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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 June 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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PSEG POWER LLC
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TABLE OF CONTENTS
PAGE
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PART I. FINANCIAL INFORMATION
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Item 1. Financial Statements............................................. 1
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations........................................ 18
Item 3. Qualitative and Quantitative Disclosures about Market Risk....... 24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings................................................ 26
Item 5. Other Information................................................ 27
Item 6. Exhibits and Reports on Form 8-K................................. 28
Signature................................................................. 29
PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2002 2001 2002 2001
------- ------- ------- -------
OPERATING REVENUES .......................................... $ 1,010 $ 1,159 $ 1,968 $ 2,295
OPERATING EXPENSES
Energy and Trading Costs ................................. 619 745 1,139 1,440
Operation and Maintenance ................................ 196 182 379 352
Depreciation and Amortization ............................ 27 25 50 55
Taxes Other Than Income Taxes ............................ (4) 6 -- 11
------- ------- ------- -------
Total Operating Expenses ............................ 838 958 1,568 1,858
------- ------- ------- -------
OPERATING INCOME ............................................ 172 201 400 437
Other Income and Deductions ................................. -- (2) -- (2)
Interest Expense - Net ...................................... (28) (25) (56) (89)
------- ------- ------- -------
INCOME BEFORE INCOME TAXES .................................. 144 174 344 346
Income Taxes ................................................ (61) (70) (141) (140)
------- ------- ------- -------
NET INCOME ................................................ $ 83 $ 104 $ 203 $ 206
======= ======= ======= =======
See Notes to Consolidated Financial Statements
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
(Unaudited)
June 30, December 31,
2002 2001
-------- ------------
CURRENT ASSETS
Cash and Cash Equivalents .................................... $ 13 $ 9
Accounts Receivable:
Affiliated Companies ....................................... 265 17
Other ...................................................... 160 270
Fuel ......................................................... 356 76
Materials and Supplies, Net of Valuation
Reserves - 2002 and 2001, $2 ............................... 131 124
Energy Trading Contracts ..................................... 462 387
Other ........................................................ 19 15
------- -------
Total Current Assets ....................................... 1,406 898
------- -------
PROPERTY, PLANT AND EQUIPMENT
Property, Plant and Equipment ................................ 4,746 4,238
Less: Accumulated Depreciation and Amortization ........... (1,333) (1,253)
------- -------
Net Property, Plant and Equipment .......................... 3,413 2,985
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NONCURRENT ASSETS
Deferred Income Taxes ........................................ 561 579
Nuclear Decommissioning Fund ................................. 830 817
Energy Trading Contracts ..................................... 47 46
Other ........................................................ 258 178
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Total Noncurrent Assets .................................... 1,696 1,620
------- -------
TOTAL ASSETS .................................................... $ 6,515 $ 5,503
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See Notes to Consolidated Financial Statements
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
(Unaudited)
June 30, December 31,
2002 2001
-------- ------------
CURRENT LIABILITIES
Accounts Payable ................................................ $ 376 $ 333
Energy Trading Contracts ................................... 418 386
Other ...................................................... 169 111
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Total Current Liabilities ................................. 963 830
------- -------
NONCURRENT LIABILITIES
Nuclear Decommissioning .................................... 830 817
Cost of Removal ............................................ 144 146
Environmental .............................................. 53 53
Energy Trading Contracts ................................... 64 54
Other ...................................................... 91 58
------- -------
Total Noncurrent Liabilities ............................. 1,182 1,128
------- -------
COMMITMENTS AND CONTINGENT LIABILITIES .......................... -- --
------- -------
CAPITALIZATION
Long-Term Debt
Project Level, Non-Recourse Debt ........................... 800 770
Long-Term Debt ............................................. 2,514 1,915
------- -------
Total Long-Term Debt ....................................... 3,314 2,685
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MEMBER'S EQUITY
Contributed Capital ........................................ 1,350 1,350
Basis Adjustment ........................................... (986) (986)
Retained Earnings .......................................... 701 498
Accumulated Other Comprehensive (Loss) ..................... (9) (2)
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Total Member's Equity ...................................... 1,056 860
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TOTAL LIABILITIES AND CAPITALIZATION ............................ $ 6,515 $ 5,503
======= =======
See Notes to Consolidated Financial Statements
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
For the Six Months Ended
June 30,
-------------------------
2002 2001
---------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income .................................................... $ 203 $ 206
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization ............................... 50 55
Amortization of Nuclear Fuel ................................ 45 52
Provision for Deferred Income Taxes and ITC - net ........... 18 12
Net Changes in certain current assets and liabilities:
Accounts Receivable ...................................... (138) (10)
Inventory-- Fuel and Materials and Supplies .............. (287) (1)
Accounts Payable ......................................... 43 289
Unrealized Gains on Energy Trading Contracts ............. (35) (14)
Other Current Assets and Liabilities ..................... 55 91
Other ....................................................... 7 (87)
------- -------
Net Cash (Used In)/Provided By Operating Activities ...... (39) 593
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, ................... (496) (763)
Additions to Long-Term Investments ............................ (45) (24)
Contributions to Decommissioning and Other Special Funds ...... (45) (22)
------- -------
Net Cash Used In Investing Activities .................... (586) (809)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt .................................... 629 1,791
Repayment of Note Payable-Affiliated Company .................. -- (2,786)
Contributed Capital ........................................... -- 1,200
------- -------
Net Cash Provided By Financing Activities ................ 629 205
------- -------
Net Change In Cash And Cash Equivalents ......................... 4 (11)
Cash And Cash Equivalents At Beginning Of Period ................ 9 20
------- -------
Cash And Cash Equivalents At End Of Period ...................... $ 13 $ 9
======= =======
Income Taxes Paid ............................................... $ 65 $ 89
Interest Paid ................................................... $ 87 $ 113
See Notes to Consolidated Financial Statements
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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. Power is a
Delaware Limited Liability Company with its principal executive offices at 80
Park Plaza, Newark, New Jersey 07102. We are a wholly-owned subsidiary of Public
Service Enterprise Group Incorporated (PSEG) and are a multi-regional
independent electric generation and wholesale energy marketing and trading
company.
We have three principal, direct, wholly-owned subsidiaries: PSEG Nuclear LLC
(Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T)
and currently operate in two reportable segments, generation and energy trading.
