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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q/A
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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 October 13, 1999, there were 10 shares of common stock of Selkirk
Cogen Funding Corporation, $1 par value outstanding.
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<PAGE>
TABLE OF CONTENTS
Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (unaudited)
Condensed Consolidated Balance Sheets as of June 30, 1999
and December 31, 1998.................................... 3
Condensed Consolidated Statements of Operations for
the three and six months ended June 30, 1999 and 1998.... 4
Condensed Consolidated Statements of Cash Flows for
the three and six months ended June 30, 1999 and 1998.... 5
Notes to Condensed Consolidated Financial Statements..... 6
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
Results of Operations.................................... 7
Liquidity and Capital Resources.......................... 10
Item 3. Quantitative and Qualitative Disclosures About
Market Risk ............................................. 14
PART II. OTHER INFORMATION
Item 5. Other Items.............................................. 15
Item 6. Exhibits and Reports on Form 8-K......................... 16
SIGNATURES........................................................... 17
2
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SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
<TABLE>
<CAPTION>
<S> <C> <C>
(unaudited)
June 30, December 31,
1999 1998
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents..................$ 1,662 $ 1,839
Restricted funds........................... 5,238 4,185
Accounts receivable........................ 15,014 14,281
Due from affiliates........................ 556 743
Fuel inventory and supplies................ 4,996 5,033
Other current assets....................... 274 333
------- ------
Total current assets.................... 27,740 26,414
Plant and equipment, net....................... 303,072 308,999
Long-term restricted funds..................... 29,222 28,188
Deferred financing charges, net................ 10,205 10,782
------- -------
Total Assets $370,239 $ 374,383
------- -------
------- -------
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable...........................$ 263 $ 617
Accrued bond interest payable.............. 375 379
Accrued expenses........................... 11,919 12,235
Due to affiliates.......................... 366 639
Current portion of long-term bonds......... 5,820 4,822
------- -------
Total current liabilities............. 18,743 18,692
Deferred revenues.............................. 6,219 6,565
Other long-term liabilities.................... 17,010 14,803
Long-term bonds, less current portion.......... 378,112 381,133
General partners' capital...................... (487) (457)
Limited partners' capital...................... (49,358) (46,353)
-------- --------
Total partners' capital............... (49,845) (46,810)
-------- --------
Total Liabilities and Partners' Capital $ 370,239 $ 374,383
------- -------
------- -------
The accompanying notes are an integral part of these condensed consolidated
financial statements.
3
</TABLE>
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
(unaudited)
<TABLE>
<CAPTION>
For the Three Months Ended For the Six Months Ended
-------------------------- ------------------------
<S> <C> <C> <C>
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
-------- -------- -------- --------
Operating revenues:
Electric and steam.................... $ 37,684 $ 37,930 $ 78,920 $ 77,348
Gas resale............................ 3,280 3,187 4,367 5,178
-------- -------- -------- --------
Total operating revenues......... 40,964 41,117 83,287 82,526
Cost of revenue.......................... 29,782 28,770 54,887 56,878
-------- -------- -------- --------
Gross profit............................. 11,182 12,347 28,400 25,648
Other operating expenses:
Administrative services - affiliates.. 520 734 758 1,321
Other general and administrative expenses 423 552 882 1,096
Amortization of deferred financing charges. 289 292 578 583
-------- -------- -------- --------
Total other operating expenses 1,232 1,578 2,218 3,000
-------- -------- -------- --------
Operating income.......................... 9,950 10,769 26,182 22,648
