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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________ to ______________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address, and Telephone Number Identification No.
000-49614 PSEG POWER LLC 22-3663480
(A Delaware Limited Liability Company)
80 Park Plaza
P.O. Box 570
Newark, New Jersey 07101-0570
973-430-7000
http://www.pseg.com
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
--- ---
Registrant is a wholly owned subsidiary of Public Service Enterprise Group
Incorporated. Registrant meets the conditions set forth in General Instruction
H(1) (a) and (b) of Form 10-Q and is filing this Form 10-Q with the reduced
disclosure format authorized by General Instruction H.
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TABLE OF CONTENTS
PAGE
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PART I. FINANCIAL INFORMATION
- -----------------------------
Item 1. Financial Statements .......................................... 1
Item 2. Management's Discussion and Analysis of Financial
Condition And Results of Operations ........................... 20
Item 3. Qualitative and Quantitative Disclosures about Market Risk .... 29
Item 4. Controls and Procedures ....................................... 29
PART II. OTHER INFORMATION
- --------------------------
Item 1. Legal Proceedings ............................................. 30
Item 5. Other Information ............................................. 30
Item 6. Exhibits and Reports on Form 8-K .............................. 32
Signature ................................................................. 33
i
PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF INCOME
(Millions)
(Unaudited)
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2001 2002 2001
---- ---- ---- ----
OPERATING REVENUES............................. $1,092 $685 $2,341 $1,919
OPERATING EXPENSES
Energy Costs............................... 644 312 1,068 691
Operation and Maintenance.................. 178 172 553 535
Depreciation and Amortization.............. 29 28 79 83
----- ---- ------ ------
Total Operating Expenses............... 851 512 1,700 1,309
----- ---- ------ ------
OPERATING INCOME............................... 241 173 641 610
Other Income and Deductions.................... -- (1) -- (4)
Interest Expense - Net......................... (35) (26) (90) (115)
----- ---- ------ ------
INCOME BEFORE INCOME TAXES..................... 206 146 551 491
Income Taxes................................... (85) (59) (226) (199)
----- ---- ------ ------
NET INCOME..................................... $ 121 $ 87 $ 325 $ 292
===== ==== ====== ======
See Notes to Consolidated Financial Statements
1
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT ASSETS
Cash and Cash Equivalents................... $ 15 $ 9
Accounts Receivable:
Affiliated Companies...................... -- 17
Trade..................................... 324 270
Fuel........................................ 468 76
Materials and Supplies, Net of Valuation....
Reserves - 2002 and 2001, $2.............. 137 124
Prepayments................................ 16 13
Energy Trading Contracts.................... 717 387
Other....................................... 25 2
------- -------
Total Current Assets...................... 1,702 898
------- -------
PROPERTY, PLANT AND EQUIPMENT
Property, Plant and Equipment............... 4,982 4,238
Less: Accumulated Depreciation
and Amortization...................... (1,378) (1,253)
------- -------
Net Property, Plant and Equipment.............. 3,604 2,985
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NONCURRENT ASSETS
Deferred Income Taxes....................... 541 579
Nuclear Decommissioning Fund................ 768 817
Energy Trading Contracts.................... 46 46
Other....................................... 316 178
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Total Noncurrent Assets................... 1,671 1,620
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TOTAL ASSETS................................... $ 6,977 $ 5,503
======= =======
See Notes to Consolidated Financial Statements
2
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT LIABILITIES
Accounts Payable:
Affiliated Companies.................................. $ 87 $ --
Trade................................................. 354 333
Energy Trading Contracts................................... 665 386
Other ..................................................... 285 111
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Total Current Liabilities................................. 1,391 830
------ ------
NONCURRENT LIABILITIES
Nuclear Decommissioning.................................... 768 817
Cost of Removal............................................ 142 146
Environmental.............................................. 53 53
Energy Trading Contracts................................... 42 54
Other ..................................................... 88 58
------ ------
Total Noncurrent Liabilities............................. 1,093 1,128
------ ------
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 3).............
CAPITALIZATION
Long-Term Debt
Project Level, Non-Recourse Debt........................... 800 770
Long-Term Debt............................................. 2,515 1,915
------ ------
Total Long-Term Debt....................................... 3,315 2,685
------ ------
MEMBER'S EQUITY
Contributed Capital........................................ 1,350 1,350
Basis Adjustment........................................... (986) (986)
Retained Earnings.......................................... 823 498
Accumulated Other Comprehensive Loss....................... (9) (2)
------ ------
Total Member's Equity...................................... 1,178 860
------ ------
TOTAL LIABILITIES AND CAPITALIZATION............................ $6,977 $5,503
====== ======
See Notes to Consolidated Financial Statements
3
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
For the Nine Months Ended September 30,
---------------------------------------
2002 2001
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income .............................................................. $ 325 $ 292
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization ......................................... 79 83
Amortization of Nuclear Fuel .......................................... 68 76
Provision for Deferred Income Taxes and Investment Tax Credit (ITC) ... 43 52
Non-Cash Benefit Plan Costs ........................................... 24 16
Unrealized (Gains) Losses ............................................. (50) 4
Net Changes in certain current assets and liabilities:
Accounts Receivable ................................................ (37) 46
Inventory Fuel, Materials and Supplies ............................. (405) (14)
Accrued Taxes ...................................................... (19) 4
Accrued Interest ................................................... 20 87
Accounts Payable ................................................... 108 (124)
Other Current Assets and Liabilities ............................... 150 (30)
Benefit Plan Funding .................................................. (75) (28)
Other ................................................................. (81) (28)
----- -------
Net Cash Provided By Operating Activities .......................... 150 436
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment .............................. (792) (1,246)
Proceeds from Sale of Property, Plant and Equipment ..................... 47 --
Contributions to Nuclear Decommissioning Trust Fund ..................... (25) (22)
----- -------
Net Cash Used In Investing Activities .............................. (770) (1,268)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt .............................................. 630 2,432
Repayment of Note Payable-Affiliated Company ............................ -- (2,786)
Contributed Capital ..................................................... -- 1,200
Deferred Issuance Costs ................................................. (4) (28)
----- -------
Net Cash Provided By Financing Activities .......................... 626 818
----- -------
Net Change In Cash And Cash Equivalents ................................... 6 (14)
Cash And Cash Equivalents At Beginning Of Period .......................... 9 20
----- -------
Cash And Cash Equivalents At End Of Period ................................ $ 15 $ 6
===== =======
Income Taxes Paid ......................................................... $ 170 $ 118
Interest Paid ............................................................. $ 111 $ 119
See Notes to Consolidated Financial Statements
4
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1. Organization and Basis of Presentation
Organization
Unless the context otherwise indicates, all references to "Power," "we," "us" or
"our" herein means PSEG Power LLC and its consolidated subsidiaries. We are a
Delaware limited liability company with our principal executive offices at 80
Park Plaza, Newark, New Jersey 07102. We are a wholly-owned subsidiary of Public
Service Enterprise Group Incorporated (PSEG).
We are an independent wholesale energy supply company that has three principal
direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), which owns and
operates nuclear generating stations, PSEG Fossil LLC (Fossil), which develops,
owns and operates domestic fossil generating stations and PSEG Energy Resources
& Trade LLC (ER&T). We also have a finance company subsidiary, PSEG Power
Capital Investment Co. (Power Capital), which provides certain financing for its
subsidiaries.
Basis of Presentation
The financial statements included herein have been prepared pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC) for Form
10-Q. Certain information and note disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations. However,
in the opinion of management, the disclosures herein are adequate to make the
information presented not misleading. These Consolidated Financial Statements
and Notes to Consolidated Financial Statements (Notes) should be read in
conjunction with the notes contained in our Annual Report on Form 10-K and our
amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002 and
our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002. These
Notes update and supplement matters discussed in our Annual Report on Form 10-K
and our amended Quarterly Report on Form 10-Q/A for the quarter ended March 31,
2002 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002.
The unaudited financial information furnished reflects all adjustments which
are, in the opinion of management, necessary to fairly state the results for the
interim periods presented. All such adjustments are of a normal recurring
nature. The year-end consolidated balance sheets were derived from the audited
consolidated financial statements included in our 2001 Annual Report on Form
10-K. Certain reclassifications of prior period data have been made to conform
with the current presentation.
Several factors impacting Power in the quarter ended September 30, 2002 also
impact the presentation of Power's financial statements presented herein. In the
third quarter, Power adopted Emerging Issues Task Force Issue No. 02-3, which
requires that we report energy trading revenues and energy trading costs on a
net basis. See Note 2. Recent Accounting Pronouncements. In addition, as a
result of these and other changes in our business, we also reevaluated our
segment presentation and have determined that Power operates in one integrated
business segment. See Note 6. Financial Information By Business Segment.
Under the Basic Generation Service (BGS) contract, which terminated on July 31,
2002, Power sold energy directly to PSE&G which in turn sold this energy to its
customers. These revenues were properly recognized on each company's stand-alone
financial statements and were eliminated when preparing our consolidated
financial statements. For the new BGS contract period beginning August 1, 2002,
Power sells energy to third party suppliers and other load serving entities
(LSEs) and PSE&G purchases the energy for its customers' needs from third party
suppliers.
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Note 2. Recent Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142)
On January 1, 2002, we adopted SFAS 142. Under SFAS 142, goodwill is considered
a nonamortizable asset and is subject to an annual review for impairment and an
interim review when indications of impairment arise. In 2001, we had recorded
goodwill of approximately $21 million as a result of our acquisition of the
Albany, NY Steam Station from Niagara Mohawk Power Corporation in May 2000.