The generation segment of our business earns revenues by selling energy on a
wholesale basis under contract to our affiliate, Public Service Electric and Gas
Company (PSE&G), other power marketers and to load serving entities, and also by
bidding energy, capacity and ancillary services into the market. The energy
trading segment of our business earns revenues by trading energy, capacity,
fixed transmission rights, fuel and emission allowances in the spot, forward and
futures markets and through management of the gas portfolio which we acquired
from PSE&G in May 2002. The energy trading segment also earns revenues through
financial transactions, including swaps, options and futures in the electricity
and natural gas markets. We were established to acquire, own and operate the
electric generation-related business of PSE&G pursuant to regulatory orders
issued by the New Jersey Board of Public Utilities (BPU) in connection with the
deregulation of the electric power industry in New Jersey. We also have a
finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital),
which provides certain financing for our 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). 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 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. 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.
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.
Note 2. Accounting Matters
Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142)
SFAS 142 became effective on January 1, 2002. Under SFAS 142, goodwill is
considered a nonamortizable asset and is subject to an annual review for
impairment and an interim review when changes in events or circumstances occur.
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 (Niagara Mohawk) 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 the recorded amount of this goodwill. We completed our analysis of
implementing SFAS 142 by June 30, 2002, and determined there was no impairment
to our recorded goodwill.
SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS
144)
On January 1, 2002, we adopted SFAS 144. Upon adoption, the impact of 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 should be measured at the lower of
the carrying amount or fair value less cost to sell, whether reported in
continued operations or in discontinued operations. 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 under SFAS 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed of" (SFAS 121), a long-lived asset must
be tested for impairment annually, and 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"
In June 2002, the EITF addressed certain issues related to energy trading
activities, including (a) gross versus net presentation in the income statement,
(b) whether the initial fair value of an energy trading contract can be other
than the price at which it was exchanged and (c) additional disclosure
requirements for energy trading activities. The EITF reached a consensus on the
first issue and determined that mark-to-market gains and losses on energy
trading contracts should be shown net 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. The EITF also reached
a consensus on the third issue regarding disclosures which will be effective for
the first year-end after July 15, 2002. The EITF did not reach a consensus on
the second issue and will address it through a working group.
Pursuant to EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), we have been recording 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 will report energy trading revenues and energy trading costs on a net
basis and will reclassify prior periods to conform with this net presentation.
The effect of this standard will be to reduce both trading revenues and trading
costs by approximately $715 million and $1,058 million for the six months ended
June 30, 2002 and June 30, 2001, respectively, and approximately $2,256 million
and $2,647 million for the years ended December 31, 2001 and December 31, 2000,
respectively. This change in presentation will have no effect on trading
margins, net income or any component of cash flows.
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143)
In July 2001, the Financial Accounting Standards Board (FASB), issued SFAS 143.
Upon adoption of SFAS 143, the fair value of a liability for an asset retirement
obligation is required to be recorded. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss upon settlement. SFAS 143 is effective for fiscal years beginning after
June 15, 2002. This standard will have an impact on our nuclear decommissioning
liability and other items. We are still evaluating the potential impact of
adopting SFAS 143, which will likely be material to our financial position and
results of operations.
Note 3. Commitments And Contingent Liabilities
Guaranteed Obligations
We have guaranteed certain energy trading contracts of ER&T. We entered into
guarantees having a maximum liability of $876 million and $506 million as of
June 30, 2002 and December 31, 2001, respectively. The amount of our exposure
under these guarantees was $169 million and $153 million as of June 30, 2002 and
December 31, 2001, respectively.
As of June 30, 2002, letters of credit were issued in the amount of
approximately $89 million. These letters of credit are in support of our trading
business and various contractual obligations.
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 owned and/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.
Passaic River Site
The United States Environmental Protection Agency (EPA) has determined that a
six mile 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 corporations, 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 the 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 a response to a request by the EPA and the NJDEP under Section 114 of the
Federal Clean Air Act (CAA) requiring information to assess whether projects
completed since 1978 at the Hudson and Mercer coal burning units were
implemented in accordance with applicable NSR regulations, we provided certain
data in November 2000. 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 units. The agreement includes a CO2 emissions
reduction goal for our New Jersey units. This single year CO2 reduction goal
will be achieved mainly through repowering projects. The estimated cost of the
program is $355 million and such costs, when incurred, will be capitalized as
plant additions. We also agreed to pay a $1.4 million civil penalty, $6 million
on supplemental environmental projects, and up to $1.5 million if reductions in
CO2 levels are not achieved.
The EPA had also asserted that PSD requirements are applicable to Bergen 2, such
that we were required to have obtained a permit before beginning actual on-site
construction. We disputed that PSD/NSR requirements were applicable to Bergen 2.
As a result of the agreement resolving the NSR allegations concerning Hudson and
Mercer, the NJDEP issued an air permit for Bergen 2. Bergen 2 began operations
in June 2002.
New Generation and Development
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 will
be approximately $465 million with expenditures to date of approximately $79
million. Construction began in 2002 with the expected completion date in 2004,
at which time the existing station will be retired.
We have completed construction of a 546 MW natural gas-fired, combined cycle
electric generation plant at Bergen Generation Station at a cost of
approximately $342 million that was declared commercial in 2002. We are also
constructing a 1,218 MW combined cycle generation plant at Linden, New Jersey
with costs estimated at approximately $700 million and expenditures to date
approximately of $432 million. Completion is expected in 2003, 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 aggregate total cost of $1.2 billion.
Total expenditures to date on these projects have been approximately $1.0
billion. The required estimated equity investment in these projects is
approximately $400 million, with the remainder being financed with non-recourse
debt. As of June 30, 2002, approximately $212 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 at stated prices. Based on current prices, this
contract is currently above market. The agreement may expire if the current
financing is repaid within five years. Additional equity investments may be
required if the proceeds received from ER&T under this tolling agreement are not
sufficient to cover the required payments under the bank financing. Due to
existing market conditions, the Waterford project did not begin commercial
operation as a single-cycle facility in 2002 as originally scheduled. Both the
Waterford and Lawrenceburg combined-cycle facilities are currently scheduled to
achieve commercial operation in 2003.
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 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.
We also have contracts with outside parties to provide upgraded turbines for the
Salem Units 1 and 2 and upgraded turbines and a power uprate for Hope Creek to
increase our generating capacity. The projects are subject to regulatory
approvals 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 $22 million.