Interest (income) expense:
Interest income........................ (582) (626) (1,080) (1,074)
Interest expense....................... 8,529 8,603 17,063 17,208
-------- -------- -------- --------
Net interest expense.............. 7,947 7,977 15,983 16,134
Net Income................................ $ 2,003 $ 2,792 $ 10,199 $ 6,514
-------- -------- -------- --------
-------- -------- -------- --------
Allocated to:
General partners....................... $ 20 $ 28 $ 102 $ 65
Limited partners 1,983 2,764 10,097 6,449
-------- -------- -------- --------
Total............................. $ 2,003 $ 2,792 $ 10,199 $ 6,514
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
<PAGE>
<TABLE>
<CAPTION>
SELKIRK COGEN PARTNERS, L.P.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)
For the Three Months Ended For the Six Months Ended
-------------------------- ------------------------
<S> <C> <C> <C> <C>
June 30, June 30, June 30, June 30,
1999 1998 1999 1998
-------- -------- -------- --------
Net cash provided by (used in)
operating activites......................... $ (1,162) $ (5,392) $15,390 $ 12,046
Cash flows provided by (used in)
investing activities:
Plant and equipment additions.......... (265) (14) (310) (14)
--------- --------- -------- ---------
Net cash used in investing activities.. (265) (14) (310) (14)
Cash flows provided by (used in)
financing activities:
Cash distributions........................ (13,234) (3,327) (13,234) (3,327)
Payments of principal on long-term debt... (2,023) (1,881) (2,023) (1,881)
Restricted Funds.......................... 16,945 7,199 --- (6,795)
--------- --------- -------- ---------
Net cash provided by (used in)
financing activities................ 1,688 1,991 (15,257) (12,003)
Net increase (decrease) in cash............... 261 (3,415) (177) 29
Cash at beginning of period................... 1,401 4,781 1,839 1,337
--------- --------- -------- ---------
Cash at end of period......................... $ 1,662 $ 1,366 $ 1,662 1,366
--------- --------- -------- ---------
--------- --------- -------- ---------
Supplemental disclosures of cash flow information:
Cash paid for interest...................... $ 17,067 $ 17,210 $ 17,067 $ 17,210
--------- --------- -------- ---------
--------- --------- -------- ---------
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
5
<PAGE>
SELKIRK COGEN PARTNERS, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Note 1. Basis of Presentation
The accompanying unaudited condensed consolidated financial statements
consolidate 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.
Certain reclassifications have been made to the Condensed Consolidated
Statements of Operations for the quarter and six months ended June 30, 1998 to
conform with the current period's basis of presentation.
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 requiring that every derivative instrument be recorded in
the balance sheet as either an asset or liability measured at its fair value.
Changes in the derivatives fair value must be recognized in the statement of
operations as a gain or loss unless specific hedge accounting criteria are met.
SFAS No. 133 is effective for fiscal years beginning after June 15, 2000. SFAS
No. 133 must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts. Management has not yet quantified the
impact of adopting SFAS No. 133 on the Partnership's financial statements.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Three and Six Months Ended June 30, 1999 Compared to the Three and Six Months
Ended June 30, 1998
Net income for the quarter ended June 30, 1999 was approximately $2.0 million as
compared to approximately $2.8 million for the corresponding period in the prior
year. The $0.8 million decrease in net income is primarily due to an increase in
maintenance expenses (offset in part by a decrease in other operating expenses).
Net income for the six months ended June 30, 1999 was approximately $10.2
million as compared to approximately $6.5 million for the corresponding period
in the prior year. The $3.7 million increase in net income is primarily due to
an increase in Unit 1 revenues and decreases in fuel costs and other operating
expenses.
Total revenues for the quarter and six months ended June 30, 1999 were
approximately $41.0 million and $83.3 million as compared to approximately $41.1
million and $82.5 million for the corresponding periods in the prior year.
