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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 March 31, 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 16
Item 3. Qualitative and Quantitative Disclosures about Market Risk 21
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings 23
Item 5. Other Information 23
Item 6. Exhibits and Reports on Form 8-K 25
Signature 26
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PSEG POWER LLC
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PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
(Unaudited)
For the Quarters Ended
March 31,
-----------------------
2002 2001
---------- ----------
OPERATING REVENUES
Generation ...................................... $ 625 $ 561
Trading ......................................... 430 587
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Total Operating Revenues ............... 1,055 1,148
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OPERATING EXPENSES
Energy Costs .................................... 221 173
Trading Costs ................................... 398 536
Operation and Maintenance ....................... 181 168
Depreciation and Amortization ................... 23 30
Taxes Other Than Income Taxes ................... 4 5
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Total Operating Expenses .................... 827 912
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OPERATING INCOME .................................... 228 236
Interest Expense - Net .............................. (28) (64)
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INCOME BEFORE INCOME TAXES .......................... 200 172
Income Taxes ........................................ (80) (70)
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EARNINGS AVAILABLE TO PUBLIC
SERVICE ENTERPRISE GROUP
INCORPORATED ........................................ $ 120 $ 102
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PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
(Unaudited)
March 31, December 31,
2002 2001
--------- ------------
CURRENT ASSETS
Cash and Cash Equivalents ................................... $ 11 $ 9
Accounts Receivable:
Affiliated Companies ...................................... -- 22
Other ..................................................... 122 270
Fuel ........................................................ 69 76
Materials and Supplies, Net of Valuation
Reserves - 2002 and 2001, $2 .............................. 127 124
Energy Trading Contracts .................................... 294 422
Other ....................................................... 17 15
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Total Current Assets ................................... 640 938
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PROPERTY, PLANT AND EQUIPMENT
Property, Plant and Equipment ............................... 4,483 4,238
Less: Accumulated Depreciation and Amortization ........... (1,292) (1,253)
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Net Property, Plant and Equipment ......................... 3,191 2,985
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NONCURRENT ASSETS
Deferred Income Taxes ....................................... 563 579
Nuclear Decommissioning Fund ................................ 815 817
Other ....................................................... 236 178
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Total Noncurrent Assets ................................ 1,614 1,574
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TOTAL ASSETS ..................................................... $ 5,445 $ 5,497
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PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
(Unaudited)
March 31, December 31,
2002 2001
--------- -------------
CURRENT LIABILITIES
Accounts Payable:
Affiliated Companies ........................... $ 56 $ --
Other .......................................... 165 333
Energy Trading Contracts .......................... 258 434
Other ............................................. 159 111
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Total Current Liabilities .................... 638 878
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NONCURRENT LIABILITIES
Nuclear Decommissioning ........................... 815 817
Cost of Removal ................................... 145 146
Environmental ..................................... 53 53
Other ............................................. 92 58
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Total Noncurrent Liabilities ................. 1,105 1,074
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COMMITMENTS AND CONTINGENT LIABILITIES .............. -- --
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CAPITALIZATION
Project Level Non-Recourse Debt ................... 800 770
Long-Term Debt .................................... 1,915 1,915
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Total Long-Term Debt ......................... 2,715 2,685
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MEMBER'S EQUITY
Contributed Capital ............................... 1,350 1,350
Basis Adjustment .................................. (986) (986)
Retained Earnings ................................. 618 498
Accumulated Other Comprehensive Income/(Loss) ..... 5 (2)
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Total Member's Equity ........................ 987 860
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TOTAL LIABILITIES AND CAPITALIZATION ................ $ 5,445 $ 5,497
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PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
For the Quarters Ended
March 31,
----------------------
2002 2001
----------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income .................................................................... $ 120 $ 102
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization ............................................... 23 30
Amortization of Nuclear Fuel ................................................ 24 27
Interest Capitalized During Construction .................................... (21) (7)
Provision for Deferred Income Taxes and ITC - net ........................... 16 12
Net Changes in certain current assets and liabilities:
Accounts Receivable ...................................................... 148 124
Inventory - Fuel and Materials and Supplies .............................. 4 4
Accounts Payable ......................................................... (90) 2
Other Current Assets and Liabilities ..................................... (2) 22
Other ....................................................................... 5 (34)
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Net Cash Provided By Operating Activities ................................ 227 282
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, excluding Capitalized
Interest ........................................................................ (216) (282)
Contributions to Decommissioning and Other Special Funds .................. (39) (30)
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Net Cash Used In Investing Activities .................................... (255) (312)
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CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of Long-Term Debt .................................................... 30 1,620
Repayment of Note Payable-Affiliated Company .................................. -- (2,786)
Contributed Capital ........................................................... -- 1,200
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Net Cash Provided By Financing Activities ................................ 30 34
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Net Change In Cash And Cash Equivalents ......................................... 2 4
Cash And Cash Equivalents At Beginning Of Period ................................ 9 20
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Cash And Cash Equivalents At End Of Period ...................................... $ 11 $ 24
======= =======
Income Taxes (Refunded)/Paid .................................................... $ (5) $ 15
Interest Paid ................................................................... $ 3 $ 86
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PSEG POWER LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, a New Jersey corporation with its
principal executive offices at 80 Park Plaza, Newark, New Jersey 07102 and its
consolidated subsidiaries. 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. The energy trading segment also earns revenues
through financial transactions, including swaps, options and futures in the
electricity 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. These Notes update and
supplement matters discussed in our Annual Report on Form 10-K.