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 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 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 as well as
the Super Region. These contracts also involve financial transactions including
swaps, options and futures.
Our energy trading 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). This requires energy trading contracts to
be marked-to-market with the resulting realized and unrealized gains and losses
included in current earnings. These contracts are recorded in our Energy Trading
segment.
For our energy trading segment for the quarter and six months ended June 30,
2002, we recorded net margins of $18 million and $48 million, respectively,
which includes margins generated by gas contracts, as shown below:
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2002 2001 2002 2001
------------- --------------- ----------------- --------------
(Millions of Dollars) (Millions of Dollars)
Realized Gains............................. $16 $27 $17 $74
Unrealized Gains........................... 5 10 35 14
------------- --------------- -------------- --------------
Gross Margin............................. 21 37 52 88
------------- --------------- -------------- --------------
Broker Fees and Other Trading-Related
Expense.................................. (3) (1) (4) (3)
------------- --------------- -------------- --------------
Net Margin............................... $18 $36 $48 $85
============= =============== ============== ==============
As of June 30, 2002 and December 31, 2001, substantially all of our energy
contracts in our trading segment 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 in our energy
trading segment are summarized in the following table:
June 30, 2002 December 31, 2001
----------------------------------- ----------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
----------------------------------- -----------------------------------
(Millions) (Millions)
Futures and Options NYMEX............ 47 10 $1 -- 16 $(1)
Physical forwards.................... 151 -- 10 41 9 (3)
Options-- OTC........................ 2 379 11 8 717 (19)
Swaps................................ -- 1,920 10 -- 1,047 24
Emission Allowances.................. -- -- 15 -- -- 9
----------------------------------- -----------------------------------
Totals.......................... 200 2,309 $47 49 1,789 $10
=================================== ===================================
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 June 30, 2002 was
approximately $3 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.
The BPU approved an auction to identify energy suppliers for the Basic
Generation Service (BGS) of New Jersey's regulated distribution utilities for
the one-year period beginning on August 1, 2002. On February 15, 2002 the BPU
approved the BGS auction results. Power did not participate directly in the
auction but agreed to supply power to several of the direct bidders, securing
contracts for more than 75% of its generation capacity in the PJM market.
Subsequently, a portion of the contracts with those builders was reassigned to
us. Therefore, for a limited portion of the New Jersey retail load, we will be a
direct supplier.
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 133. As of June 30, 2002, the fair value
of these hedges were ($8.6) million with offsetting charges to Other
Comprehensive Income (OCI) of $5.1 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 gas
contract transfer 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 similar manner as PSE&G did. Gains or losses from
these derivatives 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, "Accounting for Derivative
Instruments and Hedging Activities" where appropriate. Gains or losses on these
derivatives will be deferred and reported as a component of other comprehensive
income (OCI). The accumulated OCI will be reclassified to earnings in the period
in which the hedged transaction affects earnings. As of June 30, 2002, we had
approximately 303 MMBTU of gas forwards, futures, options and swaps to hedge
forecasted requirements with a fair value of approximately $(10) 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.
Generation
We also enter into certain other contracts for our generation business which are
derivatives but do not qualify for hedge accounting under SFAS 133, "Accounting
for Derivative Instruments and Hedging Activities" (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 in our generation segment.
For our generation business for the quarter and six months ended June 30, 2002,
we recorded gains and losses on certain derivative contracts of $(6) million and
$26 million, respectively, as shown below:
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2002 2001 2002 2001
----------------- -------------- ---------------- ---------------
(Millions of Dollars) (Millions of Dollars)
Realized (Losses) Gains................ $(5) $-- $8 $--
Unrealized (Losses) Gains.............. (1) (8) 18 (8)
--------------- -------------- -------------- ---------------
Gross Margin......................... $(6) $(8) $26 $(8)
=============== ============== ============== ===============
As of June 30, 2002 and December 31, 2001, substantially all of our energy
contracts in our generation segment 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 in our
generation segment are summarized in the following table:
June 30, 2002 December 31, 2001
--------------------------------------- ---------------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
--------------- ------------- --------- ----------------------------------------
(Millions) (Millions)
Futures and Options NYMEX............. -- 6 $1 -- -- --
Options-- OTC......................... -- 103 5 -- 86 $(11)
Swaps................................. -- -- 1 -- 84 (1)
--------------- ------------- --------- ----------------------------------------
Totals................................ -- 109 $7 -- 170 $(12)
=============== ============= ========= ========================================
Interest Rate Risk
We are subject to the risk of fluctuating interest rates in the normal course of
business. Our policy is to manage interest rate risk through the use of fixed
rate debt, floating rate debt and interest rate swaps. As of June 30, 2002, a
hypothetical 10% change in market interest rates would result in $3 million in
annual interest costs related to non-recourse floating rate debt for our
projects in Lawrenceburg, Indiana and Waterford, Ohio.
Note 5. Income Taxes
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- -------------------------
2002 2001 2002 2001
----------- ------------ ------------ ---------
Pre-Tax Income............................................... $144 $ 174 $344 $ 346
Tax Computed at the Federal Statutory Rate @ 35%............. 50 61 120 121
Increases (decreases) from Federal statutory rate
attributable to:
State Income Taxes after Federal Benefit................. 10 10 20 19
Other.................................................... 1 (1) 1 --
------------- ------------ ------------ ---------
Total Income Tax Expense $ 61 $ 70 $ 141 $ 140
------------- ------------ ------------ ---------
Effective Income Tax Rate.............................. 42.6% 40.2% 41.0% 40.5%
Note 6. Financial Information By Business Segments
Basis of Organization
We currently operate in two reportable segments, Generation and Energy Trading,
which were determined by Management in accordance with SFAS No. 131,
"Disclosures About Segments of an Enterprise and Related Information" (SFAS
131). These segments were determined based on how management measures the
performance based on segment net income, as illustrated in the following table,
and how it allocates resources to our businesses.
Generation
The generation segment of our business earns revenues by selling energy on a
wholesale basis under contract to power marketers, load serving entities (LSEs)
and by bidding our energy, capacity and ancillary services into the market.
