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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q/A
(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.
------------- ---------------------------------------------- ------------------
001-09120 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 22-2625848
(A New Jersey Corporation)
80 Park Plaza
P.O. Box 1171
Newark, New Jersey 07101-1171
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
As of April 30, 2002, Public Service Enterprise Group Incorporated had
outstanding 206,228,771 shares of its sole class of Common Stock, without par
value.
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EXPLANATORY NOTE - RESTATEMENT
This Form 10-Q is being amended to reflect a change to our Consolidated
Statement of Income for the three months ended March 31, 2002, to reduce
reported amounts of Electric Revenues and Electric Energy Costs by approximately
$80 million. This change relates to an inadvertent bookkeeping error recorded in
the month of March 2002, and reported in our March 31, 2002, Form 10-Q involving
the purchase and sale of energy with the PJM ISO by our generation segment. This
restatement is limited to these line items and time period, and had no effect on
our margins, earnings or cash flows.
For purposes of this Form 10-Q/A, and in accordance with Rule 12b-15 under
the Securities Exchange Act of 1934, as amended, each item of the Form 10-Q for
the quarter ended March 31, 2002 as originally filed on May 15, 2002 that was
affected by the restatement has been amended to the extent affected and restated
in its entirety. NO ATTEMPT HAS BEEN MADE IN THIS FORM 10-Q/A TO MODIFY OR
UPDATE OTHER DISCLOSURES AS PRESENTED IN THE ORIGINAL FORM 10-Q EXCEPT AS
REQUIRED TO REFLECT THE EFFECTS OF THE RESTATEMENT AND THE ADOPTION OF STATEMENT
OF FINANCIAL ACCOUNTING STANDARDS NO. 142, "GOODWILL AND OTHER INTANGIBLE
ASSETS" (SFAS 142). Under this standard, we were required to complete an
impairment analysis of goodwill during 2002. We implemented the impairment
provisions of SFAS 142 during the second quarter of 2002. The financial
statements have also been revised to give retroactive effect to the adoption of
SFAS 142 resulting in a $120 million after-tax charge to earnings recorded as a
cumulative effect of a change in accounting principle, as well as a decrease in
our recorded assets and equity.
Simultaneously with the filing of this amended March 31, 2002 Form 10-Q, we
are filing our June 30, 2002 Form 10-Q which reflects accounting and disclosure
relating to certain asset impairments, discontinued operations and other events
that occurred in the second quarter.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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TABLE OF CONTENTS
PAGE
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PART I. FINANCIAL INFORMATION
-----------------------------
Item 1. Financial Statements 1
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 28
Item 3. Qualitative and Quantitative Disclosures About Market Risk 42
PART II.OTHER INFORMATION
-------------------------
Item 1. Legal Proceedings 45
Item 4. Submission of Matters to Vote of Security Holders 46
Item 5. Other Information 47
Item 6. Exhibits and Reports on Form 8-K 49
Signature 50
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, except for Per Share Data)
(Unaudited)
For the Quarters Ended
March 31,
-----------------------------------------
2002 2001
(As Restated
See Note 11)
------------------- -----------------
OPERATING REVENUES
Electric $ 992 $ 925
Gas Distribution 815 1,082
Trading 430 587
Other 198 225
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Total Operating Revenues 2,435 2,819
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OPERATING EXPENSES
Electric Energy Costs 230 220
Gas Costs 527 787
Trading Costs 398 536
Operation and Maintenance 555 538
Depreciation and Amortization 137 108
Taxes Other Than Income Taxes 47 48
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Total Operating Expenses 1,894 2,237
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OPERATING INCOME 541 582
OTHER (LOSS) INCOME
Foreign Currency Transaction Loss (52) --
Other Income and Deductions 14 13
------------------- -----------------
Total Other (Loss) Income (38) 13
------------------- -----------------
Interest Expense (195) (164)
Preferred Securities Dividend Requirements
and Premium on Redemption (14) (24)
------------------- -----------------
INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 294 407
Income Taxes (114) (153)
------------------- -----------------
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE 180 254
Extraordinary Loss on Early Retirement of Debt (net of tax) -- (2)
Cumulative Effect of a Change in Accounting Principle (net
of tax) (120) 9
------------------- -----------------
NET INCOME $ 60 $ 261
=================== =================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 206,340 208,390
=================== =================
EARNINGS PER SHARE (BASIC AND DILUTED):
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE $ 0.87 $ 1.22
Extraordinary Loss on Early Retirement of Debt (net of tax) -- (0.01)
Cumulative Effect of a Change in Accounting Principle
(net of tax) (0.58) 0.04
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NET INCOME $ 0.29 $ 1.25
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DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54
=================== =================
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
(Unaudited)
March 31, December 31,
2002 2001
-------------------- -------------------
CURRENT ASSETS
Cash and Cash Equivalents $ 175 $ 169
Accounts Receivable:
Customer Accounts Receivable 958 824
Other Accounts Receivable 248 348
Allowance for Doubtful Accounts (43) (43)
Unbilled Electric and Gas Revenues 221 291
Fuel 238 494
Materials and Supplies, net of valuation reserves - 2002, $2; 2001, $11 194 189
Prepayments 57 74
Energy Trading Contracts 324 454
Restricted Cash 13 12
Assets held for Sale 457 422
Notes Receivable 142 26
Other 41 25
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Total Current Assets 3,025 3,285
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PROPERTY, PLANT AND EQUIPMENT
Generation 5,146 4,884
Transmission and Distribution 9,477 9,500
Other 507 502
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Total 15,130 14,886
Accumulated Depreciation and Amortization (4,917) (4,822)
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Net Property, Plant and Equipment 10,213 10,064
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NONCURRENT ASSETS
Regulatory Assets 5,116 5,247
Long-Term Investments, net of accumulated amortization and
Valuation allowances-- 2002, $31; 2001, $30 4,776 4,818
Nuclear Decommissioning Fund 815 817
Other Special Funds 308 222
Goodwill, net of accumulated amortization 478 649
Other 297 322
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Total Noncurrent Assets 11,790 12,075
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TOTAL ASSETS $ 25,028 $ 25,424
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See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
(Unaudited)
March 31, December 31,
2002 2001
------------------- -------------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,385 $ 1,213
Commercial Paper and Loans 1,503 1,338
Accounts Payable 546 790
Energy Trading Contracts 310 602
Accrued Taxes 257 243
Other 529 535
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Total Current Liabilities 4,530 4,721
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NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 3,186 3,205
Nuclear Decommissioning 815 817
OPEB Costs 487 476
Regulatory Liabilities 344 373
Cost of Removal 145 146
Environmental 140 140
Other 405 348
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Total Noncurrent Liabilities 5,522 5,505
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COMMITMENTS AND CONTINGENT LIABILITIES -- --
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CAPITALIZATION
Long-Term Debt 6,288 6,437
Securitization Debt 2,321 2,351
Project Level, Non-Recourse Debt 1,569 1,513
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Total Long-Term Debt 10,178 10,301
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SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption 80 80
Guaranteed Preferred Beneficial Interest in Subordinated 680 680
Debentures
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Total Subsidiaries' Preferred Securities 760 760
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COMMON STOCKHOLDERS' EQUITY
Common Stock, issued: 2002-232,313,099 shares, 2001-231,957,608 shares 3,613 3,599
Treasury Stock, at cost: 2002 and 2001-- 26,118,590 shares (981) (981)
Retained Earnings 1,761 1,809
Accumulated Other Comprehensive Loss (355) (290)
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Total Common Stockholders' Equity 4,038 4,137
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Total Capitalization 14,976 15,198
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TOTAL LIABILITIES AND CAPITALIZATION $ 25,028 $ 25,424
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See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
For the Quarters Ended
March 31,
--------------------------------------
2002 2001
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Net income $ 60 $ 261
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization 137 108
Market Transition Charge (MTC) Overcollections 8 16
Amortization of Nuclear Fuel 24 27
AFDC and IDC (24) (12)
Deferral of Gas Costs - net (86) (80)
Provision for Deferred Income Taxes and ITC-- net 20 (15)
Investment Distributions 3 86
Undistributed Earnings from Affiliates (14) (25)
Net Losses on Investments 5 14
Cumulative Effect of a Change in Accounting Principle 120 --
Change in Derivate Fair Value (10) (1)
Leasing Activities 15 2
Proceeds from Sale of Capital Leases -- 1
Foreign Currency Transaction Loss 52 --
Gain on Withdrawal from Partnership Interests (7) (51)
Proceeds from Withdrawal of Partnership Interests 7 50
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues 36 42
Inventory-Fuel and Materials and Supplies 251 162
Prepayments 17 (5)
Accounts Payable (244) (205)
Accrued Taxes 14 181
Other Current Assets and Liabilities (9) 36
Other 88 (153)
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Net Cash Provided By Operating Activities 463 438
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, excluding IDC and AFDC (373) (356)
Net Change in Long-Term Investments (49) (58)
Other (121) --
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Net Cash Used in Investing Activities (543) (414)
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CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 165 (2,332)
Issuance of Long-Term Debt 73 3,088
Issuance of Common Stock 14 --
Redemption/Purchase of Long-Term Debt (24) (330)
Redemption of Preferred Securities -- (240)
Cash Dividends Paid on Common Stock (111) (112)
Other (31) (2)
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Net Cash Provided By Financing Activities 86 72
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Net Change in Cash and Cash Equivalents 6 96
Cash and Cash Equivalents at Beginning of Period 169 102
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Cash and Cash Equivalents at End of Period $ 175 $ 198
================= ===============
Income Taxes Paid $ 119 $ 8
Interest Paid $ 122 $ 108
See Notes to Consolidated Financial Statements.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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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 "PSEG," "we,"
"us" or "our" herein means Public Service Enterprise Group Incorporated, an
exempt public utility holding company which has four principal direct
wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG
Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services
Corporation (Services).
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 2001 Annual Report on Form 10-K. These Notes update and
supplement matters discussed in our 2001 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
Effective January 1, 2002 we adopted Statement of Financial Accounting
Standards (SFAS) No. 142 "Goodwill and Other Intangible Assets" (SFAS 142), as
required by the standard. Under SFAS 142, goodwill is considered a
nonamortizable asset and is subject to an annual review for impairment and an
interim review when certain events or changes in circumstances occur. The effect
of no longer amortizing goodwill on an annual basis was not material to our
financial position and statement of income upon adoption. Under this standard,
we were required to complete an impairment analysis of goodwill during 2002 and
record any required impairment as of January 1, 2002. We have finalized our
evaluation of the effect of adopting SFAS 142 on the recorded amount of
goodwill.
See Goodwill Impairment Analysis in Note 4. Commitments and Contingencies
for further detail. In future periods, goodwill will be tested for impairment
annually and upon the occurrence of other events or changes in circumstances
that indicate goodwill might be impaired. Any impairment loss will be recorded
as a component of income from continuing operations.
On January 1, 2002 we adopted Statement of Financial Accounting Standard
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS
142, goodwill is considered a nonamortizable asset and is be subject to an
annual review for impairment and an interim review when events or circumstances
occur. The effect of no longer amortizing goodwill was not material to our
financial position and statement of operations. The impact of adopting SFAS 142
is 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. An impairment loss, as of the date of adoption, will be
recognized as the cumulative effect of a change in accounting principle in the
first interim period, if applicable. If certain events or changes in
circumstance indicate that goodwill might be impaired before completion of the
transitional goodwill impairment test, goodwill shall be tested for impairment
and any impairment loss shall be recorded as a component of income from
continuing operations. For additional information relating to potential asset
impairments, see Note 4. Commitments and Contingent Liabilities.
On January 1, 2002 we adopted SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). The impact of adopting SFAS 144 did
not have an effect on our financial position and statement of operations. Under
SFAS 144, long-lived assets to be disposed of are measured at the lower of
carrying amount or fair value less costs 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. A long-lived asset must be tested for impairment whenever events or
changes in circumstances indicate that its carrying amount may be impaired. For
additional information relating to potential asset impairments, see Note 4.
Commitments and Contingent Liabilities.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- Continued
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). Under SFAS 143, the fair value of a
liability for an asset retirement obligation should be recorded in the period in
which it is created with an offsetting amount to an asset. 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. The impact of adopting SFAS 143 is likely to be
material to our financial position and statement of operations.
