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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ------- to -------
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- --------------------------------------------- -------------------
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 June 30, 2002, Public Service Enterprise Group Incorporated had
outstanding 206,634,931 shares of its sole class of Common Stock, without par
value.
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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
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Item 1. Financial Statements 2
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations 34
Item 3. Qualitative and Quantitative Disclosures About Market Risk 51
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings 54
Item 5. Other Information 54
Item 6. Exhibits and Reports on Form 8-K 57
Signature 58
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions of Dollars, except for Per Share Data)
(Unaudited)
For the Quarter Ended For the Six Months Ended
June 30, June 30,
--------------------------- ----------------------------
2002 2001 2002 2001
------------- ---------- ----------- -------------
OPERATING REVENUES
Electric $ 1,029 $ 1,036 $ 2,000 $ 1,961
Gas 310 352 1,125 1,434
Trading 344 571 757 1,146
Other 99 88 188 210
------------- ---------- ----------- -------------
Total Operating Revenues 1,782 2,047 4,070 4,751
------------- ---------- ----------- -------------
OPERATING EXPENSES
Electric Energy Costs 270 257 483 475
Gas Costs 183 243 710 1,030
Trading Costs 334 534 715 1,058
Operation and Maintenance 451 441 902 878
Depreciation and Amortization 139 123 271 227
Write-down of Project Investments 506 -- 506 --
Taxes Other Than Income Taxes 28 38 75 86
------------- ---------- ----------- -------------
Total Operating Expenses 1,911 1,636 3,662 3,754
------------- ---------- ----------- -------------
OPERATING (LOSS) INCOME (129) 411 408 997
Foreign Currency Transaction Loss (17) -- (69) --
Other Income 10 12 17 31
Other Deductions (9) (1) (1) (2)
Interest Expense (185) (166) (381) (333)
Preferred Securities Dividend Requirements
and Premium on Redemption (18) (20) (28) (44)
------------- ---------- ----------- --------------
(LOSS) INCOME BEFORE INCOME TAXES, DISCONTINUED OPERATIONS,
EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE
IN ACCOUNTING PRINCIPLE (348) 236 (54) 649
Income Taxes 121 (85) 7 (241)
------------- ---------- ----------- -------------
(LOSS) INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
(227) 151 (47) 408
DISCONTINUED OPERATIONS
Loss from Discontinued Operations, net of tax
(including Loss on Disposal of $34, net of tax) (37) (8) (37) (11)
------------- ---------- ----------- -------------
(LOSS) INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE
(264) 143 (84) 397
Extraordinary Loss on Early Retirement of Debt, net of tax -- -- -- (2)
Cumulative Effect of a Change in Accounting Principle, net of -- -- (120) 9
tax
------------- ---------- ------------ -------------
NET (LOSS) INCOME $ (264) $ 143 $ (204) $ 404
============= ========== ============ =============
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING (000's) 206,927 208,701 206,631 208,512
============= ========== ============ =============
EARNINGS PER SHARE (BASIC AND DILUTED):
(LOSS) INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY
ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
$ (1.10) $ 0.72 $ (0.23) $ 1.96
Loss from Discontinued Operations, net of tax
(including Loss on Disposal, net of tax) (0.18) (0.04) (0.18) (0.05)
Extraordinary Loss on Early Retirement of Debt, net of tax -- -- -- (0.01)
Cumulative Effect of a Change in Accounting Principle, net of -- -- (0.58) 0.04
tax
------------- ---------- ------------ -------------
NET (LOSS) INCOME $ (1.28) $ 0.68 $ (0.99) $ 1.94
============= ========== ============ =============
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54 $ 1.08 $ 1.08
============= ========== ============ =============
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
(Unaudited)
June 30, December 31,
2002 2001
-------------------- ------------------
CURRENT ASSETS
Cash and Cash Equivalents $ 246 $ 167
Accounts Receivable:
Customer Accounts Receivable 653 684
Other Accounts Receivable 237 324
Allowance for Doubtful Accounts (66) (43)
Unbilled Electric and Gas Revenues 181 291
Fuel 359 494
Materials and Supplies, net of valuation reserves - 2002, $2; 192 182
2001, $11
Prepayments 308 74
Energy Trading Contracts 462 419
Restricted Cash 13 12
Assets held for Sale 23 422
Notes Receivable 164 --
Other 32 25
Current Assets of Discontinued Operations 422 543
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Total Current Assets 3,226 3,594
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PROPERTY, PLANT AND EQUIPMENT
Generation 5,293 4,690
Transmission and Distribution 9,529 9,500
Other 451 457
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Total 15,273 14,647
Accumulated Depreciation and Amortization (4,984) (4,787)
-------------------- ------------------
Net Property, Plant and Equipment 10,289 9,860
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NONCURRENT ASSETS
Regulatory Assets 5,094 5,247
Long-Term Investments, net of accumulated amortization and
Valuation allowances-- 2002, $19; 2001, $30 4,845 4,764
Nuclear Decommissioning Fund 830 817
Other Special Funds 288 222
Goodwill 468 569
Energy Trading Contracts 47 46