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. 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
On January 1, 2002 we adopted Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS
142, goodwill is considered a nonamortizable asset and is subject to an annual
review for impairment and an interim review when events or circumstances occur.
In 2001, we had recorded goodwill of approximately $22 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. The financial impact of adopting SFAS 142
is being evaluated and is not likely to be material to our financial position
and statement of operations. We are required to complete our analysis of
implementing SFAS No. 142 by June 30, 2002, and the related financial statement
impact is required to be recorded by December 31, 2002.
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PSEG POWER LLC
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
On January 1, 2002, we adopted SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). 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. Discontinued operations will no longer be measured at
net realizable value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the reporting of discontinued operations. The
adoption of this standard did not have any impact on our financial position or
results of operations.
In July 2001, the Financial Accounting Standards Board (FASB), issued SFAS
No. 143, "Accounting for Asset Retirement Obligations" (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. We are currently evaluating the effect of this guidance and cannot predict
the impact on our financial position or results of operations; however, such
impact could be material.
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 $701 million and $506 million as
of March 31, 2002 and December 31, 2001, respectively. The amount of our
exposure under these guarantees was $206 million and $153 million as of March
31, 2002 and December 31, 2001, respectively.
As of March 31, 2002, letters of credit were issued in the amount of
approximately $122 million. These letters of credit are in support of our
trading business and various contractual obligations.
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. 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 U.S. 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 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 our 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), and carbon dioxide
(CO2), particulate matter, and mercury from these units. The estimated cost of
the program is $355 million and such costs, when incurred, will be capitalized
as plant additions. We also paid a $1.4 million civil penalty, and will pay up
to $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 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. The unit is
expected to begin operating in June 2002.
New Generation and Development
PSEG Power New York Inc., an indirect, wholly-owned subsidiary, is in the
process developing the Bethlehem Energy Center, a 750 MW combined-cycle power
plant that will replace the 400 MW Albany Steam Station. Total costs for this
project will be approximately $450 million with expenditures to date of
approximately $59 million. Construction is expected to begin in the summer of
2002. The expected completion date is in June 2004, at which time the existing
station will be retired.
We are constructing a 550 MW natural gas-fired, combined cycle electric
generation plant at Bergen Generation Station at a cost of approximately $319
million with completion expected in June 2002. Total expenditures to date have
been $299 million. We are also constructing a 1,186 MW combined cycle generation
plant at Linden, New Jersey with costs estimated at approximately $600 million
and expenditures to date of approximately $282 million. The expected completion
date is in May 2003 at which time existing capacity of 445 MW will be retired.
We are constructing through indirect, wholly-owned subsidiaries, two
natural gas-fired combined cycle electric generation plants in Waterford, Ohio
(850 MW) and Lawrenceburg, Indiana (1,150 MW) at an aggregate total cost of $1.2
billion. Total expenditures to date on these projects have been approximately
$968 million. The required estimated equity investment in these projects is
approximately $400 million, with the remainder being financed with non-recourse
debt. As of March 31, 2002, approximately $168 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. The agreement expires if
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. The
Waterford project will not begin commerical operation as a single-cycle facility
in June 2002 as originally scheduled. Both the Waterford and Lawrenceburg
combined-cycle facilities are currently scheduled to achieve commercial
operation in 2003.