Note 3. Regulatory Assets and Liabilities
At March 31, 2002 and December 31, 2001, respectively, we had deferred the
following regulatory assets and liabilities on the Consolidated Balance Sheets:
March 31, December 31,
2002 2001
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(Millions of Dollars)
Regulatory Assets
Stranded Costs to be Recovered.............................. $4,059 $4,105
SFAS 109 Income Taxes....................................... 306 302
OPEB Costs.................................................. 207 212
Societal Benefits Charges (SBC)............................. -- 4
Environmental Costs......................................... 87 87
Unamortized Loss on Reacquired Debt and Debt Expense........ 90 92
Underrecovered Gas Costs.................................... 166 120
Unrealized Losses on Gas Contracts.......................... 22 137
Other....................................................... 179 188
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Total Regulatory Assets............................... $5,116 $5,247
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Regulatory Liabilities
Excess Depreciation Reserve................................. $282 $319
Non-Utility Generation Transition Charge (NTC).............. 37 48
SBC......................................................... 18 --
Other....................................................... 7 6
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Total Regulatory Liabilities.......................... $344 $373
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Note 4. Commitments and Contingent Liabilities
Guaranteed Obligations
Power has guaranteed certain energy trading contracts of PSEG Energy
Resources and Trading (ER&T), its subsidiary. Power has entered into guarantees
having a maximum liability of $701 and $506 million as of March 31, 2002 and
December 31, 2001, respectively. The amount of Power's 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, Power had issued letters of credit in the amount of
approximately $122 million. These letters of credit are in support of our
trading business and various contractual obligations.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNADUITED)-- Continued
Energy Holdings or PSEG Global Inc. (Global), a subsidiary of Energy
Holdings, have guaranteed certain obligations of Global's affiliates, including
the successful completion, performance or other obligations related to certain
of their projects, in an aggregate amount of approximately $188 million as of
March 31, 2002. A substantial portion of such guarantees is eliminated upon
successful completion, performance and/or refinancing of construction debt with
non-recourse project debt.
In the normal course of business, PSEG Energy Technologies Inc. (Energy
Technologies), a subsidiary of Energy Holdings, secures construction obligations
with performance bonds issued by insurance companies. In the event that Energy
Technologies' tangible equity falls below $100 million, Energy Holdings would be
required to provide additional support for the performance bonds. Tangible
equity is defined as net equity less goodwill. As of March 31, 2002, Energy
Technologies had tangible equity of $111 million and performance bonds
outstanding of $130 million. The performance bonds are not included in the $188
million of guaranteed obligations of Energy Holdings, discussed above.
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. PSE&G, Power, and predecessor companies own or owned and/or operate or
operated certain facilities situated on surface water bodies, certain of which
are currently the subject of remedial activities. The financial impact of these
regulations on these projects is not currently estimable. We do not anticipate
that the compliance with these regulations will have a material adverse effect
on our financial position, results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with the NJDEP under a program (Remediation
Program) to assess, investigate and, if necessary, remediate environmental
conditions at PSE&G's former manufactured gas plant (MGP) sites. To date, 38
sites have been identified. The Remediation Program is periodically reviewed and
revised by PSE&G based on regulatory requirements, experience with the
Remediation Program and available remediation technologies. The long-term costs
of the Remediation Program cannot be reasonably estimated, but experience to
date indicates that at least $20 million per year could be incurred over a
period of about 30 years since inception of the program in 1988 and that the
overall cost could be material. The costs for this remediation effort are
recovered through the SBC.
At March 31, 2002 and December 31, 2001, our estimated liability for
remediation costs through 2004 aggregated $87 million. Expenditures beyond 2004
cannot be reasonably estimated.
Passaic River Site
The U.S. Environment 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 PSE&G, may be potentially liable for performing
required remedial actions to address potential environmental pollution at the
Passaic River "facility." PSE&G, PSEG Fossil LLC (Fossil), a subsidiary of
Power, and certain of their predecessors operated industrial facilities at
properties within the Passaic River "facility," comprised of four former MGPs,
one operating electric generating station and one former generating station.
PSE&G's costs to clean up former MGPs are recoverable from its utility customers
under the SBC. PSE&G has contracted to sell the former generating site to a
third party that would be responsible for remediation costs. Regulatory approval
by the state is pending. We cannot predict what action, if any, the EPA or any
third party may take against PSE&G and Power with respect to these matters, or
in such event, what costs PSE&G and Power 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), 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/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. The unit is
expected to begin operating in June 2002.
Power
New Generation and Development
Power is in the process of developing the Bethlehem Energy Center, a 750 MW
combined-cycle power plant that will replace the 400 MW Albany (NY) 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.
Power is 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. Power is also constructing a 1,186 MW combined cycle
generation plant in Linden, New Jersey. Costs are estimated at approximately
$600 million with expenditures to date of approximately $282 million. Completion
is expected in May 2003 at which time 445 MW of generating capacity will be
retired.
Power is also 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 commercial 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.
Power has commitments to purchase equipment and services, to meet its
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.
Energy Holdings
California Investments
In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between
Global and Harbinger GWF LLC, entered into a 10-year power purchase agreement
(PPA) with the California Department of Water Resources (CDWR) to provide 340 MW
of electric capacity to California from three new natural gas-fired peaking
plants, Hanford, Henrietta and Tracy Peaking Plants. Total project cost is
estimated at approximately $335 million. The Hanford Peaking Plant, a 90 MW
facility, was completed and began operation in August 2001. The Henrietta
Peaking Plant is currently under construction, with completion expected in July
2002, and the Tracy Peaking Plant, a 160 MW facility, is in the permitting
process. Permitting for the Tracy Peaking project has been delayed
significantly. The California Energy Commission is not expected to issue a
permit allowing the start of construction before the end of June 2002. This date
does not allow sufficient time to complete construction before the final
Commercial Operations Date deadline of October 31, 2002 under the contract. On
February 28, 2002, GWF Energy asserted a force majeure claim under the
provisions of its contract for an appropriate extension of the deadline.
On April 24, 2002, GWF Energy received notice from the CDWR rejecting GWF
Energy's force majeure claim. Energy Holdings and Global are evaluating the
appropriate course of action to protect its rights under the CDWR PPA. Global's
permanent equity investment in these plants, including contingencies, is not
expected to exceed $100 million after completion of project financing, which is
currently expected to occur in late 2002 or in 2003. For a description of the
loans to GWF Energy, see Note 10. Related-Party Transactions.
On February 25, 2002 the Public Utilities Commission of the State of
California and the State of California Electricity Oversight Board filed
complaints with the Federal Energy Regulatory Commission (FERC) under Section
206 of the Federal Power Act against sellers, which pursuant to long-term FERC
authorized contracts, provide power to the CDWR. GWF Energy is a named
respondent in these proceedings. The complaints, which address over 40
transactions embodied in over 30 contracts with over 20 sellers, allege that,
collectively, the specified long-term wholesale power contracts are priced at
unjust and unreasonable levels and request FERC to abrogate the contracts to
enable the State to obtain replacement contracts as necessary or in the
alternative, to reform the contracts to provide for just and reasonable pricing,
reduce the length of the contracts and strike from the contracts the specific
non-price conditions found to be unjust and unreasonable. On April 25, 2002,
FERC consolidated the two dockets and set the ten year PPA contract of GWF
Energy and certain other respondents, including the ten year PPA contact for
hearing "to determine whether the dysfunctional California spot markets
adversely affected the long-term bilateral markets and, if so, whether
modification of any individual contract at issue is warranted." FERC determined
that the GWF contract, among others, was entitled to presumption of validity,
requiring the CPUC to prove it was "against the public interest." FERC also
strongly encouraged the parties to negotiate settlements and directed a
settlement judge to be appointed to oversee such negotiations. GWF Energy has
indicated to representatives of the State of California its willingness to enter
into negotiations in an attempt to resolve differences between the parties. GWF
Energy plans to attend FERC settlement conference discussions during the week of
May 13, 2002. We cannot predict the outcome of this matter or its impact on
future earnings or cash flows.
Dispute of Power Contracts-Tanir Bavi
Global owns a 74% interest in Tanir Bavi Power Company Private Ltd. (Tanir
Bavi), which owns and operates a 220 MW barge mounted, combined-cycle generating
facility. The plant commenced combined-cycle commercial operation in November
2001. Power from the plant is being sold under a seven-year fixed price PPA with
the Karnataka Power Transmission Company Limited (KPTCL), a State affiliated
entity, formerly known as Karnataka Electricity Board.
Tanir Bavi has been in dispute with KPTCL regarding the terms of payment
specified in the PPA relating to the fixed portion of the tariff, which is
approximately US $.04 per kilowatt-hour. The amount of the dispute is
approximately half of this fixed amount. During the first quarter of 2002, KPTCL
referred the dispute to the government of Karnataka, which directed KPTCL to
accept Tanir Bavi's position. Prior to KPTCL's acceptance of such direction,
however, the Karnataka Electricity Regulatory Commission (KERC) exercised
jurisdiction over the matter and requested that KPTCL not comply with the
requests of the government of Karnataka until KERC had reviewed the matter. A
hearing was held in May 2002, at which KERC determined that the disputed amounts
could not be paid until the parties complied with the dispute resolution process
called for in the PPA. KERC did not rule on the merits regarding the arrearages
but directed the parties on the process of the dispute. The dispute resolution
process could take several months.
Beginning in January 2002, approximately 50% of the disputed amounts were
subject to a reserve established by Global. Beginning in the second quarter of
2002, Global began to reserve 100% of the disputed amount. As of March 31, 2002,
the amount in dispute due from KPTCL was $22 million, net of reserves, of which
our share was $16 million. We cannot predict the outcome due to the uncertainty
of the dispute resolution process. If there was an unfavorable outcome in this
matter, we would be required to recognize a loss of up to our share of the
entire unrecovered and unreserved amount in dispute. In addition, an unfavorable
outcome would adversely impact this project's future earnings and cash flows and
could lead to an impairment of the existing $27 million of goodwill associated
with this project.
We completed our impairment testing of all recorded goodwill in accordance
with guidelines set forth in SFAS 142 including the goodwill associated with
Global's acquisition of Tanir Bavi. For additional information see Note 2.
Accounting Matters and Goodwill Impairment Analysis, below.
Potential Asset Impairments
As discussed below, we are currently evaluating the recoverability of our
remaining $529 million of capital at risk in Argentina as of March 31, 2002. In
addition, as part of our implementation of SFAS 142, we have evaluated the
goodwill of Rio Grande Energia (RGE), Empresa Distribuidora de Electricidad de
Entre Rios S.A. (EDEERSA), Energy Technologies and Tanir Bavi. Under a
worst-case scenario, if the results of these evaluations indicate a complete
impairment, we would record an approximate $735 million (pre-tax and
pre-minority interest), $473 million (after-tax and after minority interest)
charge to earnings in 2002. This would amount to approximately $2.29 per share.
The related, worst-case, charge to equity would be approximately $410 million
due to the $63 million charge to OCI recorded in the first quarter. We expect to
complete our evaluation of these asset impairments during the second quarter of
2002.
Argentine Economic Crisis
As of March 31, 2002, Energy Holdings' aggregate remaining investment
exposure in Argentina was approximately $529 million, including $109 million of
investment exposure for EDEERSA, and $420 million of investment exposure for
assets under contract for sale. This investment exposure was reduced in the
first quarter by a $47 million (pre-tax) charge related to the change in the
functional currency at EDEERSA and by a $63 million (pre-tax) charge related to
the adoption of SFAS 142, see Functional Currency - Argentine Operations and
Goodwill Impairment Analysis, respectively, discussed below. Investments include
a 90% owned distribution company, EDEERSA; and Energy Holdings' minority
interests in three distribution companies, Empresa Distribuidora de Energia
Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES), and Empresa
Distribuidora La Plata S.A. (EDELAP) and two generating companies, Central
Termica San Nicolas power plant (CTSN), and Parana which are under contract for
sale to certain subsidiaries of the AES Corporation (AES).