Other 259 311
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Total Noncurrent Assets 11,831 11,976
-------------------- ------------------
TOTAL ASSETS $ 25,346 $ 25,430
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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)
June 30, December 31,
2002 2001
-------------------- ------------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,387 $ 1,185
Commercial Paper and Loans 1,687 1,338
Accounts Payable 536 691
Energy Trading Contracts 418 554
Accrued Taxes 124 243
Other 602 535
Current Liabilities of Discontinued Operations 280 261
-------------------- ------------------
Total Current Liabilities 5,034 4,807
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NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 3,045 3,205
Nuclear Decommissioning 830 817
OPEB Costs 497 476
Regulatory Liabilities 409 373
Cost of Removal 144 146
Environmental 140 140
Energy Trading Contracts 64 54
Other 386 323
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Total Noncurrent Liabilities 5,515 5,534
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COMMITMENTS AND CONTINGENT LIABILITIES -- --
-------------------- ------------------
CAPITALIZATION
Long-Term Debt 6,625 6,437
Securitization Debt 2,293 2,351
Project Level, Non-Recourse Debt 1,423 1,404
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Total Long-Term Debt 10,341 10,192
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SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption 80 80
Guaranteed Preferred Beneficial Interest in Subordinated Debentures 680 680
-------------------- ------------------
Total Subsidiaries' Preferred Securities 760 760
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COMMON STOCKHOLDERS' EQUITY
Common Stock, issued: 2002-232,753,521 shares, 2001- 231,957,608 3,633 3,599
shares
Treasury Stock, at cost: 2002 and 2001-- 26,118,590 shares (981) (981)
Retained Earnings 1,384 1,809
Accumulated Other Comprehensive Loss (340) (290)
-------------------- ------------------
Total Common Stockholders' Equity 3,696 4,137
-------------------- ------------------
Total Capitalization 14,797 15,089
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TOTAL LIABILITIES AND CAPITALIZATION $ 25,346 $ 25,430
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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 Six Months Ended June 30,
-------------------------------------
2002 2001
--------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income $ (204) $ 404
Adjustments to reconcile net (loss) income to net cash flows from
operating activities:
Write-down of Project Investments 506 --
Loss on Disposal of Discontinued Operations, net of tax 34 --
Cumulative Effect of a Change in Accounting Principle, net of tax 120 (9)
Depreciation and Amortization 271 227
Amortization of Nuclear Fuel 45 52
Amortization of Deferred Gas Costs 17 --
Provision for Deferred Income Taxes and ITC -- net (188) 27
Investment Distributions 4 91
Unrealized Losses (Gains) on Investments 38 (36)
Unrealized Gains on Energy Trading Contracts (35) (14)
Undistributed Earnings from Affiliates (17) (46)
Leasing Activities 48 35
Foreign Currency Transaction Loss 69 --
Proceeds from Withdrawal of Partnership Interests -- 50
Net Changes in Certain Current Assets and Liabilities:
Restricted Cash 1 (62)
Accounts Receivable and Unbilled Revenues (116) 107
Inventory-Fuel and Materials and Supplies 124 (1)
Prepayments (220) (251)
Accounts Payable 161 (32)
Accrued Taxes (137) 26
Other Current Assets and Liabilities 97 247
Overrecovery of Electric Energy Costs and Market Transition Charge (MTC) 93 13
Underrecovery of Gas Costs (92) (111)
Other 107 54
--------------- --------------
Net Cash Provided By Operating Activities 726 771
--------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment (888) (1,012)
Additions to Long-Term Investments (94) (640)
Contributions to Special Funds (123) (68)
Other (130) (174)
---------------- ---------------
Net Cash Used in Investing Activities (1,235) (1,894)
---------------- ---------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 227 (1,827)
Issuance of Long-Term Debt 874 4,951
Issuance of Common Stock 34 --
Deferred Issuance Costs -- (201)
Redemption of Long-Term Debt (326) (802)
Redemption of Preferred Securities -- (448)
Cash Dividends Paid on Common Stock (223) (225)
Other 2 (2)
---------------- ---------------
Net Cash Provided By Financing Activities 588 1,446
---------------- ---------------
Net Change in Cash and Cash Equivalents 79 323
Cash and Cash Equivalents at Beginning of Period 167 102
---------------- ---------------
Cash and Cash Equivalents at End of Period $ 246 $ 425
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Income Taxes Paid $ 145 $ 263
Interest Paid $ 391 $ 323
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 and its
consolidated subsidiaries. PSEG is 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 herein are adequate to make the
information presented not misleading. These consolidated financial statements
and Notes to Consolidated Financial Statements (Notes) should be read in
conjunction with the Notes contained in our 2001 Annual Report on Form 10-K and
our Amended Quarterly Report on Form 10-Q/A for the quarter ended March 31,
2002. These Notes update and supplement matters discussed in our 2001 Annual
Report on Form 10-K and our Amended Quarterly Report on Form 10-Q/A for the
quarter ended March 31, 2002.