We have commitments to purchase equipment and services, which are
consistent with our current plans to develop additional generating capacity. The
aggregate amount due under these commitments is approximately $480 million, the
majority of which are included in estimated costs for the projects discussed
above.
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 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, capacity, fixed transmission rights and emissions
allowances in the spot, forward and futures markets primarily in
Pennsylvania-New Jersey-Maryland Power Pool (PJM), but also throughout our
target market, which we refer to as the Super Region, which extends from Maine
to the Carolinas and the Atlantic Coast to Indiana. We are also involved in
financial transactions that include swaps, options and futures in the
electricity markets.
Our energy trading contracts are recorded under Emerging Issues Task Force
(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.
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 Trading 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.
Energy Trading
For our energy trading segment for the quarters ended March 31, 2002 and
2001, we recorded net margins of $29.6 million and $48.8 million, respectively,
as shown below:
For the Quarter Ended
March 31,
---------------------------------
2002 2001
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(Millions of Dollars)
Realized Gains................... $1.1 $47.1
Unrealized Gains................. 30.3 3.6
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Gross Margin................... $31.4 $50.7
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Net Margin*. .................. $29.6 $48.8
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* Net Margin equals Gross Margin less Broker Fees and other trading-related
expenses of $1.8 million and $1.9 million, for the quarters ended March 31, 2002
and March 31, 2001, respectively.
Generation
For our generation business for the quarters ended March 31, 2002 and 2001,
we recorded gross margins of $(4.5) million and $0.2 million, respectively, as
shown below:
For the Quarter Ended
March 31,
---------------------------------
2002 2001
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(Millions of Dollars)
Realized (Losses)................ $(12.0) $--
Unrealized Gains................. 7.5 0.2
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Gross Margin................... $(4.5) $0.2
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As of March 31, 2002, the fair value of our energy contracts in trading and
generation segments was $49.8 million, described below, of which over 90% of the
contracts have terms of two years or less.
(Millions of Dollars)
----------------------------------------------------------------
Energy Trading Generation Total
--------------------- ------------------- ----------------
Fair Value December 31, 2001.............. $9.7 $(11.6) $(1.9)
Realized (Gains)/Losses................... (1.1) 12.0 10.9
Unrealized Gains.......................... 30.3 7.5 37.8
Fair Value of New Contracts............... 3.0 -- 3.0
--------------------- ------------------- ----------------
Fair Value March 31, 2002................. $41.9 $7.9 $49.8
===================== =================== ================
The fair values as of March 31, 2002 and December 31, 2001 of financial
instruments related to the energy commodities in our energy trading segment are
summarized in the following table:
March 31, 2002 December 31, 2001
----------------------------- --------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
------------------------------ ---------------------- ---------
(Millions) (Millions)
Futures and Options NYMEX. 14.0 12.0 $(1.5) -- 16.0 $(1.2)
Physical forwards......... 53.0 48.0 $9.9 41.0 9.0 $(2.6)
Options-- OTC............. 2.0 470.0 $16.7 8.0 717.0 $(18.7)
Swaps..................... -- 1,151.0 $3.5 -- 1,047.0 $23.9
Emission Allowances....... -- -- $13.3 -- -- $8.3
The fair values as of March 31, 2002 and December 31, 2001 of financial
instruments related to the energy commodities in our generation segment are
summarized in the following table:
March 31, 2002 December 31, 2001
------------------------------ ------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
------------------------------ -------------------------------
(Millions) (Millions)
Futures and Options NYMEX. -- 1.0 $1.2 -- -- --
Physical forwards......... -- -- -- -- -- --
Options-- OTC............. -- 79.0 $5.4 -- 86.0 $(10.4)
Swaps..................... -- 64.0 $1.3 -- 84.0 $(1.2)
Emission Allowances....... -- -- -- -- -- --
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 March 31, 2002 was
approximately $4.9 million.
Derivative Instruments and Hedging Activities
Commodity Contracts
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.
The BPU approved an auction to identify energy suppliers for the Basic
Generation Service (BGS) beginning on August 1, 2002. We did not participate
directly in the auction but agreed to supply power to several of the direct
bidders, securing contracts for a substantial portion of our generation
capacity. On February 15, 2002 the BPU approved the BGS auction results.
As a result of the BGS auction, we have entered into BGS/Third Party
Suppliers agreements with several counterparties who won bids to deliver energy,
capacity, transmission and ancillary services to serve the native load of
various New Jersey utilities at a fixed price. In order to hedge a portion of
our forecasted 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. As a
result, we 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
March 31, 2002, the fair value of these hedges were $11.1 million with
offsetting charges to Other Comprehensive Income (OCI) of $6.5 million
(after-tax). These hedges will mature in 2003.