Electric Revenues (dollars and kWh's in millions):
<TABLE>
<CAPTION>
For the Three Months Ended
June 30, 1999 June 30, 1998
---------------------------------------- ---------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 8.4 125.9 73.73% 91.62% 6.9 58.6 33.60% 39.10%
Unit 2 29.1 397.3 68.64% 73.67% 31.0 504.8 87.22% 94.78%
</TABLE>
<TABLE>
<CAPTION>
For the Six Months Ended
June 30, 1999 June 30, 1998
---------------------------------------- ---------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dollars kWh's Capacity Dispatch Dollars kWh's Capacity Dispatch
------- ----- -------- -------- ------- ----- -------- --------
Unit 1 19.8 278.6 82.15% 96.89% 15.2 161.2 46.45% 51.70%
Unit 2 58.6 863.0 74.97% 81.19% 62.1 1,024.2 88.97% 94.36%
</TABLE>
Revenues from Unit 1 increased approximately $1.5 million and $4.6 million for
the quarter and six months ended June 30, 1999 as compared to the corresponding
periods in the prior year, respectively. During the quarter and six months ended
June 30, 1999 revenues from Niagara Mohawk Power Corporation ("Niagara Mohawk")
were approximately $7.5 million and $18.2 million, respectively, and revenues
from PG&E Energy Trading - Power, L.P. ("PG&E Energy Trading") were
approximately $0.9 million and $1.6 million, respectively. During the six months
ended June 30, 1998 all revenues from Unit 1 were from Niagara Mohawk. The
increase in revenues from Unit 1 for the quarter and six months ended June 30,
1999 was primarily due to increases in delivered energy as evidenced by
increases in the capacity factor for the corresponding
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<PAGE>
periods 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 six months ended June 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
and June 1999 the Partnership sold all of the Excess Energy generated from Unit
1 to PG&E Energy Trading. During the months of April and May 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. Deferred revenues of approximately
$0.3 million are also included in revenues from Niagara Mohawk during the six
months ended June 30, 1999.
During the six months ended June 30, 1998, Niagara Mohawk dispatched Unit 1
on-line during January, February, May and June and off-line during March and
April. Energy delivered during most of January and the entire month of February
was sold at full contract rates. Energy delivered during the first four days of
January and the entire months of May and June were sold under special dispatch
arrangements which called for the pricing of delivered energy at variable rates
less than full contract rates. If the Partnership had not entered into special
dispatch arrangements, the Unit would have been otherwise dispatched off-line.
Revenues from Unit 2 decreased approximately $1.9 million and $3.5 million for
the quarter and six months ended June 30, 1999 as compared to the corresponding
periods in the prior year. During the quarter and six months ended June 30,
1999, revenues from Consolidated Edison Company of New York, Inc. ("Con Edison")
were $29.1 million and $58.3 million, respectively, and revenues from PG&E
Energy Trading were approximately $0 and $0.3 million, respectively. During the
quarter and six months ended June 30, 1998, revenues from Con Edison were $30.9
million and $62.0 million, respectively, and revenues from PG&E Energy Trading
were approximately $33.8 thousand and $75.0 thousand, respectively. The decrease
in revenues from Unit 2 for the quarter and six months ended June 30, 1999 was
primarily due to the decrease in the Con Edison contract price for delivered
energy resulting from lower index fuel prices and the decrease in delivered
energy as evidenced by decreases in the capacity factor for the corresponding
periods. During the six months ended June 30, 1999, revenues from PG&E Energy
Trading resulted from the sale of other energy-related products. During the six
months ended June 30, 1998, revenues from PG&E Energy Trading resulted from the
sale of generated capacity in excess of the contract amount due under the Con
Edison Power Purchase Agreement.
Steam revenues for the quarter and six months ended June 30, 1999 of
approximately $0.3 million and $0.6 million were reduced by a reserve of
approximately $69.2 thousand to reflect the estimated annual true-up so that
General Electric would be charged a
8
<PAGE>
nominal amount which is the annual equivalent of 160,000 lbs/hr. There were no
steam revenues for the quarter ended June 30, 1998. Steam revenues for the six
months ended June 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 six months ended June 30, 1999 was approximately 403.4
million pounds and 813.2 million pounds as compared to approximately 297.6
million pounds and 683.5 million pounds for the corresponding periods in the
prior year. The increase in steam revenues for the quarter and six months ended
June 30, 1999 was primarily due to the increase in delivered steam.