The unaudited financial information furnished reflects all adjustments which
are, in the opinion of management, necessary to fairly state the results for the
interim periods presented. All such adjustments are of a normal recurring
nature. The year-end consolidated balance sheets were derived from the audited
consolidated financial statements included in our 2001 Annual Report on Form
10-K. Certain reclassifications of prior period data have been made to conform
with the current presentation.
Note 2. Accounting Matters
Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and
Other Intangible Assets" (SFAS 142)
SFAS 142 became effective January 1, 2002. Under this standard we were required
to complete an impairment analysis of goodwill during 2002 and record any
required impairment retroactive to the first quarter. 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 results of operations upon adoption. We
have completed this impairment analysis and have recorded after-tax charges of
$120 million, retroactive to the first quarter as required under SFAS 142,
related to the impairment of goodwill at PSEG Global Inc.'s (Global) investments
in Argentina, Brazil and India as well as investments of PSEG Energy
Technologies Inc. (Energy Technologies).
See Goodwill Impairment Analysis in Note 3. Asset Impairments for further
details. In future periods, any goodwill impairments will be recorded as a
component of income from continuing operations.
SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS
144)
On January 1, 2002 we adopted SFAS 144. On adoption, the impact of SFAS 144 did
not have an effect on our financial position or results of operations. Under
SFAS 144, long-lived assets to be disposed of are measured at the lower of
carrying amount or fair value less costs to sell, whether reported in continued
operations or in discontinued operations. Also under SFAS 144, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred. Under SFAS 144, discontinued
operations will be measured at fair value, less costs to sell. Also, as under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" (SFAS 121), a long-lived asset must be tested for
impairment whenever events or changes in circumstances indicate that its
carrying amount may be impaired. For additional information see Note 3. Asset
Impairments and Note 4. Discontinued Operations.
Emerging Issues Task Force (EITF) Issue No. 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities"
In June 2002, the EITF addressed certain issues related to energy trading
activities, including (a) gross versus net presentation in the income statement,
(b) whether the initial fair value of an energy trading contract can be other
than the price at which it was exchanged and (c) additional disclosure
requirements for energy trading activities. The EITF reached a consensus on the
first issue and determined that mark-to-market gains and losses on energy
trading contracts should be shown net in the income statement. This change is
applicable to financial statements for periods ending after July 15, 2002 and
requires that prior periods be restated for comparability. The EITF also reached
a consensus on the third issue regarding disclosures which will be effective for
the first year-end after July 15, 2002. The EITF did not reach a consensus on
the second issue and will address it through a working group.
Pursuant to EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), we have been recording our trading revenues and
trading related costs on a gross basis for physical energy and capacity sales
and purchases. In accordance with EITF 02-3, beginning in the third quarter of
2002, we will report energy trading revenues and energy trading costs on a net
basis and will reclassify prior periods to conform with this net presentation.
The effect of this standard will be to reduce both trading revenues and trading
costs by approximately $715 million and $1,058 million for the six months ended
June 30, 2002 and June 30, 2001, respectively, and approximately $2,256 million
and $2,647 million for the years ended December 31, 2001 and December 31, 2000,
respectively. This change in presentation will have no effect on trading
margins, net income or any component of cash flows.
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143)
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143.
Under SFAS 143, the fair value of a liability for an asset retirement obligation
is required to 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. This standard will have an impact on our nuclear decommissioning liability
and other items. We are still evaluating the potential impact of adopting SFAS
143, which may be material to our financial position and statement of
operations.
Note 3. Asset Impairments
As of December 31, 2001, Energy Holdings' aggregate investment exposure in
Argentina was $632 million, including certain loss contingencies. These
investments included a 90% owned distribution company, Empresa Distribuidora de
Electricidad de Entre Rios S.A. (EDEERSA); and 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
(CTSN) and Parana which are under contract for sale to certain subsidiaries of
The AES Corporation (AES). The combination of the year-to-date operating losses,
goodwill impairment at EDEERSA, write-down of $506 million for all Argentine
assets, and certain loss contingencies resulted in a pre-tax charge to earnings
of $632 million ($410 million after-tax) for the six months ended June 30, 2002.
In connection with or write-down of our Argentine assets, we recorded a deferred
tax asset of approximately $220 million. We believe that we will have sufficient
future capital gains to realize this deferred tax asset. For a discussion of
certain contingencies related to our Argentine investments, see Note 6.
Commitments and Contingent Liabilities.
The tables below provide our share of pre-tax and after-tax impacts of the
various impairment charges, results of operations and accruals of contingencies
recorded with respect to our investments in Argentina for the quarter and six
months ended June 30, 2002 and June 30, 2001.