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. We estimate VAR across our commodity business using
a model with historical volatilities and correlations.
The Risk Management Committee of PSEG (RMC) has established a VAR threshold
of $75 million with our Board of Directors and set an internal limit of $50
million. If the $50 million threshold is reached, the RMC is notified and the
portfolio is 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 March 31, 2002 was
approximately $22 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.
The absence of a PJM price cap in situations involving emergency purchases
and the potential for plant outages may cause extreme price movements that could
have a material adverse impact on our financial condition, results of operations
and net cash flows.
Credit Risk
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 minimizes our exposure to 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, 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.
Note 5. Income Taxes
Quarter Ended March 31,
-----------------------------
2002 2001
------------- -------------
Federal tax provision at statutory rate..................... 35.0% 35.0%
New Jersey Corporate Business Tax, net of Federal benefit... 5.9% 5.9%
Other-- net................................................. (0.9)% (0.2)%
------------- -------------
Effective Income Tax Rate............................. 40.0% 40.7%
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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. Our organizational structure
supports these segments.
Generation
The generation segment of our business earns revenues by selling energy on
a wholesale basis under contract to power marketers and to 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. Our energy trading segment also earns
revenues through financial transactions, including swaps, options and futures in
the electricity markets.
Information related to the segments of our business is detailed below:
Energy Consolidated
Generation Trading Total
-------------- --------------- ---------------
(Millions of Dollars)
For the Quarter Ended March 31, 2002:
- ------------------------------------
Total Revenues........................................ $625 $430 $1,055
Operating Income Before Income Taxes.................. 198 30 228
Income Taxes.......................................... 68 12 80
Net Income............................................ $102 $18 $120
============== =============== ===============
As of March 31, 2002:
Total Assets.......................................... $4,888 $557 $5,445
============== =============== ===============
Energy Consolidated
Generation Trading Total
-------------- --------------- ---------------
(Millions of Dollars)
For the Quarter Ended March 31, 2001:
- ------------------------------------
Total Revenues........................................ $561 $587 $1,148
Operating Income Before Income Taxes.................. 187 49 236
Income Taxes.......................................... 50 20 70
Net Income............................................ $73 $29 $102
============== =============== ===============
As of December 31, 2001:
Total Assets.......................................... $4,707 $790 $5,497
============== =============== ===============
Note 7. Comprehensive Income
Comprehensive Income, Net of Tax, is detailed below:
For the Quarter Ended
----------------------------------------
March 31, 2002 March 31, 2001
(Millions of Dollars)
----------------------------------------
Net Income............................................. $120.0 $102.0
Change in the Fair Value of Financial Instruments (A).. 8.2 2.3
Reclassification Adjustments for Net Amount included
In Net Income (B).................................... (0.8) (0.6)
------------------ -----------------
Comprehensive Income................................... $127.4 $103.7
================== =================
<FN>
(A) Net of tax of $(5.1) million and $(1.2) million for the quarters ended
March 31, 2002 and 2001, respectively.
(B) Net of tax of $(0.5) million and $(0.2) million for the quarters ended
March 31, 2002 and 2001, respectively.
</FN>
Note 8. Property, Plant and Equipment
Information related to Property, Plant and Equipment is detailed below:
March 31, December 31,
2002 2001
-----------------------------
(Millions of Dollars)
Property, Plant and Equipment
-----------------------------
Plant in Service:
Fossil Production........................................ $1,910 $1,898
Nuclear Production....................................... 181 154
-----------------------------
Total Plant in Service...................................... 2,091 2,052
-----------------------------
Nuclear Fuel in Service..................................... 561 486
Construction Work in Progress Including Nuclear Fuel........ 1,814 1,693
Other....................................................... 17 7
-----------------------------
Total....................................................... $4,483 $4,238
=============================
Interest related to capital projects is capitalized in accordance with SFAS
No. 34, "Capitalization of Interest Cost". For the quarters ended March 31, 2002
and 2001, Interest Capitalized During Construction (IDC) amounted to $21 million
and $7 million, respectively.
Note 9. Related Party Transactions
PSEG & 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.