The Argentine economy has been in a state of recession for approximately
five years. Continued deficit spending in the 23 Argentine provinces, coupled
with low growth and high unemployment, has precipitated an economic, political
and social crisis. Toward the end of 2001, a liquidity crisis ensued causing the
Argentine government to default on $141 billion of national debt. The economic
crisis was fueled by political instability and social unrest as the new year
began. The present Argentine federal government is in the process of developing
an economic plan to avert a return to the economic instability and
hyperinflationary economy of the 1980s. In early January 2002, the decade old
convertibility formula that maintained the Argentine Peso at a 1:1 exchange rate
with the US Dollar, was abandoned. In early February 2002, the Argentine Peso
was no longer pegged to the US Dollar. In the first day of the free floating
formula, the currency weakened to a rate of approximately 2 Pesos per 1 US
Dollar. At the end of March 2002, the currency weakened further to a rate of
approximately 2.90 Pesos per 1 US Dollar. As of April 30, 2002, the currency
weakened further to a rate of approximately 2.96 Pesos per 1 US Dollar.
In the Province of Entre Rios, where EDEERSA is located, the electricity
law provided for a pass-through of devaluation to the end user customer.
Customers' bills were to be first computed in US Dollars and then converted into
Pesos for billing. This mechanism assured that devaluation would not impact the
level of US Dollar revenues an electric distribution company received. However,
in January 2002, the Argentine federal government implemented a new law that
prohibits any foreign price or currency indexation and any US Dollar or other
foreign currency adjustment clauses relating to public service tariffs, thus
prohibiting the pass through of the costs of devaluation to customers. The
provincial governments have been requested to adopt this provision. The
provincial government of the Province of Entre Rios has recently adopted this
provision as well as a law that requires public service companies within the
Province, including EDEERSA, to accept payment for all billed services in a
provincial promissory note, the "Federal". The terms of the "Federal" require
principal payment at maturity in an equal amount of Argentine Pesos. However,
the "Federal" is not freely convertible in the financial markets into Argentine
Pesos or US Dollars. Approximately 75% of cash receipts generated from EDEERSA's
operations are currently settled in "Federals." There are ongoing negotiations
to remedy this situation, although no assurances can be given. While we continue
to operate EDEERSA, there has been an adverse impact to its financial condition
and cash flows due to its inability to pass through the costs of devaluation to
customers and its receipt of an illiquid provincial currency. Energy Holdings is
pursuing remedies on several fronts, including holding discussions with the
Province and United States government officials, both individually and
collectively with a coalition of international investors, and Energy Holdings is
pursuing legal recourse under the Bilateral Investment Treaty between the United
States and Argentina. Energy Holdings has been notified by lenders of the
occurrence of events of default in certain of its subsidiaries non-recourse
credit agreements related to Parana, EDEN, EDES, and EDELAP credit facilities.
If Argentine conditions do not improve, Global's other Argentine properties may
also default on non-recourse obligations in connection with other financings.
Currently, we cannot predict the outcome of our ongoing negotiations with the
lenders.
The situation in Argentina is quite uncertain and highly volatile. While it
is likely that some or all of our remaining investment in Argentina is impaired,
the continued lack of stability in the political and economic environment causes
significant variability in the quantification of value. However, the continued
passage of time without a credible solution and continuing instability
diminishes the prospect of recovery. Other potential impacts of the Argentine
economic, political and social crisis, include increased collection risk,
further devaluation of the Peso, potential nationalization of assets,
foreclosure of our assets by lenders and an inability to complete the pending
sale of certain Argentine assets to certain subsidiaries of AES. Global
anticipates that evolving economic and political events, ongoing discussions
with regulators about tariff levels and discussions with lenders will occur that
will enable a determination of value in the second quarter of 2002.
Functional Currency - Argentine Operations
As of December 31, 2001, the functional currency of EDEERSA was the US
Dollar, as all revenues, most expenses and all financings were denominated in US
Dollars or were linked to the US Dollar. As a US Dollar reporting entity,
EDEERSA's monetary accounts denominated in Pesos, such as short-term receivables
or payables, were re-measured into the US Dollar with a minimal impact to
earnings. At December 31, 2001, Energy Holdings' 90% share of EDEERSA's US
Dollar denominated debt was approximately $76 million. This debt is non-recourse
to us and Energy Holdings. Due to the recent events described above, we changed
the functional currency of EDEERSA's operations to the Argentine Peso, effective
March 1, 2002. As a result, all monetary accounts denominated in US Dollars were
re-measured to the Argentine Peso effective March 1, 2002, including the US
Dollar denominated debt using the applicable exchange rate of 2.90 Pesos per 1
US Dollar. This resulted in a pre-tax loss of approximately $47 million after
deductions for minority interest for the quarter ended March 31, 2002. In
addition to this impact on our Consolidated Statements of Income, the recorded
amount of Energy Holdings' net investment in EDEERSA decreased by approximately
$100 million due to the translation adjustment as of March 31, 2002.
Assets Held for Sale-Certain Argentine Projects
On August 24, 2001, Global entered into a Stock Purchase Agreement to sell
its minority interests in EDEN, EDES, EDELAP, CTSN and Parana, to certain
subsidiaries of AES. The transaction is subject to regulatory approval and
consent of lenders.
On February 6, 2002, AES notified Global that it was terminating the Stock
Purchase Agreement. In the Notice of Termination, AES alleged that a Political
Risk Event, within the meaning of the Stock Purchase Agreement, had occurred, by
virtue of certain decrees of the Government of Argentina, thereby giving AES the
right to terminate the Stock Purchase Agreement. Global disagrees that a
Political Risk Event as defined in the Stock Purchase Agreement, which is
limited to expropriation of assets, has occurred and has so notified AES. In
April 2002, Global filed a lawsuit in New York State Supreme Court for New York
County against AES to enforce its rights under the Stock Purchase Agreement,
which it will vigorously pursue. We cannot predict the ultimate outcome of this
matter.
As of March 31, 2002, we had approximately $19 million of interest and
other receivables due from the AES Corporation as provided for in the
transaction documents.
In the first quarter of 2002, the Administrative Agent for the non-recourse
project financing notified Global that Parana was in default and a $28 million
equity commitment was accelerated by two weeks. Global made such payment in
March 2002 and it is included in the $529 million of investment exposure in
Argentina.
Goodwill Impairment Analysis
We have finalized our evaluation of the effect of adopting SFAS 142 on the
recorded amount of goodwill. The total amount of goodwill impairments is $120
million, net of tax of $66 million, and is comprised of $36 million (after-tax)
at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy
Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on
these companies, other than RGE, is fully impaired. As noted above, this has
been recorded as a cumulative effect of a change in accounting principle as of
January 1, 2002.
As of March 31, 2002 and December 31, 2001, our unamortized goodwill and
pro-rata share of goodwill in equity method investees was as follows:
As of
March 31, 2002 December 31, 2001
-------------- -----------------
Global (Millions of Dollars)
SAESA................................................... $ 315 $ 315
EDEERSA(1).............................................. -- 63
Electroandes (2)........................................ 136 164
Tanir Bavi (3).......................................... -- 27
ELCHO................................................... 6 6
-------------- -----------------
Total Global...................................... 457 575
Energy Technologies (3).................................... -- 53
Power - Generation......................................... 21 21
-------------- -----------------
Total Consolidated Goodwill.................. 478 649
-------------- -----------------
Global
RGE (4)................................................. 92 142
Chilquinta (5).......................................... 174 174
Luz del Sur............................................. 39 34
Kalaeloa................................................ 25 25
-------------- -----------------
Pro-Rata Share of Equity Investment Goodwill.......... 330 375
-------------- -----------------
Total Goodwill.................................... $ 808 $1,024
============== =================
(1) The decrease at EDEERSA relates to an impairment of $56 million and $7
million of purchase price adjustments made subsequent to December 31, 2001.
(2) The changes at Electroandes and Luz del Sur relate to purchase price
adjustments made subsequent to December 31, 2001.
Note 5. Financial Instruments, Energy Trading and Risk Management
Our operations are exposed to market risks from changes in commodity
prices, foreign currency exchange rates, interest rates and equity prices 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 nor
are 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
-------------- ---------------
Millions of Dollars
Realized Gains....................... $ 1.1 $47.1
Unrealized Gains..................... 30.3 3.6
-------------- ---------------
Gross Margin..................... $31.4 $50.7
============== ===============
Net Margin*...................... $29.6 $48.8
============== ===============
* Net Margin equals Gross Margin less broker fees and other trading related
expenses of $1.8 million and $1.9 million, for the quarters March 31, 2002 and
March 31, 2001, respectively.
Generation
For our generation asset based 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
-------------- ---------------
Millions of Dollars
Realized (Losses)................ $(12.0) $--
Unrealized Gains................. 7.5 0.2
-------------- ---------------
Gross Margin................. $(4.5) $0.2
============== ===============
As of March 31, 2002, the fair value of our energy contracts in trading and
generation segments was $49.8 million, described below, more than 90% of which
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 Financial 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. Power 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, Power has 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, Power entered into forward purchase contracts,
futures, options and swaps. Power has forecasted the energy delivery from our
generating stations based on the forward price curve movement of energy. As a
result, Power entered into swaps, options and futures transactions to hedge the
price of gas to meet our gas purchases requirements for generation. These
transactions qualify for hedge accounting treatment under SFAS 133. As of March
31, 2002, the fair value of these hedges was $11.1 million with offsetting
charges to Other Comprehensive Income (OCI) of $6.5 million (after-tax). These
hedges will mature in 2003.
As of March 31, 2002, PSE&G had entered into 268 MMBTU of gas futures,
options and swaps to hedge forecasted requirements. Also as of December 31,
2001, PSE&G had entered into 330 MMBTU of gas futures, options and swaps to
hedge forecasted requirements. As of March 31, 2002 and December 31, 2001, the
fair value of those instruments was $(22.0) and $(137.0) million, respectively,
with a maximum term of approximately one year. PSE&G utilizes derivatives to
hedge its gas purchasing activities which, when realized, are recoverable in
rates through the Levelized Gas Adjustment Clause (LGAC). Accordingly, these
commodity contracts are recognized at fair value as derivative assets or
liabilities on the balance sheet and the offset to the change in fair value of
these derivatives is recorded as a regulatory asset or liability.
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 estimated VAR across our commodity business
using a model with historical volatilities and correlations.
Our Board of Directors has established a VAR Threshold of $75 million and
the Risk Management Committee (RMC) has established an internal VAR threshold of
$50 million for Power. If the $50 million threshold was 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 $18
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.
Interest Rates
We, PSE&G, Power and Energy Holdings 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,
interest rate swaps and interest rate lock agreements. As of March 31, 2002, a
hypothetical 10% change in market interest rates would result in a $3 million,
$5 million and $1 million change in annual interest costs related to short-term
and floating rate debt at PSEG, PSE&G and Energy Holdings, respectively. The
following table shows details of the interest rate swaps at PSEG, PSE&G, Power
and Energy Holdings and their associated values that are still open at March 31,
2002:
-------------------------------------- -------- ---------- ---------- ------------ ---------- -------------- ----------
Accumulated
Total Fair Other
Project Notional Pay Receive Market Comprehensive Maturity
Underlying Securities Percent Amount Rate Rate Value Income Date
(A) (B)
-------------------------------------- ------- ---------- ---------- ------------ ---------- -------------- ----------
(Millions of dollars, where applicable)
PSEG:
Enterprise Capital Trust II 100% $150.0 5.98% 3-month $(2.6) $1.5 2008
Securities LIBOR
PSE&G:
Transition Funding Bonds (Class 100% $497.0 6.29% 3-month (10.6) -- 2011
A-4)
LIBOR
Power:
Construction Loan - Waterford 100% $177.5 4.16% 3-month 3.6 (2.1) 2005
LIBOR
Energy Holdings:
Construction Loan - Tunisia 60% $56.8 6.96% 6-month (3.6) 1.4 2009
(US$) LIBOR
Construction Loan - Tunisia 60% $62.9 5.19% 6-month (0.7) 0.3 2009
(EURO) EURIBOR*
Construction Loan - Poland 55% $108.2 8.40% 6-month (28.0) 9.5 2010
(US$) LIBOR
Construction Loan - Poland 55% $47.4 13.23% 6-month (22.2) 7.4 2010
(PLN) WIBOR**
Construction Loan - Oman 81% $70.3 6.27% 6-month (1.2) 1.0 2018
LIBOR
Construction Loan - Kalaeloa 50% $55.4 6.60% 3-month (1.4) 0.9 2007
LIBOR
Construction Loan - Guadalupe 50% $125.1 6.57% 3-month (3.3) 2.1 2004
LIBOR
Construction Loan - Odessa 50% $136.6 7.39% 3-month (5.0) 3.3 2004
LIBOR
---------- ---------- ---------
Total Energy Holdings $662.7 $(65.4) $25.9
---------- ---------- ---------
Total PSEG $1,487.2 $(75.0) $25.3
========== ========== =========
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
(A) Represents 100% of Derivative Instrument.