Prior to January 1, 2002, this amount was amortized in accordance with then
current accounting guidance at approximately $0.5 million per year. As of
January 1, 2002, we no longer amortize goodwill. We completed our transitional
analysis of goodwill impairment as required by SFAS 142 and determined that
there was no impairment to our recorded goodwill.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144)
On January 1, 2002, we adopted SFAS 144. Upon adoption, SFAS 144 did not have an
effect on our financial position or results of operations. Under SFAS 144,
long-lived assets to be disposed of are measured at the lower of the carrying
amount or fair value less cost to sell. Also under SFAS 144, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred. Also, as previously required by
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" (SFAS 121), SFAS 144 requires that a long-lived asset
must be tested for impairment whenever events or changes in circumstances
indicate that its carrying amount may be impaired.
Emerging Issues Task Force (EITF) Issue No. 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 02-3)
In June 2002, the EITF addressed certain issues related to energy trading
activities, including gross versus net presentation in the income statement and
additional disclosure requirements for energy trading activities. The EITF
determined that gains and losses on energy trading contracts should be shown net
of trading costs in the income statement. This change is applicable to financial
statements for periods ending after July 15, 2002 and requires that prior
periods be restated for comparability.
In October 2002, the EITF reached a final consensus regarding the accounting for
contracts involved in energy trading and risk management activities. Management
does not yet know the impact of adopting this consensus on January 1, 2003.
Pursuant to EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), we previously recorded our trading revenues and
trading related costs on a gross basis for physical energy and capacity sales
and purchases. In accordance with EITF 02-3, beginning in the third quarter of
2002, we started reporting energy trading revenues and energy trading costs on a
net basis and have reclassified prior periods to conform with this net
presentation. As a result, both trading revenues and trading costs were reduced
by approximately $748 million and $636 million for the quarters ended September
30, 2002 and 2001, respectively, and $1.5 billion and $1.7 billion for the nine
month periods ended September 30, 2002 and 2001, respectively. This change in
presentation did not have an effect on trading margins, net income or cash
flows.
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143)
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143.
Under SFAS 143, the fair value of a liability for an asset retirement obligation
(ARO) is required to be recorded in the period in which it is incurred with an
offsetting amount recorded as an asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss. SFAS 143 is effective for fiscal years beginning after June 15, 2002.
In August 2002, PSE&G filed a petition requesting clarification from the BPU
regarding the future cost responsibility for nuclear decommissioning and
whether, as a matter of law and policy; (a) PSE&G's customers will continue to
pay for such costs through the Societal Benefits Clause (SBC) or (b) such
customer responsibility will terminate at the end of the four-year transition
period on July 31, 2003. We cannot predict the outcome of this matter.
Upon adoption of the standard, we will likely be required to adjust our Nuclear
Decommissioning Liability ($768 million, pre-tax as of September 30, 2002) to
reflect the present value of our expected asset retirement obligation. If the
BPU determines that PSE&G's customers continue to pay for these costs, then the
difference between the recorded amount of the liability and the liability
calculated under the new ARO standard will be deferred on the balance sheet. If
the BPU determines that such customer responsibility terminates at the end of
the transition period, then the difference between the recorded amount of our
existing liability and the liability calculated under the new ARO standard will
be recorded as a one-time benefit as a Cumulative Effect of a Change in
Accounting Principle. In conjunction with the implementation of SFAS 143, we may
change our method of accounting for Cost of Removal for our Fossil Stations,
which would substantially reduce the Cost of Removal Liability that we have
recorded for our Fossil stations of $142 million, pre-tax as of September 30,
2002. We currently believe that we will have no material legal retirement
obligation under the new standard for our Fossil stations, therefore the amount
of that liability at the time we adopt SFAS 143 will reverse into income. The
impact of adopting SFAS 143 is still being determined, and is likely to be a
material benefit to our financial position and results of operations.
Although the impact of this standard on future expenses is still being
determined, our present analyses indicate that ongoing depreciation and interest
expense (to accrete from the ARO liability, which is recorded at its present
value, to the ultimate liability) will approximate our current expense levels
over our five year planning horizon. However, under current GAAP we could
experience significant volatility in earnings since the Nuclear Decommissioning
Trust Fund's assets would be required to be marked to market with unrealized
gains and losses recognized in Other Comprehensive Income (OCI) and realized
gains and losses recognized through earnings. Previously, these gains and losses
were offset by changes in the Nuclear Decommissioning Liability with no effect
on earnings. We are currently considering various methods to mitigate this
volatility, including multiple financial products, although no assurances can be
given.
SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" (SFAS 145)
During the third quarter of 2002, we adopted SFAS 145. This Statement rescinds
SFAS No. 4, "Reporting Gains and Losses from Extinguishments of Debt," (SFAS 4)
and an amendment of that Statement, SFAS No. 64, "Extinguishments of Debt Made
to Satisfy Sinking Fund Requirements" (SFAS 64). SFAS 4 required that gains and
losses from extinguishments of debt that were included in the determination of
net income be aggregated, and if material, classified as an extraordinary item.
Since the issuance of SFAS 4, the use of debt extinguishments has become part of
the risk management strategy of many companies, representing a type of debt
extinguishment that does not meet the criteria for classification as an
extraordinary item. Based on this trend, the FASB issued this rescission of SFAS
4 and SFAS 64. Accordingly, under SFAS 145, we will record any gains and losses
from
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
extinguishments of debt in Other Income or Other Deductions. We adopted SFAS 145
retroactive to January 1, 2002, with no impact to our financial position,
results of operations, or net cash flows.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
(SFAS 146)
In June 2002, the FASB issued SFAS No. 146, which addresses the financial
accounting and reporting for costs associated with exit or disposal activities.
SFAS 146 states that a liability for a cost associated with an exit or disposal
activity shall be recognized and measured initially at its fair value in the
period when the liability is incurred. A liability is established only when
present obligations to others are determined, meaning that an entity has little
or no discretion to avoid the future costs to settle the liability. SFAS 146
does not apply to costs associated with the retirement of long-lived assets
covered in SFAS 143. It applies to costs associated with an exit activity that
does not involve an entity newly acquired in a business combination or with a
disposal activity covered by SFAS 144. We will apply SFAS 146 for exit or
disposal activities initiated after December 31, 2002, in accordance with the
effective date of the standard.
Note 3. Commitments And Contingent Liabilities
Guaranteed Obligations
We have guaranteed payment of obligations incurred under energy trading
contracts of our subsidiary, ER&T, with various counterparties up to established
dollar limits. The established dollar limits of those guarantees on behalf of
counterparties totaled approximately $1 billion at September 30, 2002. In
addition, we have guaranteed payment of all amounts owed to PJM by ER&T without
a stated dollar limit. The outstanding amount of exposure under those guarantees
totaled $166 million as of September 30, 2002 representing the amount payable
under these contracts and the net amount by which open contracts are below
market.
As of September 30, 2002, we issued letters of credit in the amount of
approximately $73 million in support of various contractual obligations.
In addition, certain International Swap Dealer Agreements (ISDA) and other
supply contracts contain margin requirements that, as of September 30, 2002,
would require us to post collateral of approximately $270 million if our credit
ratings are downgraded below investment grade.
Environmental
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations
concerning site investigation and remediation require an ecological evaluation
of potential injuries to natural resources in connection with a remedial
investigation of contaminated sites. The NJDEP is presently working with
industry to develop procedures for implementing these regulations. These
regulations may substantially increase the costs of remedial investigations and
remediations, where necessary, particularly at sites situated on surface water
bodies. We and our predecessor companies own or owned and/or operate or operated
certain facilities situated on surface water bodies, certain of which are
currently the subject of remedial activities. The financial impact of these
regulations on these projects is not currently estimable. We do not anticipate
that the compliance with these regulations will have a material adverse effect
on our financial position, results of operations or net cash flows.
8
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Passaic River Site
The United States Environmental Protection Agency (EPA) has determined that a
stretch of the Passaic River in Newark, New Jersey is a "facility" within the
meaning of that term under the Federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (CERCLA) and that, to date, at least
thirteen entities, including us, may be potentially liable for performing
required remedial actions to address potential environmental pollution at the
Passaic River "facility". In a separate matter, we and certain of our
predecessors operated industrial facilities at properties within the Passaic
River "facility", including the Essex Generating Station. We have contracted to
sell the site of the former generating station, contingent upon approval by
state regulatory agencies, to a third party that would release and indemnify us
for claims arising out of that site. We cannot predict what action, if any, the
EPA or any third party may take against us with respect to these matters, or in
such event, what costs we may incur to address any such claims. However, such
costs may be material.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In January 2002, we reached an agreement with the state and the federal
government to resolve allegations of noncompliance with federal and state NSR
regulations. Under that agreement, we will install advanced air pollution
controls over 12 years that are expected to significantly reduce emissions of
nitrogen oxides (NOx), sulfur dioxide (SO2) particulate matter, and mercury from
the Hudson and Mercer coal burning units. The estimated cost of the program is
$355 million and such costs, when incurred, will be capitalized as plant
additions.
New Generation and Development
We have revised our schedules for completion of several projects under
development to provide better sequencing of our construction program with
anticipated market demand. This delay will allow us to conserve capital in 2003
and allow us to take advantage of the expected recovery of the electric markets
and their need for capacity in 2005.
PSEG Power New York Inc., an indirect, wholly-owned subsidiary, is developing
the Bethlehem Energy Center, a 763 MW combined-cycle power plant that will
replace the 380 MW Albany, NY Steam Station. Total costs for this project are
expected to be approximately $465 million with expenditures to date of
approximately $114 million. Construction began in 2002 with the expected
completion date in 2005, at which time the existing station will be retired.