As of March 31, 2002, we had a note payable to PSEG of approximately $215
million for short term funding needs. As of December 31, 2001, our note payable
to PSEG was $164 million. Our interest expense related to these borrowings was
$1.4 million and $10.7 million for the quarters ended March 31, 2002 and 2001,
respectively.
Effective with the asset transfer, we charge PSE&G for a market transition
charge (MTC) and the energy and capacity provided to meet PSE&G's BGS
requirements. These rates were established by the BPU. For the quarters ended
March 31, 2002 and 2001, we charged PSE&G approximately $460 million and $463
million, respectively, for MTC and BGS. As of March 31, 2002 and December 31,
2001, our receivable from PSE&G relating to these costs was approximately $154
million and $158 million, respectively. For the quarters ended March 31, 2002
and 2001, we purchased energy and capacity from PSE&G at the market price of
approximately $28 million and $43 million, respectively, which PSE&G purchased
under various non-utility generation (NUG) contracts. As of March 31, 2002 and
December 31, 2001, our payable to PSE&G relating to these purchases was
approximately $11 million and $7 million, respectively.
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
$35 million and $27 million for the quarters ended March 31, 2002 and 2001,
respectively. As of March 31, 2002 and December 31, 2001, our payable related to
these costs was approximately $16 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. The net proceeds from the sale of the Senior Notes 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
March 31, 2002 and 2001 and for the quarters then ended.
================================================================================
PSEG POWER LLC
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Concluded
Guarantor Other Consolidating
Power Subsidiaries Subsidiaries Adjustments Total
---------- -------------- ------------- --------------- ----------
(Millions of Dollars)
For the Quarter ended March 31, 2002:
Revenues.................................... -- $1,053 $2 -- $1,055
Operating Expenses.......................... 20 803 4 -- 827
---------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (20) 250 (2) -- 228
Other Income (Loss)......................... 156 (1) -- (155) --
Interest Expense............................ (41) (16) 29 -- (28)
Income Taxes................................ 25 (96) (9) -- (80)
---------- -------------- ------------- --------------- ----------
Net Income (Loss)........................... $120 $137 $18 $(155) $120
========== ============== ============= =============== ==========
Net Cash Provided By (Used In) Operating 144 312 227 (456) $227
Activities..................................
Net Cash Provided By (Used In) Investing
Activities.................................. (224) -- -- (31) (255)
Net Cash Provided By Financing Activities... 79 (176) 30 97 30
For the Quarter ended March 31, 2001:
Revenues.................................... $-- $1,139 $9 -- $1,148
Operating Expenses.......................... 29 869 14 -- 912
---------- -------------- ------------- --------------- ----------
Operating Income (Loss)..................... (29) 270 (5) -- 236
Other Income (Loss)......................... 171 (1) -- (170) --
Interest Expense............................ (71) (12) 18 1 (64)
Income Taxes................................ 31 (99) (1) (1) (70)
---------- -------------- ------------- --------------- ----------
Net Income (Loss)........................... $102 $158 $12 $(170) $102
========== ============== ============= =============== ==========
Net Cash Provided By (Used In) Operating 144 312 227 (401) $282
Activities..................................
Net Cash Provided By (Used In) Investing (224) -- -- (88) (312)
Activities..................................
