 million and $1.8
million, respectively on the Partnership's net income.
14
<PAGE>
PART II. OTHER INFORMATION
ITEM 5. OTHER ITEMS
Douglas F. Egan, Senior Vice President, resigned on November 5, 1999.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) Exhibits
Exhibit No. Description
27 Financial Data Schedule
(For electronic filing purposes only)
(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
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN PARTNERS, L.P.
JMC SELKIRK, INC.
General Partner
Date: November 15, 1999 /s/ JOHN R. COOPER
--------------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
16
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SELKIRK COGEN FUNDING
CORPORATION
Date: November 15, 1999 /s/ JOHN R. COOPER
------------------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
17
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