We are constructing a 1,218 MW combined cycle generation plant at Linden, New
Jersey with costs estimated at approximately $694 million and expenditures to
date of approximately $520 million. Completion is expected in 2005, at which
time 451 MW of existing generating capacity will be retired.
We are constructing through indirect, wholly-owned subsidiaries, two natural
gas-fired combined cycle electric generation plants in Waterford, Ohio (821 MW)
and Lawrenceburg, Indiana (1,096 MW) at an estimated total cost of $1.2 billion.
Total expenditures to date on these projects have been approximately $1.1
billion. The required estimated equity investment in these projects is
approximately $400 million, with the remainder being financed with non-recourse
bank financing. As of September 30, 2002, approximately $247 million of equity
has been invested in these projects. In connection with these projects, ER&T has
entered into a five-year tolling agreement pursuant to which it is obligated to
purchase the output of these facilities. The agreement may expire if the current
financing is repaid within five years. Additional equity contributions may be
required by us to the project company if the purchase price of electricity under
this contract, which will be determined prior to commercial operations, results
in revenues that are less than the required payments under the bank financing.
Based on current market prices, it is anticipated that additional equity
contributions will be required. The Waterford facility is currently scheduled to
achieve commercial operation in June 2003. The Lawrenceburg facility is
currently scheduled to achieve commercial operation in December 2003.
9
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
We have entered into an agreement to purchase Wisvest-Connecticut LLC, which
holds two electric generating stations in Connecticut, at a cost of $220
million. The agreement also calls for purchase price adjustments of up to $20
million for various expenditures made prior to closing, as well as closing
adjustments for fuel and inventory. The coal, oil, and gas-fired plants have a
total capacity of 1,019 MW. The transaction is subject to various Federal
approvals. The transfer of the two stations triggered the Connecticut Transfer
Act, which requires the commencement of any necessary remedial activities within
three years of the transfer of the property. While the cost to comply with the
Transfer Act to clean up former petroleum coke operations at one of the two
stations is still unknown, estimated costs are between $10 million and $20
million. No assurances can be given as to the ultimate remediation costs at
these facilities, however they could be material. We expect to close on this
acquisition in the fourth quarter of 2002, subsequent to Federal Energy
Regulatory Commission (FERC) approval and our performance based testing of the
units.
We also have contracts with outside parties to purchase upgraded turbines for
the Salem Nuclear Generating Station Units 1 and 2 and to purchase upgraded
turbines and to purchase a power uprate for Hope Creek Generating Station to
increase its generating capacity. The contracts are subject to regulatory
approval and are currently scheduled to be completed by 2004 for Salem Unit 1
and Hope Creek and 2006 for Salem Unit 2. Our aggregate estimated costs for
these projects are $210 million.
We have commitments to purchase gas turbines and/or other services to meet our
current plans to develop additional generating capacity. The aggregate amount
due under these commitments is approximately $480 million, approximately $370
million of which is included in estimated costs for the projects discussed
above. The approximate $110 million remaining relates to obligations to purchase
hardware and services that have not been designated to any specific projects. If
we do not contract to satisfy our commitment relating to the $110 million in
obligations by July 2003, we will be subject to penalties of up to $24 million.
Minimum Fuel Purchase Requirements
We use coal for our fossil fueled electric generation stations. We purchase coal
through various contracts and in the spot market. The total minimum purchase
requirements included in these contracts amount to approximately $72 million
through 2003.
We have several long-term purchase contracts with uranium suppliers, converters,
enrichers and fabricators to meet the currently projected fuel requirements for
Salem and Hope Creek. Our remaining minimum purchase requirement for 2002 under
these contracts is approximately $20 million. On average, we have various
multi-year requirements-based purchase commitments that total approximately $100
million per year to meet Salem and Hope Creek fuel needs. We have been advised
by Exelon Corporation, the co-owner and operator of the Peach Bottom Atomic
Power Station (Peach Bottom) that it has similar purchase contracts to satisfy
the fuel requirements for Peach Bottom.
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal
government has entered into contracts with the operators of nuclear power plants
for
10
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
transportation and ultimate disposal of the spent nuclear fuel. To pay for this
service, the nuclear plant owners were required to contribute to a Nuclear Waste
Fund at a rate of one mil per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal
government. These costs were being recovered through the Basic Generation
Service (BGS) contract through July 2002. Payments made to the United States
Department of Energy (DOE) for disposal costs are based on nuclear generation
and are included in Energy Costs in the Consolidated Statements of Income.
Under the NWPA, the DOE was required to begin taking possession of the spent
nuclear fuel by no later than 1998. The DOE has announced that it does not
expect a facility to be available earlier than 2010. Exelon has advised us that
it had signed an agreement with the DOE applicable to Peach Bottom under which
Exelon would be reimbursed for costs incurred resulting from the DOE's delay in
accepting spent nuclear fuel. The agreement allows Exelon to reduce the charges
paid to the Nuclear Waste Fund to reflect costs reasonably incurred due to the
DOE's delay. Past and future expenditures associated with Peach Bottom's
recently completed on-site dry storage facility would be eligible for this
reduction in DOE fees. Under this agreement, our portion of Peach Bottom's
Nuclear Waste Fund fees have been reduced by approximately $18 million through
August 31, 2002, at which point the credits were fully utilized and covered the
cost of Exelon's storage facility.
In 2000, a group of eight utilities filed a petition against the DOE in the U.S.
Court of Appeal, for the Eleventh Circuit, seeking to set aside the receipt of
credits by Exelon out of the Nuclear Waste Fund, as stipulated in the Peach
Bottom agreement. On September 24, 2002, the U.S. Court of Appeal, for the
Eleventh Circuit, issued an opinion upholding the challenge by the petitioners
regarding the settlement agreement's compensation provisions. Under the terms of
the agreement, DOE and Exelon Generation are required to meet and discuss
alternative funding sources for the settlement credits. The agreement provides
that if such negotiations are unsuccessful, the agreement will be null and void.
Any payments required by us resulting from a disallowance of the previously
reduced fees would be included in Energy Costs in the Consolidated Statements of
Income.
In February 2002, President Bush announced that Yucca Mountain in Nevada would
be the permanent disposal facility for nuclear wastes. On April 8, 2002, the
Governor of Nevada submitted his veto to the siting decision. On July 9, 2002,
Congress affirmed the President's decision. The DOE must still license and
construct the facility. No assurances can be given regarding the final outcome
of this matter.
Note 4. Financial Instruments, Energy Trading and Risk Management
Our operations are exposed to market risks from changes in commodity prices and
interest rates that could affect our results of operations and financial
conditions. We manage our exposure to these market risks through our regular
operating and financing activities and, when deemed appropriate, hedge these
risks through the use of derivative
11
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
financial instruments. We use the term hedge to mean a strategy designed to
manage risks of volatility in prices or rate movements on certain assets,
liabilities or anticipated transactions and by creating a relationship in which
gains or losses on derivative instruments are expected to counterbalance the
losses or gains on the assets, liabilities or anticipated transactions exposed
to such market risks. We use derivative instruments as risk management tools
consistent with our business plans and prudent business practices and for energy
trading purposes.
Energy Trading Contracts
We maintain a strategy of entering into trading positions to optimize the value
of our portfolio of generation assets and supply obligations. We do not engage
in the practice of simultaneous trading for the purpose of increasing trading
volume or revenue. We engage in physical and financial transactions in the
electricity wholesale markets and execute an overall risk management strategy to
mitigate the effects of adverse movements in the fuel and electricity markets.
We actively trade energy and energy-related products, including electricity,
natural gas, electric capacity, fixed transmission rights, coal and emission
allowances, in the spot, forward and futures markets, primarily in
Pennsylvania-New Jersey-Maryland Power Pool (PJM), and electricity in the Super
Region, which extends from Maine to the Carolinas and the Atlantic Coast to
Indiana and natural gas in the producing region, the Henry Hub Basin, as well as
the Super Region. These contracts also involve financial transactions including
swaps, options and futures.
These contracts are recorded under Emerging Issues Task Force (EITF) 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) which requires these contracts to be marked-to-market
with the resulting realized and unrealized gains and losses included in current
earnings. In prior periods we disclosed gains and losses related to certain
activities within our trading segment. Commencing with our change in segment
reporting discussed in Note 6. Financial Information by Business Segments, we
have excluded certain transactions, such as firm transmission rights and Basic
Gas Supply Service (BGSS) results, from this table and solely report gains and
losses on transactions accounted for pursuant to EITF-98-10. There was no change
in our margins, net income or cash flows as a result of this change in
presentation. Prior periods have been reclassified to conform to this
presentation.