Energy Trading
The energy trading segment of our business earns revenues by trading energy,
capacity, fixed transmission rights, fuel and emission allowances in the spot,
forward and futures markets and through management of the gas portfolio which
PSE&G transferred to us in May 2002. The energy trading segment also earns
revenues through financial transactions, including swaps, options and futures in
the electricity and natural gas markets.
Information related to the segments of our business is detailed below:
Energy Consolidated
Generation Trading Total
-------------- --------------- ---------------
(Millions of Dollars)
For the Quarter Ended June 30, 2002:
- -----------------------------------
Operating Revenues........................................... $565 $445 $1,010
Operating Income............................................. 154 18 172
Income Taxes................................................. 53 8 61
Net Income................................................... $73 $10 $83
============== =============== ===============
Energy Consolidated
Generation Trading Total
-------------- --------------- ---------------
(Millions of Dollars)
For the Quarter Ended June 30, 2001:
- -----------------------------------
Operating Revenues........................................... $588 $571 $1,159
Operating Income............................................. 165 36 201
Income Taxes................................................. 56 14 70
Net Income................................................... $82 $22 $104
============== =============== ===============
Energy Consolidated
Generation Trading Total
-------------- --------------- ---------------
(Millions of Dollars)
For the Six Months Ended June 30, 2002:
- --------------------------------------
Operating Revenues........................................... $1,110 $858 $1,968
Operating Income............................................. 352 48 400
Income Taxes................................................. 121 20 141
Net Income................................................... $175 $28 $203
============== =============== ===============
Energy Consolidated
Generation Trading Total
--------------- -------------- ----------------
(Millions of Dollars)
For the Six Months Ended June 30, 2001:
- --------------------------------------
Operating Revenues........................................... $1,149 $1,146 $2,295
Operating Income............................................. 352 85 437
Income Taxes................................................. 106 34 140
Net Income................................................... $155 $51 $206
=============== ============== ================
Total Assets................................................. $5,383 $1,132 $6,515
=============== ============== ================
As of December 31, 2001:
Total Assets................................................. $4,713 $790 $5,503
=============== ============== ================
Note 7. Comprehensive Income
Comprehensive Income, Net of Tax, is detailed below:
Comprehensive Income/(Loss)
--------------------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ ---------------------------
2002 2001 2002 2001
--------- ---------- ----------- -----------
(Millions of Dollars)
Net Income................................................. $83 $104 $203 $206
Change in the Fair Value of Financial Instruments (A)...... (14) (41) (5) (43)
Reclassification Adjustments for Net Amount included in
Net Income (B)........................................... (2) 20 (2) 20
--------- ---------- ----------- -----------
Comprehensive Income....................................... $67 $83 $196 $183
========= ========== =========== ===========
(A) Net of tax of $9 million and $4 million for the quarter and six months ended
June 30, 2002, respectively and $28 million and $30 million for the quarter
and six months ended June 30, 2001, respectively.
(B) Net of tax of $1 million and $1 million for the quarter and six months ended
June 30, 2002, respectively and $(14) million and $(14) million for
the quarter and six months ended June 30, 2001, respectively.
Note 8. Property, Plant and Equipment
Information related to Property, Plant and Equipment is detailed below:
June 30, December 31,
2002 2001
--------------- -------------------
(Millions of Dollars)
Property, Plant and Equipment.................................
Plant in Service:
Fossil Production.......................................... $2,268 $1,898
Nuclear Production......................................... 181 154
--------------- -------------------
Total Plant in Service........................................ 2,449 2,052
--------------- -------------------
Nuclear Fuel in Service....................................... 581 486
Construction Work in Progress Including Nuclear Fuel.......... 1,699 1,693
Other......................................................... 17 7
--------------- -------------------
Total......................................................... $4,746 $4,238
=============== ===================
Interest related to capital projects is capitalized in accordance with SFAS No.
34, "Capitalization of Interest Cost". For the six months ended June 30, 2002
and 2001, Interest Capitalized During Construction (IDC) amounted to $43 million
and $25 million, respectively.
Note 9. 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 $2.786 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 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 $1.620 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 loan was repaid.
Effective with the asset transfer, we charge PSE&G for a market transition
charge (MTC) for the energy and capacity provided to meet PSE&G's BGS
requirements. These rates were established by the BPU. For the quarter and six
months ended June 30, 2002, we charged PSE&G approximately $488 million and $948
million, respectively, for MTC and BGS. For the quarter and six months ended
June 30, 2001, we charged PSE&G approximately $475 million and $938 million,
respectively, for MTC and BGS. As of June 30, 2002 and December 31, 2001, our
receivable from PSE&G relating to these costs was approximately $179 million and
$159 million, respectively. For the quarter and six months ended June 30, 2002,
we purchased energy and capacity from PSE&G at the market price of approximately
$34 million and $63 million, respectively, which PSE&G purchased under various
non-utility generation (NUG) contracts. As of June 30, 2002 and December 31,
2001, our payable to PSE&G relating to these purchases was approximately $13
million and $7 million, respectively.
Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas
inventory to us at a cost of 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 BGSS requirements. The contract term ends
March 31, 2004 with a three-year renewal option. For the quarter ended June 30,
2002, we charged PSE&G approximately $96 million under terms of the contract. As
of June 30, 2002, our receivable from PSE&G relating to these costs was
approximately $54 million. As part of the agreement, PSE&G is providing us the
use of its peaking shaving facilities at cost.
We have intercompany transactions with PSEG for various activities, including
short-term funding for day-to-day operations, depending on liquidity. As of June
30, 2002, there was a net receivable of approximately $22 million from PSEG
related to these transactions. As of December 31, 2001, there was a net payable
of approximately $164 million to PSEG related to these transactions.
PSEG Services Corporation
PSEG Services Corporation provides and bills administrative services to us on a
monthly basis. Our costs related to such services amounted to approximately $66
million and $59 million for the six months ended June 30, 2002, and 2001,
respectively. As of June 30, 2002 and December 31, 2001, our payable related to
these costs was approximately $11 million and $13 million, respectively.
Note 10. 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. In June 2002, we also issued $600 million of 6.95% Senior Notes due
2012. The net proceeds from the sales were used primarily for the repayment of
the loans from PSEG. 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 June 30,
2002 and 2001 and for the quarters then ended.