Gas resale revenues for the quarter ended June 30, 1999 were approximately $3.3
million on sales of approximately 1.4 million MMBtu's as compared to
approximately $3.2 million on sales of approximately 1.3 million MMBtu's for the
corresponding period in the prior year. Gas resale revenues for the six months
ended June 30, 1999 were approximately $4.4 million on sales of approximately
2.0 million MMBtu's as compared to approximately $5.2 million on sales of
approximately 2.2 million MMBtu's for the corresponding period in the prior
year. The $0.8 million decrease in gas resale revenues during the six months
ended June 30, 1999 is primarily due to the higher dispatch of Unit 1 and lower
natural gas resale prices, which resulted in lower volumes of natural gas
becoming available for resale at lower prices. The decrease in natural gas
resale prices during the six months ended June 30, 1999 generally resulted from
more moderate temperatures in the Northeast region as compared to colder
temperatures, which resulted in higher demand for natural gas, during the
corresponding period in the prior year. The Partnership entered into gas resales
during periods when Units 1 and 2 were not operating at full capacity.
Cost of revenues for the quarter ended June 30, 1999 were approximately $29.8
million on gas purchases of approximately 6.9 million MMBtu's as compared to
$28.8 million on gas purchases of approximately 7.1 million MMBtu's for the
corresponding period in the prior year. The largest component of the increase
for the quarter ended June 30, 1999 were maintenance expenses, which increased
approximately $0.9 million from the corresponding period in the prior year. The
increase in maintenance expenses was primarily due to higher maintenance costs
and the scheduling of planned maintenance to occur during the second quarter of
1999 whereas, in the prior year, similar planned maintenance was scheduled to
occur during the fourth quarter of 1998. Cost of revenues for the six months
ended June 30, 1999 were approximately $54.9 million on gas purchases of
approximately 13.8 million MMBtu's as compared $56.9 million on gas purchases of
approximately 14.1 million MMBtu's for the corresponding period in the prior
year. The largest component of the decrease for the six months ended June 30,
1999 was fuel costs, which decreased approximately $2.4 million from the
corresponding period in the prior year. The decrease in the cost of fuel was
primarily due to lower contract firm fuel rates which resulted from lower index
fuel prices and lower transportation demand costs and the write-off of a reserve
of approximately $0.5 million for amounts no longer in dispute with a gas
transporter. 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 six
9
<PAGE>
months ended June 30, 1999 and 1998, fuel costs were increased by approximately
$1.2 million and $1.0 million, respectively, as a result of the currency swap
agreements.
Total other operating expenses for the quarter and six months ended June 30,
1999 were approximately $1.2 million and $2.2 million as compared to
approximately $1.6 million and $3.0 million for the corresponding periods in the
prior year. The decrease in other operating expenses for the quarter ended June
30, 1999 was primarily due to lower affiliate administrative services. The
decrease in other operating expenses for the six months ended June 30, 1999 was
primarily due to lower affiliate administrative services and the write-off of a
reserve of approximately $0.2 million for amounts no longer claimed by an
affiliate.
Net interest expense for the quarter and six months ended June 30, 1999 of
approximately $8.0 million and $16.0 million was comparable to the corresponding
periods in the prior year.
Liquidity and Capital Resources
- -------------------------------
Net cash flows used in operating activities for the quarter ended June 30, 1999
were approximately $1.2 million as compared to approximately $5.4 million for
the corresponding period in the prior year. Net cash flows provided by operating
activities for the six months ended June 30, 1999 was approximately $15.4
million as compared to approximately $12.0 million for the corresponding period
in the prior year. Net cash flows provided by (used in) operating activities
primarily represents net income plus the net effect of normally 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 ended June 30, 1999 were
approximately $265.0 thousand as compared to approximately $14.0 thousand for
the corresponding period in the prior year. Net cash used in investing
activities for the six months ended June 30, 1999 were approximately $310.0
thousand as compared to approximately $14.0 thousand for the corresponding
period in the prior year. Net cash flows used in investing activities primarily
represents additions to plant and equipment.