Net Cash Provided By Financing Activities... 79 (176) 30 101 34
As of March 31, 2002:
Current Assets.............................. 9 619 32 (20) $640
Property, Plant and Equipment, net.......... 50 2,036 1,105 -- 3,191
Noncurrent Assets........................... 3,023 881 1,288 (3,578) 1,614
----------- -------------- ------------- --------------- ----------
Total Assets................................ $3,082 $3,536 $2,425 $(3,598) $5,445
=========== ============== ============= =============== ==========
Current Liabilities......................... 57 436 254 $(109) $638
Noncurrent Liabilities...................... 44 1,044 17 -- 1,105
Note Payable-- Affiliated Company........... 79 1,150 -- (1,229) --
Long-Term Debt.............................. 1,915 -- 800 -- 2,715
Member's Equity............................. 987 906 1,354 (2,260) 987
----------- -------------- ------------- --------------- ----------
Total Liabilities and Member's Equity....... $3,082 $3,536 $2,425 $(3,598) $5,445
=========== ============== ============= =============== ==========
As of December 31, 2001:
Current Assets.............................. $ 7 $ 892 $ 64 $ (25) $938
Property, Plant and Equipment, net.......... 40 1,987 958 -- 2,985
Noncurrent Assets........................... 2,835 783 1,230 (3,274) 1,574
----------- -------------- ------------- -------------- ----------
Total Assets................................ $2,882 $3,662 $2,252 $(3,299) $5,497
=========== ============== ============= ============== ==========
Current Liabilities......................... $ 56 $ 631 $ 215 $ (24) $ 878
Noncurrent Liabilities...................... 30 1,028 16 -- 1,074
Note Payable-- Affiliated Company........... 21 1,150 -- (1,171) --
Long-Term Debt.............................. 1,915 -- 770 -- 2,685
Member's Equity............................. 860 853 1,251 (2,104) 860
----------- -------------- ------------- -------------- ----------
Total Liabilities and Member's Equity....... $2,882 $3,662 $2,252 $(3,299) $5,497
=========== ============== ============= ============== ==========
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
Overview of the Quarter Ended March 31, 2002 and Future Outlook
For the quarter ended March 31, 2002, net income increased $18 million or
18%, compared to the quarter ended March 31, 2001. This increase was due
primarily to higher revenues from spot sales into the market and from generation
service to PSE&G's customers as many customers who had migrated to other energy
suppliers returned to PSE&G to be served under the BGS Contract. Results were
also favorably impacted by lower fuel prices to produce electricity. This was
partially offset by lower trading margins and lower revenues resulting from the
2% rate reduction in February 2001 totaling $28 million as part of PSE&G's
deregulation plan, and a $13 million increase in Operation and Maintenance
expense.
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.
Unless the context otherwise indicates, all references to "Power," "we,"
"us" or "our" herein means PSEG Power LLC (Power), a New Jersey corporation with
its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102 and
its consolidated subsidiaries. Following are the significant changes in or
additions to information reported in our 2001 Annual Report on Form 10-K. 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.
RESULTS OF OPERATIONS
Our business consists of two reportable segments, which are Generation and
Energy Trading. The following is a discussion of the major quarter-to-quarter
financial statement variances and follows the financial statement presentation
as it relates to each of our segments.
For the Quarter Ended March 31, 2002 compared to the Quarter Ended March
31, 2001
Operating Revenues
Generation
Revenues from our generation segment increased $64 million or 11% in the
quarter ended March 31, 2002, as compared to the quarter ended March 31, 2001
primarily due to an increase of $65 million in Interchange/Spot Market Sales due
to additional generation and favorable prices. Also, a $25.0 million increase in
BGS revenue for the quarter contributed to the increase. This resulted from
customers returning to PSE&G in 2001 from Third Party Suppliers (TPS) as
wholesale market prices exceeded fixed BGS rates. At March 31, 2002, TPS were
serving less than 0.5% of the customer load traditionally served by PSE&G as
compared to the March 31, 2001 level of 8%. Partially offsetting this increase
was a net $28 million decrease in MTC revenues remitted to us from PSE&G,
relating to two 2% rate reductions in February and August 2001. As of March 31,
2002, as required by the BPU, PSE&G has had rate reductions totaling 9% since
August 1, 1999 and will have an additional 4.9% rate reduction effective August
1, 2002, which will be in effect until July 31, 2003.
Energy Trading
Revenues from our energy trading segment decreased by $157 million or 27%
for the quarter ended March 31, 2002 from the comparable period in 2001, due to
lower energy trading volumes, lower prices as compared to 2001, and emission
credits recorded in the first quarter of 2001. Despite lower trading volumes for
the quarter, we expect to meet our full year trading margin goals.
Operating Expenses
Energy Costs
Energy Costs increased $48 million or 28% for the quarter ended March 31,
2002 from the comparable period in 2001, primarily due to increased
Interchange/Spot Market costs due to the incremental load served under the BGS
contract. This was partially offset by lower fuel costs, including natural gas
and nuclear and lower demand as a result of the warmer winter weather.
Trading Costs
Trading Costs decreased $138 million or 26% for the quarter ended March 31,
2002 from the comparable period in 2001, primarily due to lower trading volumes
and lower prices as compared to 2001.
Operation and Maintenance
Operation and Maintenance expense increased $13 million or 8% for the
quarter ended March 31, 2002.
Depreciation and Amortization
Depreciation and Amortization expense decreased $7 million or 23% for the
quarter ended March 31, 2002 from the comparable period in 2001. The decrease
was primarily due to decreased estimated cost of removal of our generating
stations.