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ -----------------------
2002 2001 2002 2001
---------------------------------------------------
(millions of dollars)
---------------------------------------------------
(pre-tax) (pre-tax)
(Losses) Earnings before local taxes-EDEERSA............... $ (14) $ 2 $ (59) $ 5
Write-down of EDEERSA....................................... (94) -- (94) --
Write-down of assets held for sale to AES................... (412) -- (412) --
Loss Contingencies and other................................ (8) -- (11) --
Goodwill Impairment-EDEERSA................................. -- -- (56) --
--------- ---------- ---------- ---------
Total $ (528) $ 2 $ (632) $ 5
--------- ---------- ---------- ---------
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ -----------------------
2002 2001 2002 2001
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(millions of dollars)
---------------------------------------------------
(after-tax) (after-tax)
(Losses) Earnings -EDEERSA.................................. $ (9) $ 1 $ (40) $ 3
Write-down of EDEERSA....................................... (61) -- (61) --
Write-down of assets held for sale to AES................... (268) -- (268) --
Loss Contingencies and other................................ (5) -- (5) --
Goodwill Impairment-EDEERSA................................. -- -- (36) --
--------- ---------- ---------- ---------
Total $ (343) $ 1 $ (410) $ 3
--------- ---------- ---------- ---------
EDEERSA
Given the year-to-date and projected operating losses at EDEERSA and the
continued economic uncertainty in Argentina, we determined that it was necessary
to test these assets for impairment. As a result of this analysis, we determined
that these assets are completely impaired under SFAS 144. We recorded total
charges and losses of $213 million, pre-tax, related to this investment for the
six months ended June 30, 2002. These pre-tax charges consisted of goodwill
impairment charges of $56 million, six month operating losses of $59 million, of
which $45 million was recorded in the first quarter, and writing off the
remaining $94 million net asset balance pursuant to our SFAS 144 impairment
analysis and loss contingencies and other items of approximately $4 million.
The total after-tax charges and losses related to this investment were $139
million, for the six months ended June 30, 2002.
In addition, we have developed an exit strategy to dispose of our equity
interest in EDEERSA. This exit is expected to be complete by June 30, 2003, and
we intend to operate EDEERSA while carrying out our exit plans. However, due to
uncertainties related to the timing and method of disposal of our investment in
EDEERSA, the impairment charges and results of EDEERSA's operations will not be
reported as a discontinued operation until EDEERSA has been disposed of or a
sale is probable. During the second quarter, EDEERSA defaulted on its debt,
which is nonrecourse to Global, Energy Holdings and us.
As of January 1, 2002, goodwill related to our investment in EDEERSA was
approximately $56 million and was included in our previously disclosed
investment exposure. As part of the adoption of SFAS 142, we have determined
that this goodwill was impaired and all of the goodwill has been written-down as
a cumulative effect of a change in accounting principle as of January 1, 2002
and is reflected in our Consolidated Statement of Operations for the six months
ended June 30, 2002. See below, Goodwill Impairment Analysis, for a further
discussion of our goodwill analysis.
Our share of the (Loss) Earnings for EDEERSA were included in our Consolidated
Statement of Operations as indicated in the following table:
Quarter Ended Six Months Ended
June 30, June 30,
-------------------------- -------------------------
2002 2001* 2002 2001*
----------- ----------- ---------- ----------
Operating Revenues.......................................... $ 5 $ 2 $ 19 $ 5
Operating Expenses.......................................... 4 -- 14 --
----------- ----------- ---------- ----------
Operating Income............................................ 1 2 5 5
Other Losses - Foreign Currency Transaction Loss............
(15) -- (68) --
Minority Interest and Other................................. -- -- 4 --
----------- ----------- ---------- ----------
(Loss) Earnings before Taxes................................ (14) 2 (59) 5
* Operating results for EDEERSA were recorded in accordance with the equity
method of accounting for the quarter and six months ended June 30, 2001.
Stock Purchase Agreement
On August 24, 2001, Global entered into a Stock Purchase Agreement with AES to
sell its minority interests in EDEN, EDES, EDELAP, CTSN and Parana, to certain
subsidiaries of AES. 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 disagreed that a Political Risk Event as defined in the Stock
Purchase Agreement, which is limited to expropriation of assets, had occurred
and has so notified AES. Global's position is that the risk of a change to
currency policy and the related events in Argentina were acknowledged by the
parties and reflected in the purchase price. Global maintains that the
"Political Risk Event" contemplated as a basis for termination was narrowly
defined and limited to expropriation. There has been no expropriation to date.
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 is pursuing.
A motion is pending before the court seeking an expedited trial of Global's
claim for specific performance. We cannot predict the ultimate outcome of this
matter.
Since AES is disputing its obligation to close and we cannot predict the
outcome of the litigation, we determined it was necessary to test these assets
for impairment. As a result of this analysis, it was determined that these
assets are fully impaired and we recorded a write-down in the amount of $412
million (pre-tax) and $268 million (after-tax)and loss contingencies and other
items of approximately $7 million (pre-tax) and $3 million (after-tax) for the
three and six months ended June 30, 2002. In connection with the terms of the
Stock Purchase Agreement, Global has accrued interest and other receivables of
$17 million through February 6, 2002, which are direct obligations of AES and
represent the total remaining exposure associated with these investments on our
Consolidated Balance Sheets.