Net cash provided by financing activities for the quarter ended June 30, 1999
was approximately $1.7 million as compared to approximately $2.0 million for the
corresponding period in the prior year. Net cash used in financing activities
for the six months ended June 30, 1999 was approximately $15.3 million as
compared to approximately $12.0 million for the corresponding period in the
prior year. The decrease in net cash flows provided by financing activities for
the quarter ended June 30, 1999 and the increase in net cash flows used in
financing activities for the six months ended June 30, 1999 is primarily due to
more cash becoming available to distribute to the Partners and the increase in
the semi-annual payment of principal on long-term debt.
10
<PAGE>
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 and processes as expected,
levels of dispatch, the receipt of certain capacity and other fixed payments,
electricity prices, natural gas resale prices, fuel deliveries and prices as
contracted. A significant change in any of these factors could have a material
adverse effect on the results for the Partnership.
The Partnership believes that based on current conditions and circumstances it
will have sufficient liquidity available provided by cash flows from operations
to fund existing debt obligations and operating costs.
11
<PAGE>
Year 2000
- ---------
The Year 2000 issue exists because many computer programs use only two digits to
refer to a year, 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 individually where necessary and
tested in an integrated manner with other systems, with dates and data advanced
and aged to simulate Year 2000 operations. 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.
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.
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<PAGE>
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 July 1999, the Partnership spent approximately $372,000 to assess,
remediate and test Year 2000 problems for both mission critical and non-mission
critical items. 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.
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
and processes as expected, levels of dispatch, the receipt of certain capacity
and other fixed payments, electricity prices, natural gas resale prices, fuel
deliveries and prices as contracted and issues related to Year 2000 compliance.
13
<PAGE>
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. The
Partnership does not enter into derivative financial instruments for trading
purposes.
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, 1999 would have resulted in a negative impact of approximately $58.0
thousand and $108.0 thousand, 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 a 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 six months ended June 30, 1999 the exchange rate
differential had a negative impact of approximately $0.6 million and $1.2
million, respectively on the Partnership's net income.
14
<PAGE>
PART II. OTHER INFORMATION
ITEM 5. OTHER ITEMS
A written Consent of Directors in lieu of a meeting was executed on July 26,
1999 for both Selkirk Cogen Funding Corporation and JMC Selkirk, Inc. ("The
Managing General Partner"). The following tables set forth the names and
positions of newly appointed officers.
Selkirk Cogen Funding Corporation:
----------------------------------
Name Position
---- --------
Gary W. Weidinger Senior Vice President
The Managing General Partner:
-----------------------------
Name Position
---- --------
Gary W. Weidinger Senior Vice President
Gary W. Weidinger is Senior Vice President Asset Management of PG&E
Generating Company (formerly "U.S. Generating Company"), an affiliate of the
Partnership, and has been with PG&E Generating Company since 1991. Mr. Weidinger
was the officer responsible for the Engineering Department prior to joining the
Operations Department in 1995. Mr. Weidinger has more than 25 years of
experience in the power generation business including management positions with
Bechtel Power, Puget Sound Power and Light and California Energy. He has also
managed a consulting firm providing services to power generation and industrial
customers.
15
<PAGE>
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.
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 PARTNERS, L.P.
JMC SELKIRK, INC.
General Partner
Date: October 14, 1999 /s/ JOHN R. COOPER
----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
Chief Financial Officer
17
<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: October 14, 1999 /s/ JOHN R. COOPER
----------------------------------
Name: John R. Cooper
Title: Senior Vice President and
and Chief Financial Officer
18
<PAGE>
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<NAME> SELKIRK COGEN PARTNERS, L.P.
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