(B) Net of Tax and Minority Interest.
We expect to reclass approximately $24.5 million of open losses on interest
rate swaps from OCI to earnings during the next twelve months. As of March 31,
2002, there was a $25.3 million balance remaining in the Accumulated Other
Comprehensive Loss account, as indicated in the table above.
Equity Securities
PSEG Resources Inc. (Resources), a wholly- owned subsidiary of Energy
Holdings has investments in equity securities and limited partnerships.
Resources carries its investments in equity securities at their approximate fair
value as of the reporting date. Consequently, the carrying value of these
investments is affected by changes in the fair value of the underlying
securities. Fair value is determined by adjusting the market value of the
securities for liquidity and market volatility factors, where appropriate. The
aggregate fair values of such investments, which had quoted market prices at
March 31, 2002 and December 31, 2001 were $28 million and $34 million,
respectively. The potential change in fair value resulting from a hypothetical
10% change in quoted market prices of these investments amounted to $2 million
as of March 31, 2002.
Foreign Currencies
We conduct our business on a multinational basis in a wide variety of
foreign currencies. Our objective for foreign currency risk management policy is
to preserve the economic value of cash flows in currencies other than the US
Dollar. Our policy is to hedge significant probable future cash flows identified
as subject to significant foreign currency variability. In addition, we
typically hedge a portion of our exposure resulting from identified anticipated
cash flows, providing the flexibility to deal with the variability of
longer-term forecasts as well as changing market conditions, in which the cost
of hedging may be excessive relative to the level of risk involved. Our foreign
currency hedging activities to date include hedges of US Dollar debt
arrangements in operating companies that conduct business in currencies other
than the US Dollar.
As of March 31, 2002, Global and Resources had international assets of
approximately $3.4 billion and $1.4 billion, respectively.
Resources' international investments are primarily leveraged leases of
assets located in Austria, Australia, Belgium, China, Germany, the Netherlands,
United Kingdom, and New Zealand with associated revenues denominated in U.S.
Dollars and therefore, not subject to foreign currency risk.
Global's international investments are primarily in projects that presently
or upon completion are expected to generate or distribute electricity in
Argentina, Brazil, Chile, China, India, Italy, Oman, Peru, Poland, Taiwan,
Tunisia and Venezuela. Investing in foreign countries involves certain
additional risks. Economic conditions that result in higher comparative rates of
inflation in foreign countries are likely to result in declining values in such
countries' currencies. As currencies fluctuate against the $US, there is a
corresponding change in Global's investment value in terms of the $US. Such
change is reflected as an increase or decrease in the investment value and OCI,
a separate component of Stockholder's Equity. As of March 31, 2002, net foreign
currency devaluations have reduced the reported amount of our total
Stockholder's Equity by $320 million, of which $159 million, $84 million and $63
million were caused by the devaluation of the Brazilian Real, Chilean Peso and
Argentine Peso, respectively.
Global holds a 60% ownership interest in Carthage Power Company (CPC), a
Tunisian generation facility under construction. The Power Purchase Agreement
(PPA), signed in 1999, contains an embedded derivative that indexes a portion of
the fixed Tunisian Dinar payments to US Dollar exchange rates. The indexation
portion of the PPA is considered an embedded derivative and has been recognized
and valued separately as a derivative instrument. As the Dinar
depreciates/appreciates in relation to the US Dollar, the derivative
increases/decreases in value equal to the discounted present value of additional
units of foreign currency (measured in US Dollars) over the life of the PPA.
This increased/decreased value is reported on the balance sheet as an
asset/liability. To the extent that such indexation is provided to hedge foreign
currency debt exposure, the offsetting amount is recorded in OCI. Amounts will
be reclassified from OCI to Earnings over the life of the debt beginning on the
date of commercial operation of the project, expected to occur in the second
quarter of 2002. To the extent such indexation is provided to hedge an equity
return in US Dollars, the offsetting amount is recorded in Earnings. As of March
31, 2002, we had a derivative asset of $40 million recorded on the balance sheet
related to the indexation of the PPA. During the first quarter of 2002, a gain
of $4 million, net of tax and minority interests, was recorded to earnings as a
result of a net increase in the value of the derivative.
Global holds a 32% ownership interest in a Brazilian distribution company,
RGE, whose debt is denominated in US Dollars. As of March 31, 2002, Global's
pro-rata share of such debt was approximately $60 million. In order to hedge the
risk of fluctuations in the exchange rate between the two currencies associated
with the debt principal payments due in 2002, RGE entered into three forward
exchange contracts to purchase US Dollars for Brazilian Reais in December 2001.
Global's share of the notional value of these contracts, which expire in the
same months as the respective principal payments are due, is approximately $12
million. As of March 31, 2002, Global's share of the derivative liability
associated with these contracts was $2 million and the change in fair value for
the three months ended March 31, 2002 was negligible to our Consolidated
Statement of Income. Additionally, in order to hedge the risk of fluctuations in
the exchange rate between the two currencies associated with the principal
payments due in 2003 through 2005, RGE entered into nine cross currency interest
rate swaps in January 2002. The instruments convert the fixed US Dollar
principal payments to Brazilian Real-denominated obligations with a variable
CDI-based (the Brazilian inter-bank offered rate) interest rate. As a result,
RGE has hedged its foreign currency exposure but is still at risk for
variability in the Brazilian CDI interest rate during the terms of the
instruments. Global's share of the notional values of these instruments is
approximately $49 million. The fair market value of the instruments as of March
31, 2002, and the change in the fair market values of these instruments for the
three months ended March 31, 2002 were both approximately $1 million. The
fluctuations in the fair value of the interest rate components of these cross
currency swaps were recorded directly to the Consolidated Statements of Income.
Through its 50% joint venture, Meiya Power Company, Global holds a 17.5%
ownership interest in a Taiwanese generation project under construction where
the construction contractor's fees, payable in installments through July 2003,
are payable in Euros. To manage the risk of foreign exchange rate fluctuations
associated with these payments, the project entered into a series of forward
exchange contracts to purchase Euros in exchange for Taiwanese Dollars. As of
March 31, 2002, Global's share of the fair value and aggregate notional value of
these forward exchange contracts was an asset of less than $1 million and $16
million, respectively. These forward exchange contracts were designated as
hedges for accounting purposes and were recorded to OCI, resulting in a change
to OCI of less than $1 million, Global's share after-tax for the quarter ended
March 31, 2002.
During 2001, Global purchased approximately 100% of a Chilean distribution
company. In order to hedge final Chilean Peso denominated payments required to
be made on the acquisition, Global entered into a forward exchange contract to
purchase Chilean Pesos for US Dollars. Upon settlement of the transaction,
Global recognized an after-tax loss of $1 million. Furthermore, as a requirement
to obtain certain debt financing necessary to fund the acquisition, and in order
to hedge against fluctuations in the US Dollar to Chilean Peso foreign exchange
rates, Global entered into two forward contracts with notional values of $75
million each to exchange Chilean Pesos for US Dollars. These transactions expire
in October 2002 and are considered hedges for accounting purposes. As of March
31, 2002, the derivative liability value of $15 million has been recorded to
OCI, net of taxes.
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 have established credit policies 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.
As a result of the BGS auction, Power has 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. 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 6. Income Taxes
Our effective income tax rate is as follows:
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 .................................................... (2.1)% (3.3)%
------- ------
Effective Income Tax Rate ................................. 38.8% 37.6%
======= ======
Note 7. Financial Information by Business Segments
Information related to the segments of our business is detailed below:
Generation Energy Global Energy Other Consolidated
(A) Trading PSE&G Resources (B) Technologies (C) Total
------------ ---------- --------- ------------ ---------- --------------- ------- -------------
(Millions of Dollars)
For the For the Quarter Ended
March 31, 2002:
------------------------------------
Total Operating Revenues............ $545 $430 $1,659 $53 $137 $101 $(490) $2,435
Operating Income.................... $198 $30 $210 $49 $63 $(5) $(4) $541
Income Before a Cumulative Effect
of a Change in Accounting Principle $102 $18 $67 $14 $(10) $(3) $(8) $180
Cumulative Effect of a Change
in Accounting Principle............ -- -- -- -- $(88) $(32) -- $(120)
Segment Earnings (Loss)............. $102 $18 $67 $14 $(98) $(35) $(8) $60
Segment Earnings (Loss) Excluding
Argentina Charge and Cumulative Effect
of a Change in Accounting Principle $102 $18 $67 $14 $21 $(35) $(8) $211
As of March 31, 2002:
------------------------------------
Total Assets........................ $4,888 $557 $12,689 $3,091 $3,989 $233 $(419) $25,028
For the Quarter Ended
March 31, 2001:
-------------------------------------
Total Operating Revenues............ $561 $587 $1,952 $33 $89 $102 $(505) $2,819
Operating Income.................... $187 $49 $247 $29 $78 $5 $(13) 582
Income Before Extraordinary Item
and Cumulative Effect of a Change
in Accounting Principle............. $72 $49 $109 $3 $48 $(3) $(24) $254
Extraordinary Loss on Early
Retirement of Debt.................. -- -- -- -- $(2) -- -- $(2)
Cumulative Effect of a Change in
Accounting Principle................ -- -- -- -- $9 -- -- $9
Segment Earnings (Loss)............. $73 $29 $109 $3 $55 $(3) $(5) $261
As of December 31, 2001:
-------------------------------------
Total Assets........................ $4,707 $790 $12,936 $3,026 $4,074 $290 $(399) $25,424
Includes approximately $460 million and $463 million charges for the
quarters ended March 31, 2002 and 2001, respectively, to PSE&G related to the
BGS Contract which commenced in August 2000, following the generation-related
asset transfer to Power. Such amounts are eliminated in consolidation.
(A) For a discussion of the charge relating to Argentina, see Note 4.
Commitments and Contingent Liabilities.
(B) Our other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation), Enterprise Group
Development Company (EGDC), and intercompany eliminations, primarily
relating to intercompany transactions between Power and PSE&G. The net
losses primarily relate to financing and certain administrative and general
costs at the parent corporations.
Geographic information for us is disclosed below. The foreign assets and
operations noted below were made solely through Energy Holdings.
Revenues (1) Identifiable Assets
------------------------ -----------------------------------
Quarter Ended March 31, March 31, December 31,
------------------------ -------------- -----------------
2002 2001 2002 2001
---------- ---------- -------------- -----------------
(Millions of Dollars) (Millions of Dollars)
United States......................... $2,280 $2,768 $20,273 $20,660
Foreign Countries (2)................. 155 51 4,755 4,764
---------- ---------- -------------- -----------------
Total........................... $2,435 $2,819 $25,028 $25,424
---------- ---------- -------------- -----------------
Assets in foreign countries include:
Netherlands..................................................... $921 $911
Chile........................................................... 917 880
Argentina....................................................... 580 737
Peru............................................................ 547 520
India........................................................... 288 288
Brazil.......................................................... 252 282
Tunisia......................................................... 268 245
Other........................................................... 982 901
-------------- -----------------
Total..................................................... $4,755 $4,764
============== =================
(1) Revenues are attributed to countries based on the locations of the
investments. Global's revenue includes its share of the net income from
joint ventures recorded under the equity method of accounting.
(2) Total assets are net of foreign currency translation adjustment of $(393)
million (pre-tax and minority interest) as of March 31, 2002 and $(283)
million (pre-tax and minority interest) as of December 31, 2001.