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 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 of January 1, 2002 as a component of the
cumulative effect of a change in accounting principle and is reflected in
Consolidated Statement of Operations for the six months ended June 30, 2002. The
$53 million of goodwill at Energy Technologies and the $27 million of goodwill
at Tanir Bavi as of December 31, 2001 has been reclassified into Current
Assets-Discontinued Operations on our Consolidated Balance Sheets. For further
detail regarding the goodwill impairments at Energy Technologies and Tanir Bavi,
see Note 4. Discontinued Operations.
As of June 30, 2002 and December 31, 2001, our goodwill and pro-rata share of
goodwill in equity method investees was as follows:
As of
June 30, 2002 December 31, 2001
-------------- -----------------
Global (Millions of Dollars)
Sociedad Austral de Electricidad S.A. (SAESA)........... $ 315 $ 315
EDEERSA(1).............................................. -- 63
Empresa de Electricidad de los Andes S.A.(2)............ 126 164
Elektrociepownia Chorzow Sp. Z o.o. (ELCHO)............. 6 6
-------------- -----------------
Total Global...................................... 447 548
Power - Generation......................................... 21 21
-------------- -----------------
Total Consolidated Goodwill.................. 468 569
-------------- -----------------
Global
RGE (3)................................................. 75 142
Chilquinta (4).......................................... 166 174
Luz del Sur............................................. 34 34
Kalaeloa................................................ 25 25
-------------- -----------------
Pro-Rata Share of Equity Investment Goodwill.......... 300 375
-------------- -----------------
Total Goodwill.................................... $768 $944
============== =================
(1) The decrease relates to an impairment of $56 million under SFAS 142, and $7
million of purchase price adjustments made subsequent to December 31, 2001.
(2) The decrease relates to purchase price adjustments made subsequent to
December 31, 2001 which resulted in higher value allocated to Property,
Plant and Equipment.
(3) The decrease relates to an impairment of $50 million under SFAS 142 and the
remaining decrease relates to the devaluation of the Brazilian Real.
(4) The decrease relates to the devaluation of the Chilean Peso.
Note 4. Discontinued Operations
Energy Technologies' Investments
Energy Technologies is comprised of 11 heating, ventilating and air conditioning
(HVAC) operating companies and an asset management group which includes various
Demand Side Management (DSM) investments. DSM investments in long-term contracts
represent expenditures made by Energy Technologies to share DSM customers' costs
associated with the installation of energy efficient equipment. DSM revenues are
earned principally from monthly payments received from utilities, which
represent shared electricity savings from the installation of the energy
efficient equipment.
During the second quarter of 2002, we completed our impairment testing of all
recorded goodwill in accordance with guidance set forth in SFAS 142 including
the goodwill associated with the 11 HVAC operating companies acquired by Energy
Technologies. Such analysis indicated that the entire $53 million of goodwill
associated with the HVAC companies was impaired, which resulted in a $32 million
(after-tax) charge. In accordance with SFAS 142, this charge was recorded as of
January 1, 2002 as a cumulative effect of a change in accounting principle,
reflected in our results of operations for the six months ended June 30, 2002.
In June 2002, we adopted a plan to sell our interests in the HVAC operating
companies. The sale of the HVAC operating companies is expected to be completed
by December 31, 2002. We have retained the services of an investment-banking
firm which is marketing the HVAC operating companies to interested parties and
has completed an analysis of the fair market value of the operating companies.
The fair value was lower than our carrying value of these companies, resulting
in an impairment loss recognized for the quarter and six months ended June 30,
2002 (as noted below). Additionally, we have initiated a process for the sale of
Energy Technologies' asset management group, which we expect to sell by June 30,
2003. Based on our assessments, we believe the fair market value of these assets
approximates their carrying value as of June 30, 2002. The HVAC operating
companies and the asset management group meet the criteria for classification as
components of discontinued operations and all prior periods have been
reclassified to conform to the current year's presentation.
In addition to the goodwill impairment, we have further reduced the carrying
value of the investments in the 11 HVAC operating companies to their fair value
less costs to sell, and incurred a loss on disposal for the quarter and six
months ended June 30, 2002 of $20 million (after-tax). Our remaining investment
position in Energy Technologies is approximately $135 million, of which
approximately $35 million relates to deferred tax assets, for which no valuation
allowance is deemed necessary. Excluding the deferred tax assets, approximately
70% of our remaining investment balance relates to the asset management group
and 30% relates to the HVAC companies. Although we believe that we will be able
to sell the HVAC and asset management businesses, we can give no assurances that
we will be able to realize their total carrying values.