12
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
For the three months and nine months ended September 30, 2002, we recorded net
margins of $9 million and $36 million, respectively, as shown below:
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2001 2002 2001
---- ---- ---- ----
(Millions) (Millions)
Realized Gains .................................. $ 17 $ 38 $ 16 $ 109
Unrealized Gains ................................ (5) (4) 27 10
---- ---- ---- -----
Gross Margin .................................. 12 34 43 119
---- ---- ---- -----
Broker Fees and Other Trading-Related Expense ... (3) (2) (7) (4)
---- ---- ---- -----
Net Margin .................................... $ 9 $ 32 $ 36 $ 115
==== ==== ==== =====
As of September 30, 2002 and December 31, 2001, substantially all of our energy
contracts had terms of two years or less and were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to the energy commodities are summarized in the following
table:
September 30, 2002 December 31, 2001
------------------------------ -----------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
-------- -------- ----- -------- -------- -----
(Millions) (Millions)
Listed Futures and Options............. -- 12 $ 2 -- 14 $ (1)
Physical forwards...................... 48 -- 4 35 -- (3)
Options OTC............................ 14 286 5 7 713 (19)
Swaps.................................. 5 2,152 9 6 970 19
Emission Allowances.................... -- -- 15 -- -- 8
-- ----- --- -- ----- ----
Totals............................ 67 2,450 $35 48 1,697 $ 4
== ===== === == ===== ====
We routinely enter into exchange-traded futures and options transactions for
electricity and natural gas as part of our energy trading operations. Generally,
exchange-traded futures contracts require deposit of margin cash, the amount of
which is subject to change based on market movement and in accordance with
exchange rules. The amount of the margin deposits as of September 30, 2002 was
approximately $9 million.
Derivative Instruments and Hedging Activities
Commodity Contracts
The availability and price of energy commodities are subject to fluctuations
from factors such as weather, environmental policies, changes in supply and
demand, state and federal regulatory policies and other events. To reduce price
risk caused by market fluctuations, we enter into derivative contracts,
including forwards, futures, swaps and options with approved counterparties, to
hedge our anticipated demand. These contracts, in conjunction with owned
electric generation capacity, are designed to cover estimated electric customer
commitments.
In February 2002, New Jersey conducted an auction to identify energy suppliers
for the BGS of the State's regulated distribution utilities for the one-year
period beginning on August 1, 2002. We did not participate directly in the
auction but agreed to supply power to several of the
13
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
direct bidders. Subsequently, a portion of the contracts with those bidders was
reassigned to us. Therefore, for a limited portion of the New Jersey retail
load, we will be a direct supplier to one non-affiliated utility.
In order to hedge a portion of our forecasted energy purchases to meet our BGS
requirements, we entered into forward purchase contracts, futures, options and
swaps. We have also forecasted the energy delivery from our generating stations
based on the forward price curve movement of energy and, as a result, entered
into swaps, options and futures transactions to hedge the price of gas to meet
our gas purchases requirements for generation. These transactions qualified for
hedge accounting treatment under SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). As of September 30, 2002, the
fair value of these hedges were $17 million with offsetting charges to Other
Comprehensive Income (OCI) of $10 million (after-tax). These hedges will mature
through 2003.
Also, prior to May 2002, PSE&G had entered into gas forwards, futures, options
and swaps to hedge its forecasted requirements for natural gas, which was
required under an agreement with the BPU in 2001. Effective with the transfer of
PSE&G's gas contracts to us on May 1, 2002, we also acquired all of the
derivatives entered into by PSE&G. We account for these derivative instruments
pertaining to residential customers in a manner similar to PSE&G. Gains or
losses from these derivatives are deferred and will be recovered from customers
as part of the monthly billing to PSE&G. Derivatives relating to commercial and
industrial customers will be accounted for in accordance with SFAS 133 where
appropriate. Gains or losses on these derivatives are deferred and reported as a
component of OCI. There was no ineffectiveness associated with these hedges. The
accumulated OCI will be reclassified to earnings in the period in which the
hedged transaction affects earnings. As of September 30, 2002, we had
approximately 328 MMBTU of gas forwards, futures, options and swaps to hedge
forecasted requirements with a fair value of approximately $7 million. As of
December 31, 2001, PSE&G had approximately 330 MMBTU of gas forwards, futures,
options and swaps to hedge forecasted requirements with a fair value of
approximately $(137) million. The maximum term of these contracts is
approximately one year.
We also enter into certain other contracts which are derivatives but do not
qualify for hedge accounting under SFAS 133, nor are they classified as energy
trading contracts under EITF 98-10. Most of these contracts are option contracts
on gas purchases for generation requirements, which do not qualify for hedge
accounting and therefore the changes in fair market value of these derivative
contracts are recorded in the income statement at the end of each reporting
period.
For the three and nine months ended September 30, 2002, we recorded gains
(losses) on certain derivative contracts of $(6) million and $24 million,
respectively, as shown below:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
---- ---- ---- ----
(Millions) (Millions)
Realized (Losses) Gains...... $(7) $17 $ 1 $17
Unrealized (Losses) Gains.... 1 (6) 23 (14)
--- --- --- --
Gross Margin............... $(6) $11 $24 $3
=== === === ==
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
As of September 30, 2002 and December 31, 2001, substantially all of our energy
contracts had terms of two years or less and were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to the energy commodities are summarized in the following
table:
September 30, 2002 December 31, 2001
------------------------------ ------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
-------- -------- ----- -------- -------- -----
(Millions) (Millions)
Listed Futures and Options............ -- 32 $ 2 -- -- --
Options OTC......................... -- 63 -- 1 148 $(6)
Swaps................................. -- 41 $14 -- 11 1
-- --- --- -- --- ---
Totals................................ -- 136 $16 1 159 $(5)
== === === == === ===
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or values
of instruments with similar terms, credit ratings, remaining maturities and
redemptions at September 30, 2002 and December 31, 2001, respectively.
September 30, 2002 December 31, 2001
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(Millions)
Long-Term Debt:
Power Senior Notes............ $2,400 $2,461 $1,800 $1,942
Pollution Control.......... 124 126 124 124
Non-Recourse Debt.......... 800 800 770 770
------ ------ ------ ------
Principal Amount Outstanding..... 3,324 3,387 2,694 2,836
------ ------ ------ ------
Net Unamortized Discount......... (9) -- (9) --
------ ------ ------ ------
Total Long Term Debt $3,315 $3,387 $2,685 $2,836
====== ====== ====== ======
As of October 31, 2002, the fair value of the long-term debt for Power had
declined to estimated fair value of approximately $3.1 billion.
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Note 5. Income Taxes
A tax expense has been recorded for the results of continuing operations. An
analysis of that provision is as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------------------ -----------------
(Millions) (Millions)
Pre-Tax Income....................................... $206 $146 $551 $491
Tax Computed at the Federal Statutory Rate at 35%.... 72 51 193 172
Increases (decreases) from Federal statutory rate
attributable to:
State Income Taxes after Federal Benefit.......... 12 10 32 29
Other............................................. 1 (2) 1 (2)
---- ---- ---- ----
Total Income Tax Expense............................. $ 85 $ 59 $226 $199
---- ---- ---- ----
Effective Income Tax Rate 41.3% 40.4% 41.0% 40.5%
Note 6. Financial Information By Business Segment
Our business has evolved during 2002. With the transfer of the BGSS (i.e.,
natural gas supply requirements contract) contract to us and the commencement of
the new BGS Contracts with wholesale electric suppliers, our business has become
a fully integrated wholesale energy supply business. As a result of that
evolution of our business, trading activities changed from a stand-alone
operation to a function that has become fully integrated with the wholesale
energy supply business, and primarily serves to optimize the value of that
business. Therefore, upon review and in accordance with SFAS No. 131,
"Disclosures About Segments of an Enterprise and Related Information" (SFAS
131), we have determined that our generation and trading components no longer
meet the definition of separate operating segments for financial reporting
purposes and, effective with this filing, we have reported our financial
position and results of operations as one segment. All prior periods have been
reclassified to conform to the current presentation.
Note 7. Comprehensive Income
For the three months ended September 30, 2002 and 2001, our comprehensive income
was $121 million and $106 million, respectively. For the nine months ended
September 30, 2002 and 2001, our comprehensive income was $318 million and $288
million, respectively.
Note 8. Related Party Transactions
PSEG and PSE&G
In August 2000, PSE&G transferred its electric generating assets and liabilities
to us in exchange for a $2.8 billion promissory note. Interest on the promissory
note was payable at an annual rate of 14.23%, which represented PSE&G's weighted
average cost of capital. For the period from January 1, 2001 to January 31,
2001, we recorded
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
interest expense of approximately $34 million relating to the promissory note.
We repaid the promissory note on January 31, 2001, with funds provided from PSEG
in the form of equity and loans, including loans of $1.6 billion at various
rates for which we recorded interest expense of approximately $40 million for
the period from February 2001 to April 2001, when the loans were repaid.
Effective with the asset transfer, we charge PSE&G for a market transition
charge (MTC) for the energy provided to meet PSE&G's BGS requirements. These
rates were established by the BPU. For the quarter and nine months ended
September 30, 2002, we charged PSE&G approximately $216 million and $1.2
billion, respectively, for MTC and BGS. For the three and nine months ended
September 30, 2001, we charged PSE&G approximately $568 million and $1.5
billion, respectively, for MTC and BGS. As of December 31, 2001, our receivable
from PSE&G relating to these billings was approximately $159 million.
For the three and nine months ended September 30, 2002, we purchased energy from
PSE&G at the market price of approximately $48 million and $110 million,
respectively, which PSE&G purchased under various non-utility generation (NUG)
contracts. For the quarter and nine months ended September 30, 2001, we
purchased energy from PSE&G at the market price of approximately $55 million and
$135 million, respectively, which PSE&G purchased under various non-utility
generation (NUG) contracts. With commencement of the new BGS contract on August
1, 2002, PSE&G can sell the energy under the NUG contracts to other third-party
suppliers. As of September 30, 2002 and December 31, 2001, our payable to PSE&G
relating to these purchases was approximately $13 million and $7 million,
respectively. Prospectively, these related party NUG sales will cease to exist
given that PSE&G will conduct these transactions directly within a PJM
administered market. Therefore, with commencement of the new BGS period on
August 1, 2002, we charge PSE&G only for the MTC subsequent to July 31, 2002. As
of September 30, 2002, our receivable from PSE&G relating to the MTC billings
was approximately $1 million.
Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas
inventory to us for approximately $183 million and we entered into a
requirements contract with PSE&G under which we will provide the delivered gas
supply services needed to meet its Basic Gas Supply Service (BGSS) requirements.
The contract term ends March 31, 2004 with a three-year renewal option. For the
three and nine months ended September 30, 2002, we charged PSE&G approximately
$111 million and $208 million under terms of the contract. As of September 30,
2002, our receivable from PSE&G relating to these costs was approximately $38
million. As part of the agreement, PSE&G is providing us the use of its peaking
shaving facilities at cost.
We have transactions with PSEG for various activities, including short-term
funding for day-to-day operations, depending on liquidity. As of September 30,
2002, there was a net payable of approximately $104 million from PSEG related to
these transactions. As of December 31, 2001, there was a net payable of
approximately $142 million to PSEG related to these transactions.
PSEG Global Inc. (Global)
During 2002, we sold turbines purchased from an outside vendor to Global, a
wholly owned subsidiary PSEG Energy Holdings LLC (Energy Holdings), at their
carrying amounts totaling approximately $47 million.
PSEG Services Corporation
PSEG Services Corporation provides administrative services to us and bills us on
a monthly basis. Our costs related to such services amounted to approximately
$93 million and $94 million for the nine months ended September 30, 2002, and
2001, respectively. Our costs related to such services amounted to approximately
$27 million and $35
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
million for the three months ended September 30, 2002, and 2001, respectively.
As of September 30, 2002 and December 31, 2001, our payable related to these
costs was approximately $9 million and $13 million, respectively.
Note 9. Guarantees of Debt
In April 2001, we issued $500 million of 6.875% Senior Notes due 2006, $800
million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior Notes
due 2031. Additionally, in June 2002, we issued $600 million of 6.95% Senior
Notes due 2012. Each series of the Senior Notes is fully and unconditionally and
jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following
table presents condensed financial information for the guarantor subsidiaries as
well as our non-guarantor subsidiaries as of September 30, 2002 and 2001 and for
the quarters then ended.
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
----- ------------ ------------ ------------- -----
(Millions)
For the three months ended September 30, 2002:
- ----------------------------------------------
Revenues.................................... $ 1 $1,083 $ 8 $ -- $1,092
Operating Expenses.......................... 15 827 8 1 851
---- ------ ---- ----- ----
Operating Income (Loss)..................... (14) 256 -- (1) 241
Other Income................................ 159 6 -- (165)
Interest Income (Expense)................... (50) (15) 31 (1) (35)
Income Taxes................................ 26 (100) (11) -- (85)
---- ------ ---- ----- ------
Net Income.................................. $121 $ 147 $ 20 $(167) $ 121
==== ====== ==== ===== ======
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
----- ------------ ------------ ------------- ------
(Millions)
For the three months ended September 30, 2001:
- ----------------------------------------------
Revenues.................................... $ 21 $ 658 $ 6 $ -- $ 685
Operating Expenses.......................... 15 488 9 512
---- ------ ---- ----- ----
Operating Income (Loss)..................... 6 170 (3) -- 173
Other Income (Expense)...................... 105 34 -- (140) (1)
Interest Income (Expense)................... (40) (22) 36 -- (26)
Income Taxes................................ 16 (68) (7) -- (59)
---- ------ ---- ----- ------
Net Income.................................. $ 87 $ 114 $ 26 $(140) $ 87
==== ====== ==== ===== ======
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PSEG Power LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) Concluded
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
----- ------------ ------------ ------------- -----
(Millions)
For the nine months ended September 30, 2002:
- ---------------------------------------------
Revenues............................................... $ 2 $2,325 $ 14 $ -- $ 2,341
Operating Expenses..................................... 51 1,631 18 -- 1,700
------ ------ ------ ------- -------
Operating Income (Loss)................................ (49) 694 (4) -- 641
Other Income........................................... 433 19 -- (452) --
Interest Income (Expense).............................. (132) (45) 87 -- (90)
Income Taxes........................................... 73 (269) (30) -- (226)
------ ------ ------ ------- -------
Net Income............................................. $ 325 $ 399 $ 53 $ (452) $ 325
====== ====== ====== ======= =======
Net Cash Provided By (Used In) Operating Activities.... $ (371) $ 706 $ 66 $ (251) $150
Net Cash Provided By (Used In) Investing Activities.... (2) (489) (280) 1 (770)
Net Cash Provided By (Used In) Financing Activities.... 685 15 215 (289) 626
For the nine months ended September 30, 2001:
- ---------------------------------------------
Revenues............................................... $ 21 $1,877 $ 21 $ -- $ 1,919
Operating Expenses..................................... 63 1,212 34 -- 1,309
------ ------ ------ ------- -------
Operating Income (Loss)................................ (42) 665 (13) -- 610
Other Income (Loss).................................... 425 29 (458) (4)
Interest Income (Expense).............................. (152) (52) 89 -- (115)
Income Taxes........................................... 61 (245) (15) -- (199)
------ ------ ------ ------- -------
Net Income............................................. $ 292 $ 397 $ 61 $ (458) $ 292
====== ====== ====== ======= =======
Net Cash Provided By Operating Activities.............. $ 173 $ 357 $ 98 $ (192) $ 436
Net Cash (Used In) Investing Activities................ (2) (419) (825) (22) (1,268)
Net Cash Provided By Financing Activities.............. 205 119 741 (247) 818
As of September 30, 2002:
- -------------------------
Current Assets......................................... $ 712 $ 960 $ 30 $ -- $ 1,702
Property, Plant and Equipment, net..................... 46 2,320 1,238 -- 3,604
Noncurrent Assets...................................... 3,244 1,038 1,330 (3,941) 1,671
------ ------ ------ ------- -------
Total Assets........................................... $4,002 $4,318 $2,598 $(3,941) $ 6,977
====== ====== ====== ======= =======
Current Liabilities.................................... $ 156 $ 975 $ 260 $ -- $ 1,391
Noncurrent Liabilities................................. 47 1,033 13 -- 1,093
Note Payable Affiliated Company........... ............ 106 1,150 (1,256)
Long-Term Debt......................................... 2,515 800 3,315
Member's Equity........................................ 1,178 1,160 1,525 (2,685) 1,178
------ ------ ------ ------- -------
Total Liabilities and Member's Equity.................. $4,002 $4,318 $2,598 $(3,941) $ 6,977
====== ====== ====== ======= =======
As of December 31, 2001:
- ------------------------
Current Assets......................................... $ 9 $ 851 $ 64 $ (26) $898
Property, Plant and Equipment, net..................... 40 1,987 958 -- 2,985
Noncurrent Assets...................................... 2,834 829 1,230 (3,273) 1,620
------ ------ ------ ------- -------
Total Assets........................................... $2,883 $3,667 $2,252 $(3,299) $ 5,503
====== ====== ====== ======= =======
Current Liabilities.................................... $ 57 $ 678 $ 215 $ (120) $ 830
Noncurrent Liabilities................................. 30 1,082 16 -- 1,128
Note Payable Affiliated Company........................ 21 1,150 (1,171)
Long-Term Debt......................................... 1,915 770 2,685
Member's Equity........................................ 860 757 1,251 (2,008) 860
------ ------ ------ ------- -------
Total Liabilities and Member's Equity.................. $2,883 $3,667 $2,252 $(3,299) $ 5,503
====== ====== ====== ======= =======
There are no restrictions on the ability of our subsidiaries to transfer funds
in the form of dividends, loans or advances to us for the periods noted above.
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PSEG Power LLC
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Following are the significant changes in or additions to information reported in
our 2001 Annual Report on Form 10-K and Amended Quarterly Report on Form 10-Q/A
for the quarter ended March 31, 2002 and Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002, affecting our consolidated financial condition and
the results of operations. This discussion refers to our Consolidated Financial
Statements (Statements) and related Notes to Consolidated Financial Statements
(Notes) and should be read in conjunction with such Statements and Notes.
Overview
For the quarter ended September 30, 2002, net income was $121 million, an
increase of $34 million or 39% from the comparable period in 2001. For the nine
months ended September 30, 2002, net income increased $33 million or 11% from
the comparable period in 2001. The increase in net income was due to additional
revenue earned due to our successful participation as an indirect supplier of
energy to the state's utilities, including Public Service Electric and Gas
Company (PSE&G), involved in New Jersey's recent basic generation service (BGS)
auction. The BGS auction had a meaningful effect on our earnings, particularly
since August 1st, when the new BGS contracts went into effect. We secured
contracts to sell our generation to suppliers that won the right to serve New
Jersey's Utilities, including PSE&G, for a one year period beginning August 1,
2002. Also on May 1, 2002, we acquired the gas supply contracts and gas
inventory from PSE&G for $183 million. At that time we also entered into a
requirements contract with PSE&G under which we will provide the delivered gas
supply services to PSE&G, which are needed to meet their Basic Gas Supply
Service (BGSS). The contract term ends March 31, 2004 with a three-year renewal
option, at PSE&G's option.
Our cash position increased $6 million from December 31, 2001 to September 30,
2002 due primarily to $150 million of operating cash inflows, $626 million of
financing inflows, offset by $770 million of cash outflows for investing
activities. Our operating cash outflows were primarily due to the acquisition of
the gas portfolio from PSE&G. Our investing cash outflows related primarily to
construction expenditures. Our financing cash inflows are related primarily to
the issuance of long-term debt in June 2002.