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
--------- -------------- ------------- --------------- ----------
(Millions of Dollars)
For the three months ended June 30, 2002:
- ----------------------------------------
Revenues.................................... $1 $1,005 $4 -- $1,010
Operating Expenses.......................... 16 816 6 -- 838
--------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (15) 189 (2) -- 172
Other Income................................ 117 9 -- (126) --
Interest Income (Expense)................... (41) (14) 27 -- (28)
Income Taxes................................ 22 (73) (10) -- (61)
--------- -------------- ------------- --------------- ----------
Net Income.................................. $83 $111 $15 $(126) $83
========= ============== ============= =============== ==========
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
--------- -------------- ------------- --------------- ----------
(Millions of Dollars)
For the three months ended June 30, 2001:
- -----------------------------------------
Revenues.................................... -- $1,153 $6 -- $1,159
Operating Expenses.......................... 19 929 11 (1) 958
--------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (19) 224 (5) 1 201
Other Income (Expense)...................... 150 (4) -- (148) (2)
Interest Income (Expense)................... (41) (18) 35 (1) (25)
Income Taxes................................ 14 (78) (7) 1 (70)
--------- -------------- ------------- --------------- ----------
Net Income.................................. $104 $124 $23 $(147) $104
========= ============== ============= =============== ==========
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
--------- -------------- ------------- --------------- ----------
(Millions of Dollars)
For the six months ended June 30, 2002:
- ---------------------------------------
Revenues.................................... $1 $1,961 $6 $-- $1,968
Operating Expenses.......................... 36 1,522 10 -- 1,568
--------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (35) 439 (4) -- 400
Other Income................................ 273 13 -- (286) --
Interest Income (Expense)................... (82) (30) 56 -- (56)
Income Taxes................................ 47 (169) (19) -- (141)
--------- -------------- ------------- --------------- ----------
Net Income.................................. $203 $253 $33 $(286) $203
========= ============== ============= =============== ==========
Net Cash Provided By (Used In) Operating $(413) $600 $(23) $(203) $ (39)
Activities..................................
Net Cash Provided By (Used In) Investing (224) (516) (157) 311 (586)
Activities..................................
Net Cash Provided By (Used In)Financing 637 (80) 180 (108) 629
Activities..................................
For the six months ended June 30, 2001:
- ----------------------------------------
Revenues.................................... -- $2,280 $15 -- $2,295
Operating Expenses.......................... 48 1,785 25 -- 1,858
--------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (48) 495 (10) -- 437
Other Income (Loss)......................... 321 (5) -- (318) (2)
Interest Income (Expense)................... (112) (30) 53 -- (89)
Income Taxes................................ 45 (177) (8) -- (140)
--------- -------------- ------------- --------------- ----------
Net Income.................................. $206 $283 $35 $(318) $ 206
========= ============== ============= =============== ==========
Net Cash Provided By Operating Activities.. $124 $59 $740 $(330) $593
Net Cash (Used In) Investing Activities.... (331) (68) (740) 330 (809)
Net Cash Provided By Financing Activities.. 205 -- -- -- 205
As of June 30, 2002:
- --------------------
Current Assets.............................. $693 $898 $(137) $(48) $1,406
Property, Plant and Equipment, net.......... 48 2,194 1,171 -- 3,413
Noncurrent Assets........................... 3,052 1,067 1,269 (3,692) 1,696
--------- -------------- ------------- --------------- ----------
Total Assets................................ $3,793 $4,159 $2,303 $(3,740) $6,515
========= ============== ============= =============== ==========
Current Liabilities......................... $118 $877 $18 $(50) $963
Noncurrent Liabilities...................... 46 1,117 16 3 1,182
Note Payable-- Affiliated Company........... 59 1,150 -- (1,209) --
Long-Term Debt.............................. 2,514 -- 800 -- 3,314
Member's Equity............................. 1,056 1,015 1,469 (2,484) 1,056
--------- -------------- ------------- --------------- ----------
Total Liabilities and Member's Equity....... $3,793 $4,159 $2,303 $(3,740) $6,515
========= ============== ============= =============== ==========
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.
================================================================================
PSEG POWER LLC
================================================================================
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, 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 of the Quarter Ended June 30, 2002
For the quarter ended June 30, 2002, net income was $83 million, a decrease of
$21 million or 20% from the comparable period in 2001. For the six months ended
June 30, 2002, net income decreased $3 million or 1% from the comparable period
in 2001. The decrease in net income was due to lower margins on our energy
trading activities, outages at various generating stations, which resulted in us
purchasing electricity on the open market and providing this electricity to
PSE&G's customers under fixed BGS contract prices, lower MTC revenues,
respectively, due to two 2% rate reductions as part of PSE&G's deregulation plan
and an increase in Operation and Maintenance expense, partially offset by lower
fuel prices to produce electricity.
Our successful participation as an indirect supplier of energy to the state's
utilities, including PSE&G, involved in New Jersey's recent basic generation
service (BGS) auction will have a meaningful effect on our earnings,
particularly in the second half of the year when the new BGS contracts go into
effect. We surpassed our objective of securing contracts on more than 75% of our
capacity with suppliers that won the right to serve New Jersey's utilities,
including PSE&G, for a one-year period beginning August 1, 2002. Also, we
acquired the gas supply contracts and gas inventory from PSE&G for $183 million.
We also entered 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.
Future Outlook
For 2002, we expect to earn $460 million to $500 million. Our success as a
wholesale BGS provider will depend, in part, on our ability to meet our full
requirements under our 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 our 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 of 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 of our 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, 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. Since the majority of our generating facilities are concentrated in
the Northeast region, changes in energy and energy related prices in this
marketplace could materially affect our results. Also, changes in the rules and
regulation by FERC in the markets in which we operate, 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.
In addition, our earnings projections assume that we will continue to use energy
trading 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 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. Recently, the
energy trading markets have experienced a noticeable slowdown in the second
quarter that has affected our second quarter results and our 2002 earnings
projections. However, to date, the failure of certain internet-based energy
trading exchanges has not had a significant impact on liquidity in energy
trading markets where we conduct our business. 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.