The table below reflects our investment exposure in Latin American
countries:
Investment Exposure
----------------------
March 31, December 31,
2002 2002
--------- ------------
(Millions of Dollars)
Argentina ................................................ $529 $632
Brazil ................................................... 426 467
Chile .................................................... 528 542
Peru ..................................................... 425 387
Venezuela ................................................ 52 53
The investment exposure consists of invested equity plus equity commitment
guarantees. The investments in these Latin American countries are Global's.
Note 8. Comprehensive Income
Comprehensive Income, Net of Tax:
Quarter Ended
March 31,
--------------
2002 2001
----- -----
(Millions of Dollars)
Net income ............................................................. $ 60 $ 261
Foreign currency translation (A) ....................................... (62) (2)
Change in Fair Value of Derivative Instruments (B) ..................... (9) (5)
Cumulative effect of a change in accounting principle
(net of tax of $8) ................................................ -- (15)
Reclassification adjustments for net amounts included in Net
Income, net of tax $6 and minority interest $3 .................... 8 --
Current Period Change in the Fair Value of Financial Instruments ....... (1) --
Pension Adjustments, net of tax ........................................ (1) --
----- -----
Comprehensive Income ................................................... $ (5) $ 239
===== =====
(A) Net of tax of $38 million and $0.2 million for the quarters March 31,
2002 and 2001, respectively.
(B) Net of tax of $(4) million and $2 million for the quarters March 31,
2002 and 2001, respectively.
Note 9. Property, Plant and Equipment
Information related to Property, Plant and Equipment of PSEG and its
subsidiaries is detailed below:
March 31, December 31,
2001 2002
------- -------
(Millions of Dollars)
Property, Plant and Equipment:
Generation:
Fossil Production (A) ....................................................... $ 2,225 $ 2,233
Nuclear Production .......................................................... 181 154
Nuclear Fuel in Service ..................................................... 561 486
Construction Work in Progress (A) ........................................... 2,172 2,004
Other ....................................................................... 7 7
------- -------
Total Generation ....................................................... 5,146 4,884
------- -------
Transmission and Distribution:
Electric Transmission (A) ................................................... 1,638 1,685
Electric Distribution ....................................................... 4,291 4,254
Gas Transmission ............................................................ 75 74
Gas Distribution ............................................................ 3,146 3,121
Construction Work in Progress (A) ........................................... 13 54
Plant Held for Future Use ................................................... 20 20
Other ....................................................................... 294 292
------- -------
Total Transmission and Distribution .................................... 9,477 9,500
------- -------
Other .......................................................................... 507 502
------- -------
Total ................................................................. $15,130 $14,886
======= =======
(A) These items include the following amounts which relate to our Global
segment:
March 31, December 31,
2002 2001
--------- -----------
(Millions of Dollars)
Generation: .........................................
Fossil Production .............................. $ 315 $ 335
Construction Work in Progress .................. 366 317
------ ------
Total Generation .......................... $ 681 $ 652
------ ------
Transmission and Distribution:
Electric Transmission .......................... $ 417 $ 484
Construction Work in Progress .................. 3 28
------ ------
Total Transmission and Distribution ....... 420 512
------ ------
Total .................................... $1,101 $1,164
====== ======
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Concluded
Note 10. Related Party Transactions
Loans to TIE
In April 1999, Global and its partner, Panda Energy International, Inc.,
established Texas Independent Energy, L.P. (TIE), a 50/50 joint venture, to
develop, construct, own, and operate electric generation facilities in Texas. As
of March 31, 2002, Global's investments in the TIE partnership include $76
million of loans that earn interest at an annual rate of 12% that are scheduled
to be repaid over the next 10 years.
Loans to GWF Energy
In May 2001, GWF Energy, a 50/50 joint venture between Global and Harbinger
GWF LLC, entered into a 10-year PPA with the CDWR to provide 340 MW of electric
capacity to California from three new natural gas-fired peaking plants that GWF
Energy expects to build and operate in California. Total project cost is
estimated at approximately $335 million. The first plant, a 90 MW facility, was
completed and began operation in August 2001. The second plant is currently
under construction, with completion expected in July 2002, and the third plant
is in the permitting process. Global's permanent equity investment in these
plants, including contingencies, is not expected to exceed $100 million after
completion of project financing, which is currently expected to occur in late
2002 or in 2003. Pending completion of project financing, Global has provided
GWF Energy approximately $98 million of secured loans to finance the purchase of
turbines. The turbine loans bear interest at rates ranging from 12% to 15% per
annum and are payable in installments beginning May 31, 2002, with final
maturity no later than December 31, 2002. Global has also provided GWF Energy
$27 million of working capital loans that bear interest at 20% per annum and are
convertible into equity at Global's option on various dates expiring in May
2002. For a further discussion of this issue matter, see Note 4. Commitments and
Contingent Liabilities.
Note 11. Restatement
Subsequent to the issuance of our financial statements included in our Form
10-Q for the three-month period ended March 31, 2002, management determined that
approximately $80 million of electric revenues and electric energy costs had
been inadvertently recorded due to a bookkeeping error in the month of March
2002, involving the purchase and sale of energy with the PJM ISO by our
generation segment. As a result, the financial statements for the three months
ended March 31, 2002, have been restated from the amounts previously reported to
reduce generation revenues and energy costs as shown below. The restatement is
limited to these line items and this time period, and has no effect on our
margins, earnings or cash flows.
For the Quarter Ended March 31, 2002
As Previously As Restated
Reported -----------
--------------
Electric Revenues $1,072 $992
Total Operating Revenues 2,515 2,435
Electric Energy Costs 310 230
Total Operating Expenses 1,974 1,894
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
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
This Form 10-Q is being amended to reflect a change to our Consolidated
Statement of Income for the three months ended March 31, 2002, to reduce
reported amounts of Electric Revenues and Electric Energy Costs by approximately
$80 million. This change relates to an inadvertent bookkeeping error recorded in
the month of March 2002, and reported in our March 31, 2002, Form 10-Q involving
the purchase and sale of energy with the PJM ISO by our generation segment. This
restatement is limited to these line items and time period, and had no effect on
our margins, earnings or cash flows. For additional information related to the
restatement, see Note 11. Restatement of the Notes to Consolidated Financial
Statements (Notes).
For purposes of this Form 10-Q/A, and in accordance with Rule 12b-15 under
the Securities Exchange Act of 1934, as amended, each item of the Form 10-Q for
the quarter ended March 31, 2002 as originally filed on May 15, 2002 that was
affected by the restatement has been amended to the extent affected and restated
in its entirety. NO ATTEMPT HAS BEEN MADE IN THIS FORM 10-Q/A TO MODIFY OR
UPDATE OTHER DISCLOSURES AS PRESENTED IN THE ORIGINAL FORM 10-Q EXCEPT AS
REQUIRED TO REFLECT THE EFFECTS OF THE RESTATEMENT AND THE ADOPTION OF STATEMENT
OF FINANCIAL ACCOUNTING STANDARDS NO. 142, "GOODWILL AND OTHER INTANGIBLE
ASSETS" (SFAS 142). Under this standard, we were required to complete an
impairment analysis of goodwill during 2002. The implementation of the
impairment provisions of SFAS 142 was performed in the second quarter of 2002
retroactive to January 1, 2002, resulting in a $120 million after-tax charge to
earnings recorded as a cumulative effect of a change in accounting principle, as
well as a decrease in our recorded assets and equity.
Net Income for the quarter ended March 31, 2002 was $60 million or $0.29
per share of common stock, based on 206 million average shares outstanding,
including a non-cash charge of $120 million (after-tax) related to the adoption
of SFAS 142. These results also include a charge of $31 million (after-tax), or
$0.15 cents per share, due to a first-quarter change in the functional currency
of an investment in Argentina resulting from the economic crisis there. Results
excluding these charges would have been $211 million or $1.02 per share. We
continue to expect earnings for the year to meet our previous guidance of $3.90
to $4.10 per share, excluding any accounting charges associated with the
Argentine crisis. These charges are not expected to affect our long-term annual
EPS growth target of 7%.
The $0.15 per share non-cash charge recorded in the first quarter was
related to a change in the functional currency of EDEERSA, a distribution
company in which Global has a 90% interest, from the U.S. dollar to the
Argentine Peso. The Argentine Peso has lost significant value this year due to
the ongoing turmoil in Argentina and, because of the change in functional
currency, approximately $76 million of non-recourse, U.S. dollar-denominated
debt was marked to the Argentine Peso. This charge of $47 million (pre-tax), $31
million (after-tax), in connection with our , reduces our previously disclosed
exposure in Argentina from $632 million to $522 million. See Note 4. Commitments
and Contingent Liabilities for further discussion of the Argentine economic
crisis, our investment exposure, potential goodwill impairments, and certain
other contingencies.
Effective January 1, 2002 we adopted SFAS 142, as required by the standard.
Under SFAS 142, goodwill is considered a nonamortizable asset and is subject to
an annual review for impairment and an interim review when certain events or
changes in circumstances occur. The effect of no longer amortizing goodwill on
an annual basis was not material to our financial position and statement of
operations upon adoption. Under this standard, we were required to complete an
impairment analysis of goodwill during 2002 and record any required impairment
as of January 1, 2002. We have finalized our evaluation of the effect of
adopting SFAS 142 on the recorded amount of goodwill. The total amount of
goodwill impairments is $120 million (after-tax) and is comprised of $36 million
(after-tax) at EDEERSA, $34 million (after-tax) at Rio Grande Energia (RGE), $32
million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir
Bavi. All of the goodwill on these companies, other than RGE, is fully impaired.
As noted above, this has been recorded as a cumulative effect of a change in
accounting principle as of January 1, 2002.
While Global realized substantial growth in 2001, significant challenges
began developing during the fourth quarter of 2001 and into 2002. These
challenges include the Argentine economic crisis, the soft power market in Texas
and the worldwide economic downturn. As a result, Global has refocused its
strategy from one of accelerated growth to one that places emphasis on
increasing the efficiency and returns of its existing assets.
Power is expected to be a major factor in achieving our goals for the year.
Power's successful participation as an indirect supplier of energy to New
Jersey's utilities, including PSE&G, involved in New Jersey's recent basic
generation service (BGS) auction is expected to have a meaningful effect on our
earnings, particularly in the second half of the year and should more than
offset the lack of an earnings contribution from Argentina. Power surpassed its
objective of securing contracts on more than 75% of its capacity with suppliers
that won the right to serve New Jersey's utilities for a one-year period
beginning August 1. At the same time, PSE&G was able to secure all of its power
supply for the one-year period at competitive prices.
Following are the significant changes in or additions to information
reported in our 2001 Annual Report on Form 10-K affecting the consolidated
financial condition and the results of operations of us and our subsidiaries.
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
Earnings (Losses)
-------------------------------
For the Quarter Ended
March 31,
-------------------------------
2002 2001
------------ ------------
(Millions of Dollars)
Generation............................................ $102 $73
Energy Trading........................................ 18 29
PSE&G................................................. 67 109
Resources ............................................ 14 3
Global (A)............................................ (10) 48
Energy Technologies................................... (3) (3)
Other (B)............................................. (8) (5)
------------ ------------
Total PSEG Before Cumulative Effect of a Change
in Accounting Principle and Extraordinary Item (A)... $180 $254
Cumulative Effect of a Change in Accounting Principle(C) $(120) $9
Extraordinary Item.................................... -- (2)
------------ ------------
Total PSEG............................................ $60 $261
------------ ------------
Total PSEG Excluding Argentina Charge, Cumulative Effect of
a Change in Accounting Principle and Extraordinary Item(C) $211 $254
============ ============
Contribution to Earnings Per
Share
(Basic and Diluted)
For the Quarter Ended March
31,
------------ ----- ------------
2002 2001
------------ ------------
Generation.......................................... $0.49 $0.35
Energy Trading...................................... 0.09 0.14
PSE&G............................................... 0.32 0.52
Resources........................................... 0.07 0.02
Global (A).......................................... (0.05) 0.24
Energy Technologies................................. (0.02) (0.02)
Other (B)........................................... (0.03) (0.03)
------------ ------------
Total PSEG Before Cumulative Effect of a Change
in Accounting Principle and Extraordinary Item (A)... $0.87 $1.22
Cumulative Effect of a Change in Accounting Principle(C) $(0.58) $0.04
Extraordinary Item.................................... -- $(0.01)
------------ ------------
Total PSEG............................................ $0.29 $1.25
------------ ------------
Total PSEG Excluding Argentina Charge, Cumulative Effect of
a Change in Accounting Principle and Extraordinary Item(C) $1.02 $1.22
============ ============
(A) Includes a charge $47 million pre-tax, $31 million after-tax or $0.15
per share related to the change in the functional currency of the
$US to the Argentine Peso.