Operating results of Energy Technologies, less certain allocated costs from
Energy Holdings, have been reclassified into discontinued operations in our
Consolidated Statements of Operations. The operating results of these
discontinued operations for the quarter and six months ended June 30, 2002,
yielded additional losses of $5 million (after-tax) and $8 million (after-tax),
respectively, and are disclosed below:
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ -------------------------
2002 2001 2002 2001
----------- ---------- ---------- -----------
(Millions of Dollars) (Millions of Dollars)
Operating Revenues.......................................... $ 97 $ 111 $ 198 $ 213
Operating Loss.............................................. (6) (13) (10) (17)
Loss Before Income Taxes.................................... (7) (13) (11) (18)
The carrying amounts of the assets and liabilities of Energy Technologies'
investments, as of June 30, 2002 and December 31, 2001, have been reclassified
into Current Assets of Discontinued Operations and Current Liabilities of
Discontinued Operations, respectively, in our Consolidated Balance Sheets. The
carrying amounts of the major classes of assets and liabilities of Energy
Technologies, to be discontinued as of June 30, 2002 and December 31, 2001, are
included in our Consolidated Balance Sheets and are summarized in the following
tables:
June 30, December 31,
2002 2001
------------ --------------
(Millions of Dollars)
Current Assets.............................................. $ 118 $ 158
Net Property, Plant and Equipment........................... 17 14
Investments................................................. 47 54
Other Assets................................................ 10 64
------------ --------------
Total Assets of Discontinued Operations............... $ 192 $ 290
============ ==============
Current Liabilities......................................... $ 83 $ 82
Noncurrent Liabilities...................................... 3 6
Long-Term Debt.............................................. 6 1
------------ --------------
Total Liabilities of Discontinued Operations.......... $ 92 $ 89
============ ==============
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 in India. The plant commenced combined-cycle commercial operation in
2001. Power from the plant is being sold under a seven-year fixed price Power
Purchase Agreement (PPA) with the Karnataka Power Transmission Company Limited
(KPTCL), a state affiliated entity, formerly known as Karnataka Electricity
Board.
During the second quarter of 2002, 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. Such analysis
indicated that the entire $27 million of goodwill recorded in connection with
our investment in Tanir Bavi was impaired and resulted in an $18 million
(after-tax) charge. In accordance with SFAS 142, this charge was recorded as of
January 1, 2002 as a component of the cumulative effect of a change in
accounting principle, reflected in our results of operations for the six months
ended June 30, 2002. For additional information see Note 2. Accounting Matters
and Note 3. Asset Impairments.
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 $0.04 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. The dispute resolution process and certain other legal
remedies could take an extended period of time before a result is known. While
pursuing legal recourse, it is likely we would need to make additional equity
contributions in the plants to maintain liquidity. We believe the delays in the
process have greatly diminished our expectations of a satisfactory resolution
and in June 2002, we adopted a plan to exit Tanir Bavi.
Global and its partner in this venture, GMR Vasavi Group, a local Indian
company, are in negotiations for the sale of Global's majority interest in Tanir
Bavi to the GMR Vasavi Group. The final negotiations and completion of sale are
expected to occur in the third quarter of 2002. Should this sale not be
consummated, we will seek another buyer for this facility. In such an event, we
can give no assurances that we will be able to realize our adjusted carrying
value. Tanir Bavi meets the criteria for classification as a component of
discontinued operations and all prior periods have been reclassified to conform
to the current year's presentation. We have reduced the carrying value of Tanir
Bavi to its fair value less costs to sell and incurred a loss on disposal for
the quarter and six months ended June 30, 2002 of $14 million (after-tax). The
operating results of Tanir Bavi for the quarter and six months ended June 30,
2002 yielded income of $2 million (after-tax) and $5 million (after-tax),
respectively. The respective income from discontinued operations partially
offsets the loss on disposal.
Operating results of this discontinued operation are summarized in the following
table:
Quarter Ended Six Months Ended
June 30, June 30,
-------------------------- -----------------------
2002 2001* 2002 2001*
---------- ----------- ---------- ----------
(Millions of Dollars)
Operating Revenues.......................................... $ 32 $ 1 $ 61 $ 1
Operating Income............................................ 11 1 23 1
Income Before Income Taxes.................................. 3 1 9 1
* Operating results for Tanir Bavi were recorded in accordance with the
equity method of accounting for the quarter ended and six months ended June
30, 2001.
The carrying amounts of the assets and liabilities of Tanir Bavi, as of June 30,
2002 and December 31, 2001, have been reclassified into Current Assets of
Discontinued Operations and Current Liabilities of Discontinued Operations,
respectively, in our Consolidated Balance Sheets. The carrying amounts of the
major classes of assets and liabilities of Tanir Bavi, to be discontinued as of
June 30, 2002 and December 31, 2001, are summarized in the following tables:
June 30, December 31,
2002 2001
--------------------------------------
(Millions of Dollars)
Current Assets................................................................. 32 36
Net Property, Plant and Equipment.............................................. 183 190
Goodwill....................................................................... -- 27
Other Assets................................................................... 15 --
-------------- ---------------------
Total Assets of Discontinued Operations................................. $ 230 $ 253
============== =====================
Current Liabilities............................................................ 52 45
Non Current Liabilities........................................................ 19 19
Long-Term Debt................................................................. 117 108
-------------- ---------------------
Total Liabilities of Discontinued Operations......................... $ 188 $ 172
============== =====================
Note 5. Regulatory Assets and Liabilities
PSE&G prepares its financial statements in accordance with the provisions of
SFAS 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 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. These costs are
deferred based on rate orders issued by the New Jersey Board of Public Utilities
(BPU) or the Federal Energy Regulatory Commission (FERC) and our recovery
experience with prior rate cases. As of June 30, 2002, approximately 87% of our
regulatory assets were deferred based on written rate orders. Regulatory assets
recorded on a basis other than by an issued rate order have less certainty of
recovery since they can be disallowed in the future by regulatory authorities.