RESULTS OF OPERATIONS
Operating Revenues
For the quarter and six months ended June 30, 2002, Revenues decreased $149
million or 13% and $327 million or 14%. The decreases were primarily due to
lower trading revenues of $227 million and $389 million for the quarter and six
months ended June 30, 2002 from the comparable periods in 2001, respectively,
due to lower energy trading volumes, lower prices as compared to 2001, and sales
of emission credits recorded in the first quarter of 2001. See Note 4. Financial
Instruments, Energy Trading and Risk Management for further discussion. Also
contributing to the decrease were lower revenues from our generation segment of
$23 million and $39 million in the quarter and six months ended June 30, 2002,
from the comparable periods in 2001, respectively. This is due primarily to
decreases of $8 million and $36 million for the quarter and six months ended
June 30, 2002 in MTC revenues, primarily due to two 2% rate reductions in August
2001 and February 2001. These rate reductions reduce the MTC revenues that PSE&G
remits to us as part of its BGS contract. These decreases were partially offset
by increases in BGS revenue of $22 million and $47 million for the quarter and
six months ended June 30, 2002, respectively, which resulted from additional
customers returning to PSE&G in 2002 from Third Party Suppliers (TPS) as
wholesale market prices exceeded fixed BGS rates. At June 30, 2002, TPS were
serving less than 0.3% of the customer load traditionally served by PSE&G as
compared to the June 30, 2001 level of 1.5%. Also, partially offsetting this
decrease were revenues of $97 million recorded in connection with our BGSS
contract with PSE&G for the quarter ended June 30, 2002, discussed above. Also
contributing were decreases for the quarter and six months ended June 30, 2002,
respectively of $9 million and $23 million in Interchange/Spot Market Sales and
$9 million and $12 million in ancillary services. A $17 million gain on a sale
of a fixed asset recorded in 2001 also contributed to the decrease in 2002.
Operating Expenses
Energy and Trading Costs
For the quarter and six months ended June 30, 2002, Energy and Trading Costs
decreased $126 million or 17% and $301 million or 21%. The decreases were
primarily due to lower trading costs of $200 million and $343 million for the
quarter and six months ended June 30, 2002 from the comparable periods in 2001,
respectively, primarily due to lower trading volumes (see corresponding decrease
in trading revenues). See Note 4. Financial Instruments, Energy Trading and Risk
Management for further discussion. Also, contributing to the decrease were lower
fuel expenses for oil ($12 million and $33 million, respectively) and gas ($14
million and $33 million), as a result of lower fuel prices in 2002. Partially
offsetting this decrease were increased costs of $91 million for the quarter
ended June 30, 2002 associated with our obligations under the BGSS contract with
PSE&G, discussed above.
Operation and Maintenance
Operation and Maintenance expense increased $14 million or 8% and $27 million or
8% for the quarter and six months ended June 30, 2002, from the comparable
periods in 2001, respectively. This was due primarily as a result of various
outages at our electric generating stations.
Depreciation and Amortization
Depreciation and Amortization expense increased $2 million or 8% and decreased
$5 million or 9% for the quarter and six months ended June 30, 2002, from the
comparable periods in 2001, respectively. The decrease for the six month period
was primarily due to decreases in the estimated cost of removal of our
generating stations in 2001.
Interest Expense
Interest Expense increased $3 million or 12% and decreased $33 million or 37%
for the quarter and six months ended June 30, 2002 from the comparable periods
in 2001, respectively. The decrease for the six month period is primarily due to
our recapitalization as our higher rate intercompany loans with PSE&G and PSEG
were replaced with lower rate external debt and equity. Our $2.786 billion
14.23% promissory note to PSE&G was repaid on January 31, 2001 and was replaced
on an interim basis by loans of $1.084 billion at 14.23% and $536 million at
7.11% from PSEG from January 2001 to April 2001. These loans were repaid with
the proceeds of our $1.8 billion Senior Notes issued in April 2001. We also
issued $600 million of 6.95% Senior Notes in June 2002. Also, interest
capitalization on various projects under construction was $22 million and $43
million for the quarter and six months ended June 30, 2002, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Financing Methodology
Our capital requirements and those of our subsidiaries are met and liquidity is
provided by internally generated cash flow and external financings. From time to
time, we 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. At times, we utilize intercompany dividends and
inter-company loans to satisfy various subsidiary needs and efficiently manage
us, and our subsidiaries' short-term cash needs. Any excess funds are invested
in accordance with guidelines adopted by our Board of Directors.
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 by us to make equity
investments in our subsidiaries. External funding is also provided through PSEG,
which may use proceeds of its financing transactions to make equity
contributions or loans to us. External financing may consist of public and
private capital market debt and equity transactions, bank revolving credit and
term loan facilities, commercial paper and/or project financings.
The availability and cost of external capital could be affected by our
performance as well as by the performance of PSEG and our subsidiaries. This
could include the degree of structural or regulatory separation between us and
our subsidiaries and affiliates and the potential impact of affiliate ratings on
our credit quality. Additionally, compliance with applicable financial covenants
will depend upon future financial position and levels of earnings and net cash
flows, as to which no assurances can be given.
Financing for two of our projects under construction in Lawrenceburg, Indiana
and Waterford, Ohio has been provided by non-recourse project financing
transactions. These consist of loans from banks and other lenders that are
secured by the project and the special purpose subsidiary assets and/or cash
flows. 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.
Further, the consequences of permitting a project-level default include loss of
any invested equity by the parent.
Over the next several years, we and our Lawrenceburg and Waterford subsidiaries
and PSEG will be required to refinance maturing debt, expect to incur additional
debt and provide equity to fund investment activity. 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
Our senior debt indenture and the credit agreements of our Lawrenceburg and
Waterford subsidiaries contain cross-default provisions under which a default by
us involving an aggregate of $50 million of indebtedness in other agreements
would result in a default and the potential acceleration of payment under such
indenture and credit agreements. In addition, as discussed below, we depend on
PSEG's credit facilities for our short-term financing needs. Under PSEG's credit
agreements, a default with respect to specified indebtedness in an aggregate
amount of $50 million for each of PSEG, us and PSE&G and $5 million for PSEG
Energy Holdings, including relevant equity contribution obligations in
subsidiaries' non-recourse transactions, could cause a cross-default in our
credit agreements.
If such a default were to occur, lenders, or the debt holders under our
indenture, could determine that debt payment obligations may be accelerated as a
result of a cross-default. A declaration of a cross-default could severely limit
our liquidity and restrict our ability to meet our debt, capital and, in extreme
cases, operational cash requirements. Any inability to satisfy required
covenants and/or borrowing conditions could have a similar impact. In the event
of any likely default or failure to satisfy covenants or conditions, we would
seek to renegotiate terms of the agreements with the lenders. No assurances can
be given as to whether these efforts would be successful. This would have a
material adverse effect on our financial condition, results of operations and
net cash flows, as well as those of our subsidiaries.