Future Outlook
For 2002, we are expecting to earn $460 million to $500 million. Our successful
participation as an indirect supplier of energy to New Jersey's utilities,
including PSE&G, in New Jersey's recent basic generation service (BGS) auction
is expected to have a meaningful effect on our earnings for the remainder of the
year.
Looking ahead, the volatile marketplace is creating extraordinary challenges for
the energy industry, including us, to improve on 2002 results in 2003. Several
of the assumptions in our 2003 planning process have changed in this evolving
economic environment. Specifically, two factors, increased pension expense due
to the erosion of the value of the investments in our pension plans, and
emerging capital structure considerations, will pressure our earnings growth. If
market conditions do not alleviate these pressures, we will be challenged to set
2003 earnings targets at levels beyond those for 2002. Other assumptions in our
2003 business plan are that we will continue to benefit from our performance as
a wholesale BGS provider with the new one year BGS contract that began August 1,
2002 and a reasonable outcome to next year's auction for contracts beginning
August 1, 2003.
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Factors Affecting Future Outlook
Due to the inherent price volatility of the commodities in our business, and
many other factors, it is much more difficult to accurately forecast our future
earnings. Some of the key sensitivities and risks of our businesses are
discussed below.
Our success as a BGS provider will depend, in part, on our ability to meet our
obligations under our full requirements contracts with the BGS suppliers in a
profitable manner. We expect to accomplish this by producing energy from our own
generation and/or energy purchases in the market. We also enter into trading
positions related to our generation assets and supply obligations. To the extent
we do not hedge our obligations, whether long or short, we will be subject to
the risk of price fluctuations that could affect our future results, such as
increases in the price of energy purchased to meet supply obligations, the cost
of fuel to generate electricity, the cost of congestion credits that we need to
transmit electricity and other factors. In addition, we are subject to the risk
of subpar operating performance of our fossil and nuclear generating units. To
the extent there are unexpected outages at our generating facilities, changes in
environmental or nuclear regulations or other factors which impact the
production by such units or the ability to generate and transmit electricity in
a cost-effective manner, it may cost us more to produce electricity or we may be
required to purchase higher cost energy to replace the energy we anticipated
producing. These risks can be exacerbated by, among other things, changes in
demand in electricity usage, such as those due to extreme weather and economic
conditions.
Our future revenue stream is also uncertain. Due to the timing of the New Jersey
BGS auction process, the majority of our revenues for August 1, 2003 and
thereafter cannot be accurately predicted. Also, certain new projects, such as
our investments in the Lawrenceburg and Waterford projects in the Midwest and
the plants we are acquiring from Wisvest in Connecticut, and our development of
the Bethlehem Energy Center in New York are also subject to the risk of changes
in future energy prices as we have not entered into forward sale contracts for
the majority of their expected generation capacity. Also, since the majority of
our generation facilities are concentrated in the Northeast region, changes in
future energy supply and demand and energy-related prices in this region could
materially affect our results. Also, changes in the rules and regulation of
these markets by Federal Energy Regulatory Commission (FERC), particularly
changes in the ability to maintain market based rates, could have an adverse
impact on our results. As a result of these variables and risks, we cannot
predict the impact of these potential future changes on our forecasted results
of operations, financial position, or net cash flows, however such impact could
be material.
We will continue our energy trading activities to optimize the value of our
portfolio of generating assets and supply obligations. This will depend, in
part, on our, as well as our counterparties', ability to maintain sufficient
creditworthiness and to display a
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willingness to participate in energy trading activities at anticipated volumes.
Potential changes in the mechanisms of conducting trading activity, such as the
continued availability of energy trading exchanges, could positively or
negatively affect trading volumes and liquidity in these energy trading markets
compared to the assumptions of these factors embedded in our business plans. As
a result of these variables, we cannot predict the impact of these potential
future changes on our forecasted results of operations, financial position, or
net cash flows, however such impact could be material.
In addition, we have exposure to the equity and debt markets through our
substantial use of short-term financing, lower pension fund balances, the effect
of lower assumed rate of investment returns on our pension expense and the
effect of a lower discount rate on our pension plan liabilities and costs. Also,
increases in the cost of capital, which could result from market and lender
concerns regarding us, our industry and economic conditions and other factors,
could make it more difficult for us to enter into profitable investments. Recent
market trends could also affect our ability to access capital, potentially
impacting both our business plans and opportunities as well as our liquidity.
Also, changes in our credit ratings by rating agencies could significantly
impact our access to capital, cost of capital, ability to meet earnings
expectations and future business plans. We are also subject to credit risk. See
Item 3. Qualitative and Quantitative Disclosures about Market Risk for further
discussion.
RESULTS OF OPERATIONS
Operating Revenues
For the quarter ended September 30, 2002, Operating Revenues increased by $407
million or 59%. Included in this increase were $172 million of gas revenues
relating to our BGSS contract resulting from the Gas Contract transfer from
PSE&G in May 2002. Also contributing to the increase was a $268 million increase
in electric revenues, primarily due to the new BGS contracts with third party
wholesale electric suppliers which went into effect August 1, 2002 and
comparably warmer weather which were partially offset by lower market transition
charge (MTC) revenues primarily due to a 4.9% rate reduction in August 2002 and
a 2% rate reduction in August 2001. These rate reductions reduce the MTC
revenues that PSE&G remits to us as part of its BGS contract. Also offsetting
the increases were lower net trading revenues of approximately $23 million due
to lower trading volumes and prices during the three months ended September 30,
2002 as compared to the same period in 2001. See Note 4. Financial Instruments,
Energy Trading and Risk Management for further discussion information relating
to our trading activities.
For the nine months ended September 30, 2002, Operating Revenues increased by
$422 million or 22%. Included in this increase were $273 million of gas revenues
relating to our BGSS contract resulting from the Gas Contract transfer from
PSE&G in May 2002. Also contributing to the increase was a $228 million increase
in electric revenues, primarily due to the new BGS contracts with third party
wholesale electric suppliers which went into effect August 1, 2002 and
comparably warmer weather which were partially offset by lower MTC revenues
primarily due to a 4.9% rate reduction in August 2002 and a two 2% rate
reductions in August 2001 in February 2001. Also offsetting the increases were
lower net trading revenues of approximately $79 million due to lower trading
volumes and prices during the nine months ended September 30, 2002 as compared
to the same period in 2001.
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Operating Expenses
Energy Costs
For the quarter ended September 30, 2002, Energy Costs increased $332 million or
106%. The increases were primarily due to increased energy purchases for the BGS
and third party wholesale electric supplier contracts of approximately $122
million due to higher volume and $197 million of increased gas purchases to
satisfy our BGSS contract and our fuel needs for generation. Also contributing
to the increase were approximately $43 million of increased network transmission
expenses in the Pennsylvania-New Jersey-Maryland Power Pool (PJM). These
increases were offset by $22 million of gains on fuel hedges, $5 million of
reduced congestion charges due to more efficient unit scheduling by PJM and a $3
million decrease in nuclear fuel usage.
For the nine months ended September 30, 2002, Energy Costs increased $377
million or 55%. The increases were primarily due to increased energy purchases
for the BGS and third party wholesale electric supplier contacts of
approximately $144 million due to higher volumes and $276 million of increased
gas purchases to satisfy our BGSS contract and our fuel needs for generation.
Also contributing to the increase was higher network transmission expenses of
$35 million for PJM and $11 million of increased coal purchases. These higher
expenses were partially offset by a $13 million decrease in nuclear fuel usage
and a $36 million decrease in oil consumption. Further expense reductions can be
attributed to $14 million of decreases in fuel hedges, $13 million decrease in
Non-Utility Generation (NUG) purchases and $13 million in lower congestion
charges due to less constraint in the system.
Operation and Maintenance
Operation and Maintenance expense increased $6 million or 3% for the quarter
ended September 30, 2002, and increased $18 million or 8% for the nine months
ended September 30, 2002 from the comparable periods in 2001, respectively. This
was due primarily as a result of various scheduled outages at our electric
generating stations.
Depreciation and Amortization
Depreciation and Amortization expense increased $1 million or 4% for the quarter
ended September 30, 2002, and decreased $4 million or 5% for the nine months
ended September 30, 2002, from the comparable periods in 2001. The increase for
the quarter was primarily due to the Bergen Generating Station (Unit 2) being
placed into service in the second quarter of 2002. The decrease for the
nine-month period was primarily due to increased asset lives and the elimination
of recorded goodwill related to the acquisition of our Albany Steam Station.
Interest Expense
Interest Expense increased $9 million or 35% for the quarter ended September 30,
2002 from the comparable period in 2001, due to the issuance of $600 million of
6.95% Senior Notes in June 2002, and the issuance of $123 million in pollution
control notes in 2001. These increases were partially offset by interest
capitalization on various projects under construction of approximately $26
million.
Interest Expense decreased $25 million or 22% for the nine months ended
September 30, 2002 from the comparable periods in 2001. The decrease for the
nine month period is primarily due to our refinancing of our higher rate
affiliate loans with PSE&G and PSEG, which were replaced with equity and lower
rate external debt.
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LIQUIDITY AND CAPITAL RESOURCES
Financing Methodology
Our capital requirements are met through liquidity provided by internally
generated cash flow and external financings. We from time to time make equity
contributions to our direct and indirect subsidiaries to provide for part of
their capital and cash requirements, generally relating to long-term
investments. As of September 30, 2002 we had guaranteed equity contribution
commitments of $153 million. In addition, we had other guarantees and
commitments of $73 million. At times, we utilize affiliate company loans to
efficiently manage our short-term cash needs.