Interest Expense
Interest Expense decreased $36 million or 56% for the quarter ended March
31, 2002 from the comparable period in 2001 primarily due to the repayment of
the $2.786 billion 14.23% promissory note to PSE&G. This loan 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 the $1.8 billion Senior Notes
issued in April 2001, resulting in a total decrease in interest expense of $23
million for this quarter. Also contributing to the decrease was the
capitalization of $21 million of interest on various projects under construction
in 2002.
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 our 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.
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 being 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 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.
Debt Covenants, Cross Default Provisions, Material Adverse 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 $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, would cause a cross-default and the
potential acceleration of payment thereunder.
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. 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 be
limited.
PSEG's credit agreements contain maximum debt to equity ratios as a
financial covenant. Compliance with this financial covenant will depend upon
PSEG's future financial position and the level of earnings and cash flow, as to
which no assurances can be given. As part of PSEG's financial planning forecast,
it performs stress tests on its financial covenant. These tests include a
consideration of the impacts of potential asset impairments and other items.
PSEG's current analyses and projections indicate that PSEG should be able to
meet its financial covenant.
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. These same
contracts provide reciprocal benefits to us. 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. 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.
Over the next several years, we, our Lawrenceburg and Waterford
subsidiaries and PSEG will be required to refinance maturing debt, incur
additional debt and/or 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 affect our financial condition, results of operations and net cash flows.
Regulatory Restrictions
If PSEG were no longer to be exempt under the Public Utility Holding
Company Act of 1935 (PUHCA), PSEG and its subsidiaries, including us, would be
subject to additional regulation by the SEC with respect to financing and
investing activities, including the amount and type of non-utility investments.
We believe that this would not have a material adverse effect on our financial
condition, results of operations and net cash flows.
Short-Term Liquidity
Our short-term financing needs will be met using PSEG's commercial paper
program or lines of credit. As of March 31, 2002, we had a payable to PSEG of
approximately $215 million for short-term funding needs. As of December 31,
2001, our payable was $164 million.
We are constructing through indirect, wholly-owned subsidiaries, two
natural gas-fired combined cycle electric generation plants in Waterford, Ohio
(850 MW) and Lawrenceburg, Indiana (1,150 MW) at an aggregate total cost of $1.2
billion. Total expenditures to date on these projects are approximately $968
million. Our required estimated equity investment in these projects is
approximately $400 million, with the remainder being financed with non-recourse
debt. As of March 31, 2002, approximately $168 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. The agreement may expire if the
projects are refinanced or 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. The Waterford project will not begin commerical
operation as a single-cycle facility in June 2002 as originally scheduled. Both
the Waterford and Lawrenceburg combined-cycle facilities are currently scheduled
to achieve commerical operation in 2003.
CAPITAL REQUIREMENTS
We have substantial commitments as part of our growth strategy 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.
For the quarter ended March 31, 2002, we had net plant additions of $216
million, excluding capitalized interest. The majority of these additions are
related to developing the Lawrenceburg, Indiana and the Waterford, Ohio sites
and adding capacity to the Bergen and Linden stations in New Jersey.
ACCOUNTING MATTERS
For a discussion of SFAS 142, SFAS 143 and SFAS 144, 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) and EITF 99-19, "Reporting
Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), 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.
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.
For additional information regarding Derivative Financial Instruments, See
Note 4 - Financial Instruments Energy Trading and Risk Management - Derivative
Instruments and Hedging Activities of Notes.
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.
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 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. 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 March 31, 2002 was
approximately $22 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.
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.
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 is updated below. See information on the
following proceedings at the pages indicated:
(1) Form 10-K, Pages 14 and 15. See Page 23. Administrative proceedings
before the NJDEP under the FWPCA for certain electric generating
stations.
(2) Form 10-K, Page 17. See Pages 22 and 23. DOE Overcharges, Docket No.
01-592C.
(3) Form 10-K, Pages 16 and 17. See Pages 22 and 23. DOE not taking
possession of spent nuclear fuel, Docket No. 01-551C.
(4) Form 10-K, Pages 16 and 51. See Page 6. 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 is
updated below. References are to the related pages on the Form 10-K as printed
and distributed.
Gas Contract Transfer
Form 10-K, page 9. On August 11, 2000, PSE&G filed a gas merchant
restructuring plan with the BPU. On January 9, 2002, 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. We
will, under a requirements contract, provide gas supply to PSE&G to serve its
Basic Gas Supply Service (BGSS) customers. The transfer took place on May 1,
2002. On May 1, 2002, the Ratepayer Advocate requested rehearing by the BPU of
its decision, but did not seek a stay.