However, we have experienced no material disallowances in the past. We believe
that all of our regulatory assets are probable of recovery.
At June 30, 2002 and December 31, 2001, respectively, we had deferred the
following regulatory assets and liabilities on the Consolidated Balance Sheets:
June 30, December 31,
2002 2001
-------------- -----------------
(Millions of Dollars)
Regulatory Assets
- -----------------
Stranded Costs to be Recovered.............................. $ 4,009 $ 4,105
SFAS 109 Income Taxes....................................... 313 302
OPEB Costs.................................................. 203 212
Societal Benefits Charges (SBC)............................. -- 4
Manufactured Gas Plant Remediation Costs.................... 87 87
Unamortized Loss on Reacquired Debt and Debt Expense........ 88 92
Underrecovered Gas Costs.................................... 195 120
Unrealized Losses on Gas Contracts.......................... -- 137
Other....................................................... 199 188
-------------- -------------------
Total Regulatory Assets................................. $ 5,094 $ 5,247
============== ===================
Regulatory Liabilities
- ----------------------
Excess Depreciation Reserve................................. $ 245 $ 319
Non-Utility Generation Transition Charge (NTC).............. 125 48
SBC......................................................... 28 --
Other....................................................... 11 6
-------------- -------------------
Total Regulatory Liabilities............................ $ 409 $ 373
============== ===================
All regulatory assets and liabilities are excluded from our rate base unless
otherwise noted in the descriptions below.
Stranded Costs To Be Recovered: This reflects the deferred costs to be
recovered by the securitization transition charge, which was authorized by the
BPU's Final Order and Finance Order in PSE&G's deregulation proceedings. These
orders are a matter of public record and are available at the BPU. These costs
primarily relate to the write-down of our fixed assets in 1999 that was required
under SFAS 121. PSE&G Transition Funding LLC, a wholly-owned subsidiary of
PSE&G, issued transition bonds to recover these costs net of deferred taxes.
Accordingly, this regulatory asset is offset by securitization debt and a
deferred tax liability. Funds collected through the securitization transition
charge will be used to make the future interest and principal payments on the
transition bonds. This amount will be recovered over the life of the transition
bonds, which is expected to conclude in December 2015.
SFAS 109 Income Taxes: This amount represents the portion of deferred income
taxes that will be recovered through future rates, based upon established
regulatory practices, which permit the recovery of current taxes. Accordingly,
this regulatory asset is offset by a deferred tax liability and is expected to
be recovered without interest over the period the underlying book-tax timing
differences reverse and become current taxes.
OPEB Costs: Includes costs associated with adoption of SFAS No. 106, "Employers'
Accounting for Benefits Other Than Pensions" (SFAS 106) which were deferred in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated
Enterprises" (EITF 92-12). Prior to the adoption of SFAS 106, post-retirement
benefits costs were recognized on a cash basis. SFAS 106 required that these
costs be accrued as the benefits were earned. Accordingly, a liability and a
regulatory asset were recorded for the total benefits earned at the
implementation date. Beginning January 1, 1998, we began to recover this
regulatory asset over 15 years without interest.
SBC: The SBC includes costs related to our electric and gas distribution
business as follows: 1) social programs which include the universal service
fund; 2) nuclear plant decommissioning; 3) DSM programs; 4) manufactured gas
plant remediation expenditures; 5) consumer education; 6) Under and
overrecovered electric bad debt expenses; and 7) MTC overrecovery. These costs
are recovered/refunded with interest. The SBC clause will be revised at the end
of the transition period on August 1, 2003.
Manufactured Gas Plant Remediation Costs: Represents estimated future
environmental investigation and remediation expenditures (net of insurance
recoveries), which are probable of recovery in future rates through the SBC.
This amount will be transferred to the SBC regulatory asset when the actual
expenditures are made. Interest is not recoverable on these costs until the
actual expenditures are made. This regulatory asset is offset by a noncurrent
liability on the balance sheet.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance
costs, premiums, discounts and losses on reacquired long-term debt. These costs
are amortized with interest, over the remaining life of the reacquired debt or
over the life of the new debt, if refinanced.
Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess of or
below the amount included in rates and probable of recovery in the future.
Generally, underrecovered gas costs do not accrue interest while overrecovered
gas costs do accrue interest. The LGAC rate is normally adjusted on an annual
basis. A portion of the current underrecovery, $117 million at June 30, 2002, is
being recovered over an extended period through September 2004. We are
recovering interest during this extended period. The remaining portion of the
current underrecovery, $78 million, is expected to be recovered subsequent to
our next gas rate proceeding, the time of which is not currently known.