(B) Other activities include amounts applicable to PSEG (parent
corporation) and Energy Holdings. Losses primarily result from
after-tax effect of interest on certain financing transactions and
certain other administrative and general expenses at parent companies.
(C) Related to the adoption of SFAS 142 for 2002 and the adoption of SFAS
133 for 2001.
Basic and diluted earnings per share of our common stock (Common Stock)
were $0.29 for the quarter ended March 31, 2002, representing a decrease of
$0.96 or a 77% from the comparable 2001 period. The results include a charge of
$31 million or $0.15 per share due to a first-quarter change in the functional
currency of an investment in Argentina resulting from the economic crisis there,
and an after-tax charge of $120 million or $0.58 per share related to the
adoption of SFAS 142. Results excluding the charge would have been $211 million
or $1.02 per share.
Power's contribution to earnings per share of Common Stock for the quarter
ended March 31, 2002 increased $0.09 or 18% from the comparable 2001 period. The
increase was due primarily to higher generation revenues and lower fuel costs.
PSE&G's earnings per share of Common Stock for the quarter ended March 31, 2002
decreased $0.20 or 39% for the quarter ended March 31, 2002 from the comparable
2001 period primarily due to unusually warm winter weather. Energy Holdings'
contribution to earnings per share of Common Stock for the quarter ended March
31, 2002 decreased $0.27 from the comparable 2001 period, primarily due to the
$0.15 charge due to the change in the functional currency of an Argentine
investment noted above, and the absence of a $0.19 benefit to Global related to
its withdrawal from an interest in the Eagle Point Cogeneration Partnership in
the first quarter of 2001. In December 2000, Global withdrew from its interest
in Eagle Point in exchange for a series of payments through 2005, expected to
total up to $290 million. Such payments will be made in each year until 2005,
provided certain operating contingencies are met. With respect to Eagle Point,
Global expects to record a total of $46 million in the second and third quarters
of 2002, as operating contingencies for the facility are expected to be met.
For the Quarter Ended March 31, 2002 compared to the Quarter Ended March
31, 2001
Operating Revenues
Electric
Electric revenues increased $67 million or 7% for the quarter ended March
31, 2002 from the comparable period in 2001 primarily due to the inclusion of
$92 million of revenues related to various majority-owned acquisitions and
plants going into operation at our Global segment in the second quarter of 2001.
Generation segment revenues increased $64 million or 11% for the quarter
ended March 31, 2002 from the comparable period in 2001 primarily due to an
increase of $65 million in Interchange/Spot Market Sales due to additional
generation and favorable prices. Also, a $25 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%. These increases were partially offset by a net $28 million
decrease in Market Transition Charge (MTC) revenues remitted to Power from PSE&G
relating to the two 2% rate reductions that occurred in February and August 2001
and a decrease in our PSE&G segment revenues of $10 million or 3% due to the
effects of warmer weather.
Gas Distribution
Gas distribution revenues decreased $267 million or 25% for the quarter
ended March 31, 2002 from the comparable period in 2001 due to the unusually
warm winter and decreased commodity rates that became effective in January 2002,
partially offset by increased gas base rates. For the quarter ended March 31,
2002, we experienced an 18% decrease in degree days, as compared to the first
quarter 2001.
Trading
Trading revenues decreased $157 million or 27% for the quarter ended March
31, 2002 from the comparable period in 2001 due to lower trading volumes in the
first quarter of 2001 (see corresponding decrease in trading costs). Despite
lower trading volumes for the quarter, we expect to meet our full year trading
margin goals.
Other
Other revenues decreased $27 million or 12% for the quarter ended March 31,
2002 from the comparable period in 2001 due primarily to a $43 million gain
recorded in connection with Global's withdrawal and sale from its interest in
the Eagle Point Cogeneration Partnership. Global expects to recover much of this
shortfall with scheduled payments later this year. This decrease was partially
offset by Resources' higher leveraged lease income of $10 million, as compared
to the first quarter of 2001, and Resources' lower net investment losses of $10
million, as compared to the first quarter of 2001.
Operating Expenses
Electric Energy Costs
Electric Energy Costs increased $10 million or 5% for the quarter ended
March 31, 2002 from the comparable 2001 period primarily due to the inclusion of
expenses related to various majority-owned acquisitions and plants going into
operation at our Global segment in the second and third quarters of 2001.
The increased load served under the BGS contract due to the additional
retail customers returning to PSE&G in 2001 also contributed to the increase.
This increase was partially offset by the lower cost of fuel, particularly
natural gas and the continued strong performance of our nuclear generating
plants.
Gas Costs
Gas Costs decreased $260 million or 33% for the quarter ended March 31,
2002 from the comparable 2001 period primarily due to lower demand as a result
of the warmer weather and decreased commodity rates that became effective in
January of 2002.
Trading Costs
Trading Costs decreased $138 million or 26% for the quarter ended March 31,
2002 from the comparable 2001 period primarily due to lower trading volumes (see
corresponding decreases in trading revenues).
Operations and Maintenance
Operations and Maintenance expense increased $17 million or 3% primarily
due to higher operating costs associated with new projects going into service at
our Global segment.
Depreciation and Amortization
Depreciation and Amortization expense increased $29 million or 27% for the
quarter ended March 31, 2002 from the comparable 2001 period. The increase was
primarily due to a full periods recognition of amortization of the regulatory
asset recorded for PSE&G's stranded costs beginning in February 2001 and the
increase in gas depreciation expense recorded in accordance with PSE&G's
increased gas base rates.
Interest Expense
Interest Expense increased $31 million or 19% for the quarter ended March
31, 2002 from the comparable 2001 period primarily due to increased long-term
debt used to finance several investments made in 2001.
Liquidity and Capital Resources
The following discussion of our liquidity and capital resources is on a
consolidated basis, noting the uses and contributions of our three direct
operating subsidiaries, PSE&G, Power and Energy Holdings.
Financing Methodology
Our capital requirements and those of our subsidiaries are met through
liquidity provided by internally generated cash flow and external financings.
PSEG, Power and Energy Holdings from time to time make equity contributions to
their respective direct and indirect subsidiaries to provide for part of their
capital and cash requirements, generally relating to long-term investments. At
times, we utilize inter-company 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 our needs and the needs of PSE&G, the majority of
the requirements of Power and a substantial portion of the requirements of
Energy Holdings, is comprised of corporate finance transactions. The debt
incurred is the direct obligation of those respective entities. Some of the
proceeds of these debt transactions are used by the respective obligor to make
equity investments in its subsidiaries.
Depending on the particular company, 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.
Some of these transactions involve special purpose entities. These are
corporations, limited liability companies or partnerships formed in accordance
with applicable tax, accounting and legal requirements in order to achieve
specified beneficial financial advantages, such as favorable tax, legal
liability or accounting treatment.
The availability and cost of external capital could be affected by each
subsidiary's performance as well as by the performance of their respective
subsidiaries and affiliates. This could include the degree of structural or
regulatory separation between us and our subsidiaries and between PSE&G and its
non-utility affiliates and the potential impact of affiliate ratings on
consolidated and unconsolidated 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 Global's projects and investments is generally provided by
non-recourse project financing transactions. These consist of loans from banks
and other lenders that are typically secured by project and special purpose
subsidiary assets and/or cash flows. Two of Power's projects currently under
construction have similar financing. 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 Global, Energy Holdings, and/or Power. 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 credit agreements and those of our subsidiaries and the debt indentures
of Power and Energy Holdings contain cross-default provisions under which a
default by us or by specified subsidiaries involving specified levels of
indebtedness in other agreements would result in a default and the potential
acceleration of payment under such indentures and credit agreements. For
example, a default with respect to specified indebtedness in an aggregate amount
of $50 million for us, $50 million for Power, $50 million for PSE&G or $5
million for Energy Holdings, including relevant equity contribution obligations
in subsidiaries' non-recourse transactions, would cause a cross-default in our
or certain of our subsidiaries' credit agreements or indentures.
If such a default were to occur, lenders, or the debt holders under any of
our or our subsidiaries' indentures, could determine that debt payment
obligations may be accelerated as a result of a cross-default. A declaration of
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 would have a
similar impact. This would have a material adverse effect on our financial
condition, results of operations and net cash flows, and those of our
subsidiaries.
In addition, our credit agreements and those of our 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, Energy Holdings', Power's or PSE&G's business or financial condition. In
the event that we or the lenders in any of our or our subsidiaries' credit
agreements determine that a material adverse change has occurred, loan funds may
not be advanced.
Some of these credit agreements also 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 our
future financial position and the level of earnings and cash flow, as to which
no assurances can be given. As part of our financial planning forecast, we
perform stress tests on our financial covenants. These tests include a
consideration of the impacts of potential asset impairments, foreign currency
fluctuations and other items. Our current analysis and projections indicate
that, even in a worst-case scenario with respect to our investments in Argentina
and considering other potential events, we should still be able to meet our
financial covenants.
Our debt indentures and credit agreements and those of our subsidiaries do
not contain any "ratings triggers" that would cause an acceleration of the
required interest and principal payments in the event of a ratings downgrade.
However, in the event of a downgrade, we and/or our subsidiaries may be subject
to increased interest costs on certain bank debt. Also, in connection with its
energy trading business, Power must meet certain credit quality standards as are
required by counterparties. If Power loses its investment grade credit rating,
ER&T would have to provide credit support (letters of credit or cash), which
would significantly impact the energy trading business. These same contracts
provide reciprocal benefits to Power. 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. Global and Energy Holdings may have to provide collateral for certain
of their equity commitments if Energy Holdings' ratings should fall below
investment grade.
Regulatory Restrictions
Capital resources and investment requirements could be affected by the
outcome of proceedings by the BPU pursuant to the Energy Competition Act and the
requirements of the 1992 Focused Audit conducted by the BPU, of the impact of
our non-utility businesses, owned by Energy Holdings, on PSE&G. As a result of
the Focused Audit, the BPU ordered that, among other things:
(1) We will not permit Energy Holdings' investments to exceed 20% of our
consolidated assets without prior notice to the BPU;
(2) PSE&G's Board of Directors would provide an annual certification that
the business and financing plans of Energy Holdings will not adversely
affect PSE&G;
(3) We will (a) limit debt supported by the minimum net worth maintenance
agreement between us and PSEG Capital to $650 million and (b) make a
good-faith effort to eliminate such support over a six to ten year
period from May 1993; and
(4) Energy Holdings will pay PSE&G an affiliation fee of up to $2 million
a year which is to be used to reduce customer rates.
In the Final Order the BPU noted that, due to significant changes in the
industry and, in particular, our corporate structure as a result of the Final
Order, modifications to or relief from the Focused Audit order might be
warranted. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt
by the end of the second quarter of 2003 and that it believes that the Final
Order otherwise supercedes the requirements of the Focused Audit. The BPU is
expected to address the matter later this year. While we believe that this issue
will be satisfactorily resolved, no assurances can be given. In addition, if we
were no longer to be exempt under the Public Utility Holding Company Act of 1935
(PUHCA), we and our subsidiaries 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.
Over the next several years, we and our subsidiaries will be required to
refinance maturing debt, 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 affect our financial condition,
results of operations and net cash flows.
Short Term Liquidity
We and our subsidiaries have revolving credit facilities to provide
liquidity for our $850 million commercial paper program and PSE&G's $550 million
commercial paper program and for various funding purposes. We are in the process
of increasing our commercial paper program to $1 billion and have already
increased our available credit facilities accordingly. We also have bilateral
agreements available at PSEG, PSE&G and Energy Holdings.