External funding to meet the majority of our requirements is comprised of
corporate finance transactions. The debt incurred is our direct obligation. Some
of the proceeds of these debt transactions are used to make equity investments
in our subsidiaries.
As discussed below external financing may consist of public and private capital
market debt and/or project financings. The availability and cost of external
capital could be affected by our performance as well as by the performance of
our subsidiaries and affiliates. This could include the degree of structural or
regulatory separation between us and our subsidiaries and the potential impact
of affiliate ratings on consolidated and unconsolidated credit quality.
Two of our projects currently under construction have non-recourse financing.
Non-recourse transactions generally impose no material obligation on the
parent-level investor to repay any debt incurred by the project borrower.
However, in some cases, certain obligations relating to the investment being
financed, including additional equity commitments, are guaranteed by us for our
subsidiaries. The consequences of permitting a project-level default include
loss of any invested equity by the us.
Over the next several years, we will be required to refinance maturing debt and
expect to incur additional debt to fund investment activity. Also, from time to
time, we may repurchase debt using funds from operations, debt issuances and
other sources of funding. Any inability to obtain required additional external
capital or to extend or replace maturing debt and/or existing agreements at
current levels and reasonable interest rates may adversely affect our financial
condition, results of operations and net cash flows.
Debt Covenants, Cross Default Provisions, Material Adverse Clause Changes, and
Ratings Triggers
The PSEG credit agreements contain cross-default provisions under which a
default by it or its major subsidiaries in an aggregate amount of $50 million
would result in a default and the potential acceleration of payment under the
agreements.
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The Power Senior Debt Indenture contains a default provision under which a
default by it or its subsidiaries (Nuclear, Fossil, ER&T) in an aggregate amount
of $50 million would result in an event of default and the potential
acceleration of payment under the indenture. There are no cross-defaults within
Power's indenture from PSEG, Energy Holdings or PSE&G.
A failure to make principal and or interest payments, when due, would be a
default under our indenture. Any inability to satisfy required covenants and/or
borrowing conditions would have a similar impact. If a default were to occur,
the respective lenders and debt holders, after giving effect to any applicable
grace and/or cure periods, could determine that debt payment obligations may be
accelerated. In the event of any likely default or failure to satisfy covenants
or conditions, we, or the relevant subsidiary, would seek to renegotiate terms
of the agreements with the lenders. No assurances can be given as to whether
these efforts would be successful. A declaration of cross-default could severely
limit PSEG's and our liquidity and restrict our ability to meet debt and, in
extreme cases, operational cash requirements which could have a material adverse
effect on our financial condition, results of operations and net cash flows.
The credit agreements generally contain provisions under which the lenders could
refuse to advance loans in the event of a material adverse change in the
borrower's business or financial condition. In that event, loan funds may not be
advanced.
As explained in detail below, some of these credit agreements also contain
maximum debt to equity ratios, minimum cash flow tests and other restrictive
covenants and conditions to borrowings. Compliance with applicable financial
covenants will depend upon our future financial position and the level of
earnings and cash flow, as to which no assurances can be given.
The debt indentures do not contain any "ratings triggers" that would cause an
acceleration of the required interest and principal payments in the event of a
ratings downgrade. However, in the event of a downgrade, we and/or our
subsidiaries may be subject to increased interest costs on certain bank debt.
Also, in connection with our energy trading activities, we must meet certain
credit quality standards as are required by counterparties. If we lose our
investment grade credit rating, ER&T would have to provide credit support
(letters of credit or cash), which would significantly impact the cost of the
energy trading activities. These same contracts provide reciprocal benefits to
us. Providing this credit support would increase our costs of doing business and
limit our ability to successfully conduct energy trading activities. In
addition, our counterparties may require us to meet margin or other security
requirements that may include cash payments. We may also have to provide credit
support for certain equity commitments if we lose our investment grade rating.
Credit Ratings
Our current ratings of securities are shown below and reflect the respective
views of the rating agencies, from whom an explanation of the significance of
their ratings may be obtained. There is no assurance that these ratings will
continue for any given period of time or that they will not be revised or
withdrawn entirely by the rating agencies, if, in their respective judgments,
circumstances so warrant. Any downward revision or withdrawal may adversely
effect the market price of our securities and serve to increase our cost of
capital, and access to capital.
Moody's(1) Standard & Poor's(2) Fitch(3)
---------- -------------------- --------
Power:
Senior Notes Baa1 BBB BBB+
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(1) On October 11, 2002 Moody's reaffirmed these credit ratings but changed
the outlook from stable to negative.
(2) Affirmed in the second quarter of 2002 and noted an outlook of Stable.
(3) Affirmed in the second quarter of 2002 and noted an outlook of Stable.
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Short-Term Liquidity
We rely on PSEG for our short-term financing needs and have a $50 million Letter
of Credit facility expiring in August 2005. As of September 30, 2002, we had
approximately $125 million of short-term borrowings from PSEG.
PSEG has revolving credit facilities to provide liquidity for its $1 billion
commercial paper program and for various funding purposes. The following table
summarizes the various revolving credit facilities of PSEG as of September 30,
2002.
Expiration Total Primary
Company Date Facility Purpose
- ------- ---------- -------- -------
(Millions)
PSEG:
- -----
364-day Credit Facility March 2003 $620 CP Support
364-day Bilateral Facility March 2003 100 CP Support
5-year Credit Facility March 2005 280 CP Support
5-year Credit Facility December 2002 150 Funding
Uncommitted Bilateral Agreement N/A * Funding
* Availability varies based on market conditions.
As of September 30, 2002, PSEG has $673 million of commercial paper outstanding
and $329 million outstanding under its uncommitted credit facility.
Financial covenants contained in PSEG's credit facilities include the ratio of
debt (excluding non-recourse project financings and securitization debt and
including commercial paper and loans, certain letters of credit and similar
instruments) to total capitalization. At the end of any quarterly financial
period such ratio shall not be more than 0.70 to 1. As of September 30, 2002,
the ratio of debt to capitalization was 0.650 to 1. As part of its financial
planning forecast, PSEG performs stress tests on its financial covenants which
include a consideration of the impacts of potential asset impairments, foreign
currency fluctuations, adjustments relating to pension plans and other items.
Current forecasts do not indicate that PSEG will exceed the required ratio of
debt to total capitalization, however, no assurances can be given and, if an
event of default were to occur, it could materially impact our results of
operations, cash flow and financial position.
External Financings
In June 2002, we issued $600 million of 6.95% Senior Notes due 2012. The
proceeds of which were used to repay short-term funding from PSEG, including
amounts related to the Gas Contract Transfer in May 2002.
CAPITAL REQUIREMENTS
Our capital needs will be dictated by our strategy to continue to develop as a
profitable, growth-oriented supplier in the wholesale power market. We have
revised our schedules for completion of several projects under development to
provide better sequencing of our construction program with anticipated market
demand. This delay will allow us to conserve capital in 2003 and allow us to
take advantage of the expected recovery of the electric markets and their need
for capacity in 2005. Our subsidiaries have substantial commitments as part of
their growth strategies and ongoing construction programs. Power will continue
to evaluate its development and construction requirements in relation to the
energy and financial markets.
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2002 2003 2004 2005 2006
---- ---- ---- ---- ----
(Millions)
Construction/investment expenditures $1,100 $500 $675 $250 $80
For the nine months ended September 30, 2002 and 2001, we had net plant
additions of $792 million and $1.2 billion, respectively. The majority of these
additions were related to developing the Lawrenceburg, Indiana and Waterford,
Ohio sites, the purchase of Wisvest LLC, and adding capacity to the Bergen and
Linden stations in New Jersey. For additional information related to these
projects, see Note 3. Commitments and Contingent Liabilities.
ACCOUNTING MATTERS
For a discussion of SFAS 142, SFAS 143, SFAS 144, SFAS 145, SFAS 146 and EITF
02-03, see Note 2. Accounting Matters.
SFAS No. 87 - "Employers' Accounting for Pensions" (SFAS 87)
SFAS 87 requires a pension plan sponsor to recognize an additional minimum
pension liability to the extent that its accumulated benefit obligation under
any of its pension plans exceeds the fair market value of its plan assets as of
its annual measurement date. This additional minimum pension liability
represents the amount by which its unfunded accumulated benefit obligation
exceeds the fair market value of the plan's assets, and is partially offset by
an intangible asset no larger than the unrecognized net transition obligation
and prior service cost, with no impact to earnings. At this time, we are
monitoring the fair market value of our investments and our accumulated benefit
obligation and are evaluating the potential impact to us and options available
to us with respect to this issue. Since our measurement date is December 31,
2002 we are unable to predict what the impact could be, however the impact could
be material to our financial position and, more specifically, could result in a
decrease in equity.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the matters
discussed in this report and Form 10-K constitute "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements are subject to risks and uncertainties, which could
cause actual results to differ materially from those anticipated. Such
statements are based on management's beliefs as well as assumptions made by and
information currently available to management. When used herein, the words
"will", "anticipate", "intend", "estimate", "believe", "expect", "plan",
"hypothetical", "potential", variations of such words and similar expressions
are intended to identify forward-looking statements. We undertake no obligation
to publicly update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise. The following review of factors
should not be construed as exhaustive or as any admission regarding the adequacy
of our disclosures prior to the effective date of the Private Securities
Litigation Reform Act of 1995. In addition to any assumptions and other factors
referred to specifically in connection with such forward-looking statements,
factors that could cause actual results to differ materially from those
contemplated in any forward-looking statements include, among others, the
following:
o Credit, Commodity, and Financial Market Risks May Have an Adverse Impact
o Energy Obligations, Available Supply and Trading Risks May Have an Adverse
Impact
o The Electric Utility Industry is Undergoing Substantial Change
o Generation Operating Performance May Fall Below Projected Levels
o We Are Subject to Substantial Competition From Well Capitalized
Participants in the Worldwide Energy Markets
o Our Ability to Service Our Debt Could Be Limited
o Power Transmission Facilities May Impact Our Ability to Deliver Our Output
to Customers
o Regulatory Issues Significantly Impact Our Operations
o Environmental Regulation May Limit Our Operations
o We Are Subject to More Stringent Environmental Regulation than Many of Our
Competitors
o Insurance Coverage May Not Be Sufficient
o Acquisition, Construction and Development Activities May Not Be Successful
o Changes in Technology May Make Our Power Generation Assets Less
Competitive
o We Are Subject to Control By PSEG
o Recession, Acts of War, Terrorism Could Have an Adverse Impact
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Consequently, all of the forward-looking statements made in this report are
qualified by these cautionary statements and we cannot assure you that the
results or developments anticipated by us will be realized, or even if realized,
will have the expected consequences to or effects on us or our business
prospects, financial condition or results of operations. You should not place
undue reliance on these forward-looking statements in making any investment
decision. We expressly disclaim any obligation or undertaking to release
publicly any updates or revisions to these forward-looking statements to reflect
events or circumstances that occur or arise or are anticipated to occur or arise
after the date hereof. In making any investment decision regarding our
securities, we are not making, and you should not infer, any representation
about the likely existence of any particular future set of facts or
circumstances. The forward-looking statements contained in this report are
intended to qualify for the safe harbor provisions of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended.