In addition, the credit agreements of PSEG and our Lawrenceburg and Waterford
subsidiaries generally contain provisions under which the lenders could refuse
to advance loans in the event of a material adverse change in the borrower's,
and, as may be relevant, our business or financial condition. In the event that
PSEG, we or the lenders in any of these credit agreements determine that a
material adverse change has occurred, advances of loan funds may not be
advanced.
PSEG's credit agreements contain maximum debt to equity ratios, minimum cash
flow tests and other restrictive covenants and conditions to borrowing.
Compliance with applicable financial covenants will depend upon PSEG's future
financial position and the level of earnings and cash flow, as to which no
assurances can be given.
Our debt indenture and such credit agreements 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 PSEG may be subject to increased interest costs on certain
bank debt. Also, in connection with our energy trading business, 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 our energy trading
business. 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 our energy trading operations. In addition, our
counterparties may require us to meet margin or other security requirements,
which may include cash payments. We may also have to provide credit support for
certain of our equity commitments if we lose our investment grade rating.
Short-Term Liquidity
We have no such credit facilities and rely on PSEG for our short-term financing
needs. As of June 30, 2002, Power had no short-term borrowings payable to 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 June 30, 2002.
Expiration Total Primary
Company Date Facility Purpose
- ---------------------------------------- ------------------- ------------------- ------------------
(Millions of Dollars)
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 June 30, 2002, PSEG has $744 million of commercial paper outstanding and
$349 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 commerical 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. PSEG plans to issue
equity-linked securities before year-end, which will lower this ratio. PSEG's
current forecasts do not indicate that it will exceed the required ratio of debt
to total capitalization in its credit facilities, even if PSEG does not issue
any equity-linked securities. Also, as part of its financial planning forecast,
PSEG will perform stress tests on its financial covenants. These tests include a
consideration of the impacts of potential asset impairments, foreign currency
fluctuations and other items. As of June 30, 2002, PSEG was in compliance with
this covenant and expects to continue to meet the ratio requirements of debt to
total capitalization in the future. 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 Unsecured 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 its strategy to continue to develop as a
profitable, growth-oriented supplier in the wholesale power market. Our
subsidiaries have substantial commitments as part of their growth strategies and
ongoing construction programs. We expect that the majority of our capital
requirements over the next five years will come from internally generated funds,
with the balance to be provided by the issuance of debt at the subsidiary or
project level and equity contributions from PSEG. Projected construction and
investment expenditures for the next five years are as follows:
2002 2003 2004 2005 2006
-------- --------- --------- --------- ---------
(Millions of Dollars)
Construction/investment expenditures....... $960 $700 $340 $250 $230
For the six months ended June 30, 2002 and 2001, we had net plant additions of
$496 million and $763 million, respectively. The majority of these additions are
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 and SFAS 144 and EITF 02-03, see Note 2.
Accounting Matters.
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of: Emerging
Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" (EITF 98-10), EITF 99-19, "Reporting
Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), and EITF
02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 02-03), for our energy trading business; and SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities", as amended (SFAS
133), to account for our various hedging transactions.
Accounting, Valuation and Presentation of Our Energy Trading Business
Accounting - We account for our energy trading business in accordance with the
provisions of EITF 98-10, which requires that energy trading contracts be marked
to market with gains and losses included in current earnings.
Valuation - Since the vast majority of our energy trading contracts have terms
of less than two years, valuations for these contracts are readily obtainable
from the market exchanges, such as PJM, and over the counter quotations. The
valuations also include a credit reserve and a liquidity reserve, which is
determined using financial quotation systems, monthly bid-ask prices and spread
percentages. We have consistently applied this valuation methodology for each
reporting period presented. The fair values of these contracts and a more
detailed discussion of credit risk are reflected in Note 4. Financial
Instruments, Energy Trading and Risk Management.
Presentation - EITF 99-19 provided guidance on the issue of whether a company
should report revenue based on the gross amount billed to the customer or the
net amount retained. The guidance states that whether a company should recognize
revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We report swaps,
futures, option premiums, firm transmission rights, transmission congestion
credits, and purchases and sales of emission allowances on a net basis. One of
the primary drivers of our determination that these contracts should be
presented on a gross basis was that we retain counterparty risk. Beginning in
the third quarter of 2002, we will report all energy trading revenues and energy
trading costs on a net basis under EITF 02-3. For additional information, see
Note 2. Accounting Matters.
SFAS 133 - Accounting for Derivative Instruments and Hedging Activities
SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in OCI, net of tax. Amounts in accumulated OCI are ultimately
recognized in earnings when the related hedged forecasted transaction occurs.
The change in the fair value of the ineffective portion of the derivative
instrument designated as a cash flow hedge is recorded in earnings. Derivative
instruments that have not been designated as hedges are adjusted to fair value
through earnings. We have entered into several derivative instruments, including
hedges of anticipated electric and gas purchases and interest rate swaps, which
have been designated as cash flow hedges.
The fair value of the derivative instruments is determined by reference to
quoted market prices, listed contracts, published quotations or quotations from
counterparties. In the absence thereof, we utilize mathematical models based on
current and historical data. The fair value of most of our derivatives is
determined based upon quoted market prices. Therefore, the effect on earnings of
valuations from our models is minimal.
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 gas contract
transfer 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 similar manner as PSE&G did. Gains or losses from these
derivatives will be recovered from customers through 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 will be deferred and reported as a component of OCI. The
accumulated OCI will be reclassified to earnings in the period in which the
hedged transaction affects earnings.
For additional information regarding Derivative Financial Instruments, See Note
4 - Financial Instruments Energy Trading and Risk Management - Derivative
Financial Instruments and Hedging Activities of Notes.
ITEM 3. QUALITATIVE AND QUANTITATIVE
DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our market risk sensitive instruments and positions
is the potential loss arising from adverse changes in commodity prices and
interest rates as discussed in the notes to the financial statements. Our policy
is to use derivatives to manage risk consistent with our business plans and
prudent practices. We have a Risk Management Committee (RMC) comprised of
executive officers, which utilizes an independent risk oversight function to
ensure compliance with corporate policies and prudent risk management practices.