The following table summarizes the various revolving credit facilities of
PSEG, PSE&G and Energy Holdings as of March 31, 2002. Power has no such credit
facilities and relies on PSEG for its short-term financing needs.
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
PSE&G:
364-day Credit Facility June 2002* 275 CP Support
5-year Credit Facility June 2002* 275 CP Support
Uncommitted Bilateral Agreement N/A ** Funding
Energy Holdings:
364-day Credit Facility May 2003 200 Funding
5-year Credit Facility May 2004 495 Funding
Uncommitted Bilateral Agreement N/A ** Funding
* Expected to be extended in the second quarter of 2002.
** Availability varies based on market conditions.
As of March 31, 2002, our consolidated total short-term debt outstanding
was $1.503 billion, including $689 million of commercial paper at PSEG, $284
million of non-recourse short-term financing at Global and $258 million and $272
million outstanding under credit facilities and through the uncommitted
bilateral agreement at PSEG and Energy Holdings, respectively. In addition, we
have a total of $1.385 billion of long-term debt due within one year, comprised
of $274 million at PSEG, $823 million at PSE&G and $288 million at Energy
Holdlings.
In the ordinary course of business, we and our subsidiaries have financial
commitments for debt maturities and general corporate purposes. On April 16,
2002 PSEG filed a shelf registration statement on Form S-3 for the issuance of
$1.5 billion of various debt and equity securities. The registration statement
is currently under review by the Staff of the Securities and Exchange Commission
(SEC). In the near term, while we anticipate that our commitments could be in
excess of our current short-term funding capacity and internally-generated cash
flow, we expect to meet these commitments through a variety of short-term
borrowings incremental to our existing commercial paper programs, credit
facilities and bilateral credit agreements. It is expected that any such
incremental, short-term borrowings would be refinanced through the issuance of
more permanent financing by PSEG.
PSEG
As of December 31, 2001, we had repurchased approximately 26.5 million
shares of Common Stock, at a cost of approximately $997 million since 1998. For
the year-ended December 31, 2001, we had repurchased approximately 2.3 million
shares of Common Stock, at a cost of approximately $92 million. The repurchased
shares have primarily been held as treasury stock with the balance used for
general corporate purposes. No shares have been repurchased subsequent to
December 2001. In addition, since December 31, 2001 we have issued 355,491
shares under our Dividend Reinvestment and Stock Purchase Plan (DRASPP).
Dividend payments on Common Stock for the quarter ended March 31, 2002 were
$0.54 per share and totaled approximately $111 million. Our dividend rate has
remained constant since 1992 in order to retain additional capital for
reinvestment and to reduce the payout ratio as earnings grow. Although we
presently believe we will have adequate earnings and cash flow in the future
from our subsidiaries to maintain common stock dividends at the current level,
earnings and cash flows required to support the dividend will become more
volatile as our business continues to change from one that was principally
regulated to one that is principally competitive. Future dividends declared will
necessarily be dependent upon our future earnings, cash flows, financial
requirements, alternate investment opportunities and other factors. We would
consider raising the dividend if our payout ratio declined to 50% and could be
sustained at that level.
We have issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on these
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, we may not pay any dividends on its common stock until such
payments become current. Currently, there has been no deferral or default.
Financial covenants contained in our credit facilities include the ratio of
debt (excluding non-recourse project financings and securitization debt and
including commercial paper and loans, certain letters of credit and similar
instruments) to total capitalization. At the end of any quarterly financial
period such ratio shall not be more than 0.70 to 1. As of March 31, 2002, the
ratio of debt to capitalization was 0.65 to 1.
As noted above, PSEG has filed a registration statement with the SEC which
is currently under review and has not yet become effective.
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements and/or retired Mortgage Bonds
provided that its ratio of earnings to fixed charges calculated in accordance
with its Mortgage is at least 2:1. At March 31, 2002, PSE&G's Mortgage coverage
ratio was 3:1. As of March 31, 2002, the Mortgage would permit up to
approximately $1 billion aggregate principal amount of new Mortgage Bonds to be
issued against previous additions and improvements. PSE&G will need to obtain
BPU authorization to issue any financing necessary for its capital program,
including refunding of maturing debt and opportunistic refinancing. PSE&G has
authorization from the BPU to issue $1 billion of long-term debt through
December 31, 2003 for the refunding of maturing debt and opportunistic
refinancing of debt.
In December 2001, PSE&G filed a shelf registration statement on Form S-3
for the issuance of $1 billion of debt and tax deferred preferred securities,
which was declared effective by the SEC in February 2002.
Since 1986, PSE&G has made regular cash payments to us in the form of
dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock
dividends of $150 million and $112 million to us for the quarters ended March
31, 2002 and 2001, respectively.
PSE&G has issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on those
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, PSE&G may not pay any dividends on its common or preferred stock
until such default is cured. Currently, there has been no deferral or default.
Power
Power's short-term financing needs will be met using our commercial paper
program or lines of credit discussed above.
Energy Holdings
As of March 31, 2002, Energy Holdings had two separate senior revolving
credit facilities with a syndicate of banks as discussed in the table above. The
five-year facility permits up to $250 million of letters of credit to be issued
of which $14 million are outstanding as of March 31, 2002.
Financial covenants contained in these facilities include the ratio of cash
flow available for debt service (CFADS) to fixed charges. At the end of any
quarterly financial period such ratio shall not be less than 1.50x for the
12-month period then ending. As a condition of borrowing, the pro-forma CFADS to
fixed charges ratio shall not be less than 1.75x as of the quarterly financial
period ending immediately following the first anniversary of each borrowing or
letter of credit issuance. CFADS includes, but is not limited to, operating cash
before interest and taxes, pre-tax cash distributions from all asset
liquidations and equity capital contributions from us to the extent not used to
fund investing activity. In addition, the ratio of consolidated recourse
indebtedness to recourse capitalization, as at the end of any quarterly
financial period, shall not be greater than 0.60 to 1.00. This ratio is
calculated by dividing the total recourse indebtedness of Energy Holdings by the
total recourse capitalization. This ratio excludes the debt of PSEG Capital,
which is supported by us. As of March 31, 2002, the latest 12 months CFADS
coverage ratio was 5.2 and the ratio of recourse indebtedness to recourse
capitalization was .44 to 1.
PSEG Capital has a $650 million MTN program which provides for the private
placement of MTNs. This MTN program is supported by a minimum net worth
maintenance agreement between PSEG Capital and us which provides, among other
things, that we (1) maintain its ownership, directly or indirectly, of all
outstanding common stock of PSEG Capital, (2) cause PSEG Capital to have at all
times a positive tangible net worth of at least $100,000 and (3) make sufficient
contributions of liquid assets to PSEG Capital in order to permit it to pay its
debt obligations. We will eliminate our support of PSEG Capital debt by the
second quarter of 2003, as required by the Focused Audit. At March 31, 2002 and
December 31, 2001, total debt outstanding under the MTN program was $480 million
and $480 million, respectively maturing from 2002 to 2003.
Capital Requirements
Power's capital needs will be dictated by its strategy to continue to
develop as a profitable, growth-oriented supplier in the wholesale power market.
PSE&G's construction expenditures are primarily to maintain the safety and
reliability of its electric and gas transmission and distribution facilities. We
plan to continue the growth of Resources. Global has refocused its strategy,
from one of accelerated growth to one that places emphasis on increasing the
efficiency and returns of its existing assets. We are evaluating the future
prospects and opportunities of Energy Technologies' business.
For the quarter ended March 31, 2002, we made net plant additions of $373
million, excluding Allowance for Funds Used During Construction (AFDC) and
capitalized interest. The majority of these additions, $216 million, primarily
related to Power for developing the Lawrenceburg, Indiana and the Waterford,
Ohio sites and adding capacity to the Bergen and Linden stations in New Jersey.
In addition, PSE&G had net plant additions of $80 million related to
improvements in its transmission and distribution system, gas system and common
facilities. Also, Energy Holdings' subsidiaries made investments totaling
approximately $77 million for the quarter ended March 31, 2002. These
investments included investments by Resources and additional investments in
existing domestic and international facilities at Global. The $373 million of
net plant additions and $77 million of investments were included in our
forecasted expenditures for the year.
Accounting Matters
For a discussion of SFAS 142, SFAS 143 and SFAS 144, see Note 2. Accounting
Matters and Note 4. Commitments and Contingent Liabilities.
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of SFAS No.
71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) for
PSE&G, our regulated transmission and distribution business; 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; SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities", as amended (SFAS 133), to account for our various hedging
transactions; SFAS 52, "Foreign Currency Translation" and its impacts on
Global's foreign investments; and SFAS 142 and SFAS 144 and their potential
impacts on our various investments.
Accounting for the Effects of Regulation
PSE&G prepares its financial statements in accordance with the provisions
of SFAS No. 71, which differs in certain respects from the application of GAAP
by non-regulated businesses. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated utility is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if
it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, PSE&G has
deferred certain costs, which will be amortized over various future periods. To
the extent that collection of such costs or payment of liabilities is no longer
probable as a result of changes in regulation and/or PSE&G's competitive
position, the associated regulatory asset or liability is charged or credited to
income.
As a result of New Jersey deregulation legislation and regulatory orders
issued by the BPU, certain regulatory assets and liabilities were recorded. Two
of these items will have a significant effect on our annual earnings. They
include the estimated amount of MTC revenues to be collected in excess of the
authorized amount of $540 million and the amount of excess electric distribution
depreciation reserves.
The MTC was authorized by the BPU as an opportunity to recover up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on a
net present value basis. As a result of the appellate reviews of the Final
Order, PSE&G's securitization transaction was delayed until the first quarter of
2001, causing a delay in the implementation of the Securitization Transition
Charge (STC) which would have reduced the MTC. As a result, MTC was being
recovered at a faster rate than intended under the Final Order and a significant
overrecovery was probable. In order to properly recognize the recovery of the
allowed unsecuritized stranded costs over the transition period, PSE&G recorded
a regulatory liability and Power recorded a charge to net income of $88 million,
pre-tax, or $52 million, after tax, in the third quarter of 2000 for the
cumulative amount of estimated collections in excess of the allowed
unsecuritized stranded costs from August 1, 1999 through September 30, 2000.
PSE&G then began deferring a portion of these revenues each month to recognize
the estimated collections in excess of the allowed unsecuritized stranded costs.
As of March 31, 2002, this deferred amount was $177 million and is aggregated
with the Societal Benefits Clause. After deferrals, pre-tax MTC revenues
recognized were $220 million in 1999, $239 million in 2000, and $196 million in
2001. In 2002 and 2003, we expect to record approximately $90 million and $121
million, respectively.
The amortization of the Excess Depreciation Reserve is another significant
regulatory liability affecting our earnings. As required by the BPU, PSE&G
reduced its depreciation reserve for its electric distribution assets by $569
million and recorded such amount as a regulatory liability to be amortized over
the period from January 1, 2000 to July 31, 2003. Through March 31, 2002, $287
million had been amortized and recorded as a reduction of depreciation expense
pursuant to the Final Order, of which $37 million relates to 2002. The remaining
$282 million will be amortized through July 31, 2003.
See Note 3. Regulatory Assets and Liabilities of Notes for further
discussion of these and other regulatory issues.
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 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 5. 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, or as a Regulatory Asset (Liability). 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,
interest rate swaps and foreign currency hedges 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 5 - Financial Instruments Energy Trading and Risk Management - Derivative
Instruments and Hedging Activities of Notes.
SFAS 52 - Foreign Currency Translation
Our financial statements are prepared using the $US Dollar as the reporting
currency. In accordance with SFAS 52 "Foreign Currency Translation", foreign
operations whose functional currency is deemed to be the local (foreign)
currency, asset and liability accounts are translated into $US Dollars at
current exchange rates and revenues and expenses are translated at average
exchange rates prevailing during the period. Translation gains and losses (net
of applicable deferred taxes) are not included in determining net income but are
reported in other comprehensive income. Gains and losses on transactions
denominated in a currency other than the functional currency are included in the
results of operations as incurred.
The determination of an entity's functional currency requires management's
judgment. It is based on an assessment of the primary currency in which
transactions in the local environment are conducted, and whether the local
currency can be relied upon as a stable currency in which to conduct business.