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. After the gas
contract transfer, PSE&G will pay ER&T 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 Regulatory Commission (NRC)
Form 10-K, page 11. A pressurized water reactor nuclear unit (PWR) not
owned by us was recently identified with a degradation of the reactor vessel
head, which forms part of the pressure boundary for the reactor coolant system.
Although analysis of the cause is still in progress, primary water stress
corrosion cracking of the control rod drive mechanism nozzles is suspected. In
March 2002, the NRC issued bulletin 2002-01, requiring that all operators of PWR
units submit information concerning: (i) the integrity of the reactor coolant
pressure boundary, (ii) inspections that have been and will be undertaken to
satisfy applicable regulatory requirements, and (iii) the basis for concluding
that plants satisfy applicable regulatory requirements related to the structural
integrity of the reactor coolant pressure boundary. In April, we provided the
requested information in our response for Salem Nuclear Generation Station
(Salem). The response included an assessment that primary water stress corrosion
cracking of the control rod drive mechanism nozzles at Salem Units 1 and 2 is
unlikely in the near term, and our assurance that both Salem Units 1 and 2 are
in compliance with applicable regulatory requirements. A visual inspection of
the Salem Unit 2 reactor head has been completed during the current refueling
outage, and no evidence of reactor vessel head degradation was found. A similar
inspection was performed at Salem Unit 1 in 2001, which also found no evidence
of degradation. Our Hope Creek nuclear unit and our interests in the Peach
Bottom units 2 and 3 are unaffected as they are Boiling Water Reactor nuclear
units. We cannot predict what other actions the NRC may take on this issue.
Nuclear Fuel Disposal
Form 10-K, page 17. 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 May 8,
2002, the U.S. House of Representatives approved a resolution to override the
veto. The issue now awaits a vote by the U.S. Senate, which is expected in early
July. No assurances can be given regarding the final outcome of this matter.
Water Pollution Control
Form 10-K, page 15. The EPA is conducting a rulemaking under Federal Water
Pollution Control Act (FWPCA) Section 316(b), which requires that cooling water
intake structures reflect the best technology available (BTA) for minimizing
"adverse environmental impact". Phase I of the rule became effective on January
17, 2002. None of the projects that we currently have under construction or in
development is subject to the Phase I rule. EPA published for public comment on
April 9, 2002 proposed draft Phase II rules covering large existing power
plants, and is expected to issue final rules by August 28, 2003. The draft
regulations propose to regulate existing power plants that have a design intake
flow of 50 million gallons per day greater and use at least 25% of the water for
cooling purposes. The draft regulations propose to establish three means of
demonstrating that a facility has BTA at an intake; two of which would be linked
to demonstrating compliance with specific performance criteria and the third
requiring a determination by the permitting authority that a case-by-case
demonstration would be warranted. The proposed uniform performance standards are
applicable to subsets of facilities based on waterbody type and capacity
utilization rate. The content of the final Phase II rules cannot be predicted at
this time, although it is reasonable to expect that the rule will apply to all
of our steam electric and combined cycle units that use surface waters for
cooling purposes. If the Phase II rules require retrofitting of cooling water
intake structures at our existing facilities, the cost of complying with the
rules would be material.
New Matter
Approximately 150,000 tons of fly ash generated by Hudson and Mercer
Generating Stations was taken by the ash marketer we then employed and sold to
the owner and operator of a clay mine in Monroe Township, New Jersey. During the
Fall of 1997 through the Fall of 1998, the owner and operator of the clay mine
used the fly ash as fill material to return the mine site to grade, without
obtaining the necessary approvals from the NJDEP. Upon discovery of this use of
the material, we terminated the services of its ash marketer and initiated
discussions with NJDEP for the appropriate regulatory approvals to allow this
material to remain at the site. NJDEP likely will require a clay cap and other
engineering controls to ensure that the ash is isolated from the environment if
the ash is left in place. Our negotiations with NJDEP and the property owner are
continuing. Our cost of resolving this matter will depend upon the results of
our negotiations with NJDEP and the property owner. Although the precise extent
of liability is not currently estimable, it is not expected to be material.
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
-------------- --------------------------------------------------------
4.7 First Supplemental Indenture Dated as of March 13, 2002
12 Computation of Ratios of Earnings to Fixed Charges
(B) Reports on Form 8-K:
None.
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: May 15, 2002