ITEM 3. QUALITATIVE AND QUANTITATIVE
DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our risk sensitive instruments and positions is the
potential loss arising from adverse changes in commodity prices and interest
rates. Our policy is to use derivatives to manage risk consistent with our
business plans and prudent practices. We have a Risk Management Committee
comprised of executive officers, which utilizes an independent risk oversight
function to ensure compliance with corporate policies and prudent risk
management practices.
Except as noted below, there were no other material changes from the disclosures
in our Form 10-K filed with the Securities and Exchange Commission for the year
ended December 31, 2001.
Credit Risk
Counterparties expose us to credit losses in the event of non-performance or
non-payment. We have a credit management process which is used to assess,
monitor and mitigate counterparty exposure for us and our subsidiaries. In the
event of non-performance or non-payment by a major counterparty, there may be a
material adverse impact on our and our subsidiaries' financial condition,
results of operations or net cash flows. As of September 30, 2002 over 97% of
the credit exposure (mark to market plus net receivables and payables) for
Power's trading business was with investment grade counterparties. As of
September 30, 2002, Power's trading business had over 145 active counterparties.
As a result of the New Jersey BGS auction, we have contracted to provide energy
to the direct suppliers of New Jersey electric utilities, including PSE&G,
commencing August 1, 2002. Subsequently, a portion of the contracts with those
bidders was reassigned to us. Therefore, for a limited portion of the New Jersey
retail load, we will be a direct supplier to one utility, although this utility
is not PSE&G. These bilateral contracts are subject to credit risk. This risk is
substantially higher than the risk that was associated with potential nonpayment
by PSE&G under the BGS contract which expired on July 31, 2002, since PSE&G is a
rate-regulated entity. This credit risk relates to the ability of counterparties
to meet their payment obligations for the power delivered under each BGS
contract. We sell electricity to approximately nine supplier-counterparties that
serve the load of the utilities, and one utility directly. Four of these
supplier-counterparties pay us directly, and one of the four prepays its
purchases. The revenue from the remaining five counterparties is paid directly
from the utilities that those suppliers serve, and the related margin due to the
counterparties is recorded as a liability and will be remitted to those
counterparties separately. Any failure to collect these payments under the new
BGS contracts could have a material impact on our results of operations, cash
flows and financial position.
ITEM 4. CONTROLS AND PROCEDURES
We have established and maintain disclosure controls and procedures which are
designed to provide reasonable assurance that material information relating to
the Company, including our consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this
quarterly report is being prepared. We have established a Disclosure Committee
which is made up of several key management employees and reports directly to the
Chief Financial Officer and Chief Executive Officer, to monitor and evaluate
these disclosure controls and procedures. The Chief Financial Officer and Chief
Executive Officer have evaluated the effectiveness of our disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"). Based on this evaluation, we have
concluded that our disclosure controls and procedures were effective in
providing reasonable assurance during the period covered in this quarterly
report. There were no significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date
of our most recent evaluation.
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PART II. OTHER INFORMATION
--------------------------
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of PSEG Power LLC's (Power)
2001 Annual Report on Form 10-K and Power's Amended Quarterly Report on Form
10-Q/A for the quarter ended March 31, 2002 and our Quarterly Report on Form
10-Q for the quarter ended June 30, 2002 are updated below. See information on
the following proceedings at the pages indicated:
(1) Form 10-K, Page 17 and June 30, 2002 Form 10-Q, Page 10. See Page
10. DOE Overcharges, Docket No. 01-592C.
(2) Form 10-K, Pages 16 and 17 and June 30, 2002 Form 10-Q, Page 10. See
Page 10. DOE not taking possession of spent nuclear fuel, Docket No.
01-551C.
(3) Form 10-K, Pages 16 and 51 and June 30, 2002 Form 10-Q, Page 9. See
Page 8. Investigation and additional investigation by the EPA
regarding the Passaic River site. Docket No. EX93060255.
(4) Form 10-K, page 17, March 31, 2002 Form 10-Q/A, page 25 and June 30,
2002 Form 10-Q, page 10. See Page 11. Petition against DOE in the
Eleventh Circuit U.S. Court of Appeals seeking to set aside the
receipt of credits out of the Nuclear Waste Fund.
ITEM 5. OTHER INFORMATION
Certain information reported under our 2001 Annual Report on Form 10-K to the
SEC and our Amended Quarterly Report on Form 10-Q/A for the quarter ended March
31, 2002 and our Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 are updated below. References are to the related pages on the Form 10-K or
Form 10-Q/A or Form 10-Q as printed and distributed.
FERC Order related to PJM Restructuring
New Matter: On July 12, 2002, the United States Court of Appeals, D.C. Circuit,
issued an opinion in favor of PSE&G and the other utility petitioners, reversing
an order of the FERC relating to the restructuring of PJM into an Independent
System Operator. The Court agreed with PSE&G's position an ruled that FERC lacks
authority to require the utility owners to give up their statutory rights under
Section 205 of the Federal Power Act. Hence, FERC was wrong to require a
modification to the PJM ISO Agreement eliminating their rights to file changes
to rate design. The court further noted that FERC lacks authority under Section
203 of the Federal Power Act to require the utility owners to obtain approval of
their withdrawal from the PJM ISO. Hence, FERC had no right under Section 203 to
eliminate the withdrawal rights to which the utilities had agreed. Further, in
ruling on a specific argument raised by PSE&G, the Court held that FERC had not
justified its decision to generically abrogate wholesale power requirements
contracts; FERC was required to make a particularized finding with respect to
the public interest, which was not done here. This matter is now pending on
remand before the FERC.
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Nuclear Regulatory Commission (NRC)
Form 10-K, page 11. A pressurized water reactor nuclear unit (PWR) not owned by
us was recently identified with a degradation of the reactor vessel head, which
forms part of the pressure boundary for the reactor coolant system. In August
2002, the NRC issued a bulletin 2002-02, requiring that all operators of PWR
units submit information concerning: (i) a summary discussion of the
supplemental inspections to be implemented, and (ii) if no changes are to be
implemented, justification for reliance on visual examinations as the primary
method to detect degradation. In September, we provided the requested
information for the Salem Facility. The response stated that a bare metal visual
examination will be performed on the Salem reactor vessel heads during each
unit's next refueling outage, in compliance with the bulletin. If repairs are
determined to be necessary, it is estimated that the repair would extend the
outage by approximately four weeks. The bare metal visual inspection for Salem
Unit 1 was recently completed during the October 2002 refueling outage, and no
degradation of the reactor head was observed. Our Hope Creek nuclear unit and
our interests in the Peach Bottom units 2 and 3 are unaffected as they are
Boiling Water Reactor nuclear units. We cannot predict what other actions the
NRC may take on this issue.
31
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
Exhibit Number Document
-------------- --------
12 Computation of Ratios of Earnings to Fixed Charges
99 Certification by E. James Ferland, Chief Executive
Officer of PSEG Power LLC Pursuant to Section 1350 of
Chapter 63 of Title 18 of the United States Code
99.1 Certification by Thomas M. O'Flynn, Chief Financial
Officer of PSEG Power LLC Pursuant to Section 1350 of
Chapter 63 of Title 18 of the United States Code
(B) Reports on Form 8-K :
Date Form Items
---- ---- -----
October 11, 2002 8-K 5 & 7
July 29, 2002 8-K/A 5 & 7
July 18, 2002 8-K 5 & 7
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SIGNATURE
Pursuant to the requirements 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.
PSEG POWER LLC
--------------
(Registrant)
By: /s/ Patricia A. Rado
-------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2002
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Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of the PSEG Power LLC
(the registrant);
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of the PSEG's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: November 1, 2002 /s/ E. James Ferland
---------------- --------------------
E. James Ferland
Chief Executive Officer
34
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PSEG Power LLC
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Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of the PSEG Power LLC
(the registrant);
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of PSEG's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: November 1, 2002 /s/ Thomas M. O'Flynn
---------------- -----------------------
Thomas M. O'Flynn
Chief Financial Officer
35