As economic and business conditions change, we are required to reassess the
economic environment and determine the appropriate functional currency. The
impact of foreign currency accounting has had and could continue to have a
material adverse impact on our financial condition, results of operation and net
cash flows. See Note 4. Commitments and Contingent Liabilities for a discussion
of the change in functional currency of EDEERSA from the $US Dollar to the
Argentine Peso.
Accounting for the Effects of Goodwill
We have finalized our evaluation of the effect of adopting SFAS 142 on the
recorded amount of goodwill. The total amount of goodwill impairments is $120
million, net of tax of $66 million, and is comprised of $36 million (after-tax)
at EDEERSA, $34 million (after-tax) at RGE, $32 million (after-tax) at Energy
Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on
these companies, other than RGE, is fully impaired. As noted above, this has
been recorded as a cumulative effect of a change in accounting principle as of
January 1, 2002.
As of March 31, 2002 and December 31, 2001, our unamortized goodwill and
pro-rata share of goodwill in equity method investees was as follows:
As of
March 31, 2002 December 31, 2001
-------------- -----------------
Global (Millions of Dollars)
SAESA................................................... $ 315 $ 315
EDEERSA(1).............................................. -- 63
Electroandes (2)........................................ 136 164
Tanir Bavi (3).......................................... -- 27
ELCHO................................................... 6 6
-------------- -----------------
Total Global...................................... 457 575
Energy Technologies (3).................................... -- 53
Power - Generation......................................... 21 21
-------------- -----------------
Total Consolidated Goodwill.................. 478 649
-------------- -----------------
Global
RGE (4)................................................. 92 142
Chilquinta (5).......................................... 174 174
Luz del Sur............................................. 39 34
Kalaeloa................................................ 25 25
-------------- -----------------
Pro-Rata Share of Equity Investment Goodwill.......... 330 375
-------------- -----------------
Total Goodwill.................................... $ 808 $1,024
============== =================
(1) The decrease at EDEERSA relates to an impairment of $56 million and $7
million of purchase price adjustments made subsequent to December 31, 2001.
(2) The changes at Electroandes and Luz del Sur relate to purchase price
adjustments made subsequent to December 31, 2001.
Accounting for Long-Lived Assets
On January 1, 2002 we adopted SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). The impact of adopting SFAS 144 did
not have an effect on our financial position and statement of operations. Under
SFAS 144, long-lived assets to be disposed of are measured at the lower of
carrying amount or fair value less costs 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. A long-lived asset must be tested for impairment whenever events or
changes in circumstances indicate that its carrying amount may be impaired.
As previously disclosed, we have approximately $529 million of investment
exposure in Argentina. Due to the economic, political and social crisis in
Argentina, our investments there are faced with considerable fiscal and cash
flow uncertainties. As a result of these events, an impairment test of these
investments is required. However, due to the vast uncertainty related to the
situation in Argentina, reasonable assumptions related to the environment in
Argentina cannot be easily made. As the situation continues to evolve, we will
be able to develop assumptions related to the environment in Argentina and these
investments and will complete our impairment test.
In addition to impairment testing for the Argentine investments, an
impairment test for Energy Technologies is also being done as negative operating
cash flow of certain parts of that entity indicate a potential impairment. These
tests are required whenever events or circumstances indicate an impairment may
exist. Examples of potential events which could require an impairment test are
when power prices become depressed for a prolonged period in a market, when a
foreign currency significantly devalues, or when an investment generates
negative operating cash flows. Any potential impairments of these investments
are recorded above the line. For additional information relating to potential
asset impairments, see Note 4. Commitments and Contingent Liabilities.
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 foreign currency
exchange rates, commodity prices, equity security 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 comprised of executive officers
which utilizes an independent risk oversight function to ensure compliance with
corporate policies and prudent risk management practices.
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.
Our Board of Directors has established a VAR Threshold of $75 million and
the Risk Management Committee (RMC) has established an internal VAR threshold of
$50 million for Power. If the $50 million threshold was 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 $18
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 have established credit policies 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.
As a result of the BGS auction, Power has contracted to provide generating
capacity to the direct suppliers of New Jersey's 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.
Foreign Operations
As of March 31, 2002, Global and Resources had approximately $3.4 billion
and $1.4 billion, respectively, of international assets. As of March 31, 2002,
foreign assets represented 19% of our consolidated assets and the revenues
related to those foreign assets contributed 6% to consolidated revenues for the
quarter ended March 31, 2002. For discussion of foreign currency risk and
potential asset impairments related to our investments in Argentina, see Note 5.
Financial Instruments Energy Trading and Risk Management, Note 4. Commitments
and Contingent Liabilities.
Resources' international investments are primarily leveraged leases of
assets located in Austria, Australia, Belgium, China, Germany, the Netherlands,
United Kingdom, and New Zealand with associated revenues denominated in U.S.
Dollars and therefore, not subject to foreign currency risk.
Global's international investments are primarily in projects that are
presently or upon completion are expected to generate or distribute electricity
in Argentina, Brazil, Chile, China, India, Italy, Peru, Poland, Tunisia and
Venezuela. Investing in foreign countries involves certain additional risks.
Economic conditions that result in higher comparative rates of inflation in
foreign countries are likely to result in declining values in such countries'
currencies. As currencies fluctuate against the $US, there is a corresponding
change in Global's investment value in terms of the $US. Such change is
reflected as an increase or decrease in the investment value and Other
Comprehensive Income, a separate component of Stockholder's Equity. As of March
31, 2002, net foreign currency devaluations have reduced the reported amount of
our total Stockholder's Equity by $320 million, of which $159 million, $84
million and $63 million were caused by the devaluation of the Brazilian Real,
Chilean Peso and Argentine Peso, respectively.
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 because a portion of our business is conducted outside the United
States, adverse international developments could negatively impact our
business;
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 industry is undergoing substantial change;
o generation operating performance may fall below projected levels;
o ability to obtain adequate and timely rate relief;
o we and our subsidiaries are subject to substantial competition from
well capitalized participants in the worldwide energy markets;
o our ability to service debt could be limited;
o power transmission facilities may impact our ability to deliver our
output to customers;
o government regulation affects many of our operations;
o environmental regulation significantly impacts 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 may not be successful; and
o recession, acts of war or 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 Public Service
Enterprise Group Incorporated's (PSEG) 2001 Annual Report on Form 10-K is
updated below.
New Matter. On November 15, 2001, Consolidated Edison, Inc. (Con Edison)
filed a complaint against PSE&G at the Federal Energy Regulatory Commission
(FERC) pursuant to Section 206 of the Federal Power Act asserting that PSE&G had
breached agreements covering 1,000 MW of transmission by curtailing service and
failing to maintain sufficient system capacity to satisfy all of its service
obligations. PSE&G denied the allegations set forth in the complaint. While
finding that Con Edison's presentation of evidence failed to demonstrate several
of the allegations, on April 26, 2002, FERC found sufficient reason to set the
complaint for hearing. The hearing will be conducted on an expedited basis, with
an Initial Decision to be issued by the end of May and a FERC order by the end
of June. If Con Edison is successful, PSE&G could be required to provide future
transmission services with uneconomic generation resources at a substantial cost
to PSE&G. PSE&G believes it has complied with the terms of the Agreement and
will vigorously defend its position. The nature and cost of any remedy, which is
expected to be prospective only, cannot be predicted. Docket No. EL02-23-000.
New Matter. Pages 11-13. AES termination of the Stock Purchase Agreement,
relating to the sale of certain Argentine assets. New York State Supreme Court
for New York County (Docket No. 60155/2002) PSEG Global, et al vs. The AES
Corporation, et al.
In addition, see information on the following proceedings at the pages
indicated:
(1) Form 10-K, Pages 26 and 27. See Page 45. DOE not taking possession of
spent nuclear fuel, Docket No. 01-551C.
(2) Form 10-K Page 100. See Page 8. PSE&G's MGP Remediation Program.
(3) Form 10-K Page 100. See Page 8-9. Investigation and additional
investigation by the EPA regarding the Passaic River site. Docket No.
EX93060255.
(4) Form 10-K Page 102. See Page 10. Complaint filed with the Federal
Energy Regulatory Commission addressing contract terms of certain
Sellers of Energy and Capacity under Long-Term Contracts with the
California Department of Water Resources. Public Utilities Commission
of the State of California v. Sellers of Long Term Contracts to the
California Department of Water Resources FERC Docket No. EL02-60-000.
California Electricity Oversight Board v. Sellers of Energy and
Capacity Under Long-Term Contracts with the California Department of
Water Resources FERC Docket No. EL02-62-000.
ITEM 4. SUBMISSION OF MATTERS TO A
VOTE OF SECURITY HOLDERS
PSEG's Annual Meeting of Stockholders was held on April 16, 2002. Proxies
for the meeting were solicited pursuant to Regulation 14A under the Securities
Act of 1934. There was no solicitation of proxies in opposition to management's
nominees as listed in the proxy statement and all of management's nominees were
elected to the Board of Directors. Details of the voting are provided below:
=========================================================================================
Votes For Votes Withheld
------------------------------------------------------- --------------- -----------------
Proposal 1:
Election of Directors
------------------------------------------------------ --------------- ------------------
Class II - Term expiring in 2004 175,787,329 3,560,131
William V. Hickey
------------------------------------------------------ --------------- ------------------
Class III - Terms expiring in 2005
Raymond V. Gilmartin 176,711,184 2,636,276
Conrad K. Harper 174,596,036 4,751,424
Shirley Ann Jackson 175,334,212 4,013,248
=========================================================================================
Directors Whose Terms Continue Beyond the 2002 Annual Meeting:
-------------------------------------------------------------
Class II - Terms expiring in 2004
Albert R. Gamper, Jr.
Richard J. Swift
--------------------------------------------------------------
Class I - Terms expiring in 2003
Ernest H. Drew
E. James Ferland
=======================================================================================================================
Votes Broker
Votes For Against Abstentions Non-Votes
------------------------------------------------------ -------------- ------------------ ---------------- -------------
Proposal 2:
Approval of the 2001 Long-Term Incentive Plan 112,810,574 35,625,968 3,204,947 27,726,516
------------------------------------------------------ -------------- ------------------ ---------------- -------------
Proposal 3:
Approval of Restated and Amended Management
Incentive Compensation Plan 150,807,910 24,894,914 3,640,166 --
------------------------------------------------------ -------------- ------------------ ---------------- -------------
Proposal 4:
Ratification of Appointment of Deloitte & Touche LLP
as Independent Auditors 170,924,041 6,660,938 1,756,074 --
------------------------------------------------------ -------------- ------------------ ---------------- -------------
Proposal 5:
Shareholder Proposal 12,605,865 134,101,764 4,906,401 27,726,516
=======================================================================================================================
ITEM 5. OTHER INFORMATION
Certain information reported under PSEG's 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 16. 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 ER&T which 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 reduce volatility in PSE&G's cash
flows; however, ER&T will bear the increased commodity risk. Gas residential
commodity costs are currently recovered through adjustment charges 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 18. A pressurized water reactor nuclear unit (PWR) not
owned by us was recently identified with a degradation of the reactor vessel
head, which forms part of the pressure boundary for the reactor coolant system.
In March 2002, the NRC issued a 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 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 26. 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.
Employee Relations
Form 10-K, page 20. As previously disclosed, PSE&G has collective
bargaining arrangements with the Utility Co-Workers Association, (UWUA) covering
approximately 1,400 employees primarily in the customer operations area. This
contract expired on April 30, 2002, and was extended through May 6, 2002. A
tentative agreement was reached on May 7, 2002, and is subject to a ratification
vote by union membership.
Water Pollution Control
Form 10-K, page 23. 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 or 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, meeting the specific or
performance criteria, identified as an option under the draft rule, 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 NJDEP. Upon discovery of this use of the
material, we terminated the services of this 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
-------------- --------
12 Computation of Ratios of Earnings to Fixed Charges
(B) Reports on Form 8-K:
Date of Report Items Reported
-------------- --------------
January 25, 2002 Items 5 and 7
February 7, 2002 Item 5
April 16, 2002 Items 5 and 7
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
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.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
By: PATRICIA A. RADO
--------------------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: July 29, 2002