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.
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 and gas
customer commitments.
We use a value-at-risk (VAR) model to assess the market risk of our commodity
business. This model includes fixed price sales commitments, owned generation,
native load requirements, physical contracts and financial derivative
instruments. VAR represents the potential gains or losses for instruments or
portfolios due to changes in market factors, for a specified time period and
confidence level. PSEG estimates VAR across its commodity business using a model
with historical volatilities and correlations.
The RMC has established a VAR threshold of $75 million with our Board of
Directors and set an internal limit of $50 million and a trip limit of $40
million. If the $50 million threshold is reached, the RMC would be notified and
the portfolio would be closely monitored to reduce risk and potential adverse
movements.
The measured VAR using a variance/co-variance model with a 95% confidence level
and assuming a one-week time horizon as of June 30, 2002 was approximately $25
million, compared to the December 31, 2001 level of $14 million, which was
calculated using various controls and conservative assumptions, such as a 50%
success rate in the BGS Auction. This estimate, however, is not necessarily
indicative of actual results, which may differ due to the fact that actual
market rate fluctuations may differ from forecasted fluctuations and due to the
fact that the portfolio of hedging instruments may change over the holding
period and due to certain assumptions embedded in the calculation.
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 June 30, 2002 over 97% of the
credit exposure (mark to market plus net receivables and payables) for our
trading business was with investment grade counterparties. As of June 30, 2002,
our trading business had over 80 active counterparties.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We are subject to credit policies established by PSEG that we
believe significantly minimize credit risk. These policies include an evaluation
of potential counterparties' financial condition (including credit rating),
collateral requirements under certain circumstances and the use of standardized
agreements, which may allow for the netting of positive and negative exposures
associated with a single counterparty. We also establish credit reserves for our
energy trading contracts based on various factors, including individual
counterparty's position, credit rating, default possibility and recovery rates.
As a result of the BGS auction, we have contracted to provide generating
capacity to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. These bilateral contracts are subject to
credit risk. This credit risk relates to the ability of counterparties to meet
their payment obligations for the power delivered under each BGS contract. This
risk is substantially higher than the risk associated with potential nonpayment
by PSE&G under the BGS contract expiring July 31, 2002 since PSE&G is a
rate-regulated entity. 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.
FORWARD-LOOKING STATEMENTS
Except for the historical information contained herein, certain of the matters
discussed in this report 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
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.
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 are updated below. See information
on the following proceedings at the pages indicated:
(1) Form 10-K, Pages 14 and 15. See Page 24. Administrative proceedings before
the NJDEP under the FWPCA for certain electric generating stations.
(2) Form 10-K, Page 17. See Page 27. DOE Overcharges, Docket No. 01-592C.
(3) Form 10-K, Pages 16 and 17. See Page 27. DOE not taking possession of spent
nuclear fuel, Docket No. 01-551C.
(4) Form 10-K, Pages 16 and 51. See Page 7. Investigation and additional
investigation by the EPA regarding the Passaic River site. Docket
No.EX93060255.
ITEM 5. OTHER INFORMATION
Certain information reported under our 2001 Annual Report to the SEC and our
Amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002 are
updated below. References are to the related pages on the Form 10-K or Form
10-Q/A as printed and distributed.
Gas Contract Transfer
Form 10-K, page 9 and Amended Form 10-Q/A, page 24.
On August 11, 2000, PSE&G filed a gas merchant restructuring plan with the BPU.
The BPU approved an amended stipulation, which authorized the transfer of
PSE&G's gas supply business, including its interstate capacity, storage and gas
supply contracts to us which will, under a requirements contract, provide gas
supply to PSE&G to serve its Basic Gas Supply Service (BGSS) customers. On April
17, 2002, the BPU issued the final order approving the transfer of PSE&G's gas
supply business, including its interstate capacity, storage and gas supply
contracts to us. We entered into a BGSS contract with PSE&G as required under
the above BPU order. The transfer took place on May 1, 2002 at the book value of
approximately $183 million. The initial term of the contract ends on March 31,
2004 and PSE&G has the option to extend the term for an additional three years.
Under this agreement, we will provide the full requirements needed by PSE&G to
render service under its BGSS tariff rate schedules.
The gas contract transfer is expected to increase our commodity risk. Gas
residential commodity costs are currently recovered through PSE&G's adjustment
clauses that are periodically trued-up to actual costs and reset. Effective with
the gas contract transfer, PSE&G pays us for gas provided to PSE&G for its gas
distribution customers. Industrial and commercial BGSS customers will be priced
under PSE&G's Market Priced Gas Service (MPGS). Residential BGSS customers will
remain under current pricing until April 1, 2004, after which, subject to
further BPU approval those residential gas customers would also move to MPGS
service.
Nuclear Fuel Disposal
Form 10-K, page 17 and Amended Form 10-Q/A, page 25. Under the NWPA, the DOE was
required to begin taking possession of all spent nuclear fuel generated by our
nuclear units for disposal by no later than 1998. DOE construction of a
permanent disposal facility has not begun and DOE has announced that it does not
expect a facility to be available earlier than 2010.
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.
Uranium Enrichment Decontamination and Decommissioning Fund
Form 10-K, page 18. In accordance with the EPAct, domestic entities that own
nuclear generating stations are required to pay into a decontamination and
decommissioning fund, based on their past purchases of U.S. government
enrichment services. Along with other nuclear generator owners, PSEG filed suit
in the U.S. Court of Claims and in the U.S. District Court, Southern District of
New York to recover these costs. In July 2002, PSEG withdrew from this lawsuit
without prejudice, due to an unfavorable decision against another nuclear
generator owner in the lawsuit.
FERC Order related to PJM Restructuring
New Matter: Atlantic City Electric Co., et al. v. Federal Energy Regulatory
Commission. 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 and 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, as
to PSE&G's situation, FERC could not accomplish a generic existing precedent, it
was first necessary to make a particularized finding with respect to the public
interest, which was not done here. This decision could be subject to an appeal
to the United States Supreme Court by the respondents, including the FERC.
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
(B) Reports on Form 8-K and Form 8-K/A:
-----------------------------------
Date Form Items
----------------------------------------
July 17, 2002 8-K Items 5 and 7
July 29, 2002 8-K/A Items 5 and 7
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: Patricia A. Rado
--------------------------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: July 29, 2002