Unrealized Losses on Gas Contracts: This represents the recoverable portion of
unrealized losses associated with contracts used in PSE&G's gas distribution
business. This asset is offset by the net energy contracts payable on the
balance sheet. Subsequent to the gas contract transfer to Power in May 2002,
PSE&G no longer enters into these contracts.
Other Regulatory Assets: Includes Decontamination and Decommissioning Costs
which are offset by a noncurrent liability on the balance sheet and are expected
to be collected without interest until December 2007; Plant and Regulatory Study
Costs are expected to be recovered without interest until December 2021; Repair
Allowance Tax Deficiencies and Interest; Oil and Gas Property Write-Down which
is expected to be recovered without interest until December 2002; restructuring
costs that will be recovered with or without interest, which will be determined
at our upcoming electric rate case, from August 1, 2003 through July 31, 2007
and recovery of costs related to Transition Funding's interest rate swap that
will be recovered without interest over the life of Transition Funding's
transition bonds, which is expected to conclude in December 2015. This asset is
offset by a derivative liability on the balance sheet.
Excess Depreciation Reserve: As required by a BPU rate order, we reduced our
depreciation reserve for our 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.
NTC: This clause was established to account for above market costs related to
non-utility generation (NUG) contracts. NUG contract costs are charged to
expense and proceeds from the sale of the energy and capacity purchased under
these NUG contracts are also credited to expense. The difference between the
collection of NTC revenue and the related expense is deferred. Costs or benefits
associated with the restructuring of these contracts are deferred as well. These
amounts are expected to be returned to customers with interest. The NTC balance,
including the anticipated deferral of the difference between the Basic
Generation Service (BGS) payments to suppliers and collections from customers,
are expected to be addressed together with the electric distribution base rate
case and collectively incorporated into rates on August 1, 2003.
Other Regulatory Liabilities: This includes the following: 1) Interest on
amounts collected from customers that are used to fund incentives for choosing a
third party gas supplier; 2) Interest on amounts collected from customers
resulting from the Energy Tax Reform Act and are currently being used to fund
customer education discounts approved by the BPU; 3) Amounts collected from
customers in order for Transition Funding to obtain a AAA rating on its
transition bonds; and 4) Amounts that will be returned to Firm Gas customers.
Note 6. Commitments and Contingent Liabilities
Guaranteed Obligations
Power
Power has guaranteed certain energy trading contracts of PSEG Energy Resources &
Trade LLC (ER&T), its subsidiary. Power has entered into guarantees having a
maximum liability of $876 million and $506 million as of June 30, 2002 and
December 31, 2001, respectively. The amount of Power's exposure under these
guarantees was $169 million and $153 million, as of June 30, 2002 and December
31, 2001, respectively.
As of June 30, 2002, Power had issued letters of credit in the amount of
approximately $89 million. These letters of credit are in support of its trading
business and various contractual obligations.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of Global's
affiliates, including the successful completion, performance or other
obligations related to certain of the projects in an aggregate amount of
approximately $190 million as of June 30, 2002. The guarantees consist of a $61
million equity commitment for ELCHO in Poland, $56 million of various guarantees
for Dhofar Power Company in Oman, a $25 million guarantee for Chilquinta
Energia, S.A. (Chilquinta) in Chile and Peru, and various other guarantees
comprising the remaining $48 million. A substantial portion of such guarantees
is cancelled upon successful completion, performance and/or refinancing of
construction debt with non-recourse project debt.
In the normal course of business, Energy Technologies secures construction
obligations with performance bonds issued by insurance companies. In the event
that Energy Technologies' tangible equity falls below $100 million, we would be
required to provide additional support for the performance bonds. Tangible
equity is defined as net equity less goodwill. As of June 30, 2002, Energy
Technologies' tangible equity was $106 million. Energy Holdings is in the
process of negotiating alternate support arrangements with bond issuers,
including an indemnification agreement, which is likely to be executed in the
near future. As of June 30, 2002, Energy Technologies had $206 million of such
bonds outstanding, of which $71 million was at risk in ongoing construction
projects. Energy Holdings expects to reduce this amount over time as part of its
exit from this business. The performance bonds are not included in the $190
million of guaranteed obligations, discussed above. No assurances can be given
that Energy Holdings will be successful in extinguishing these obligations.
Default on non-recourse project financing does not cross default to any other
credit agreements of Energy Holdings. In cases where Energy Holdings or Global
have guaranteed obligations, default under the project finance agreements may be
accelerated if the project is in default. In June 2002, the Administration Agent
for the EDELAP project loan notified Global that the loan was in default and
Global paid $2 million in sponsor guarantees that were due. This amount was
included in the $632 million of Argentine investment exposure that was impaired
(see Note 3. Asset Impairments).
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 the
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 June 30, 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 United States Environmental Protection Agency (EPA) has determined that a
six mile stretch of the Passaic River in the area of Newark, New Jersey is a
"facility" within the meaning of that term under the Federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980 and that, to
date, at least thirteen corporations, including us, may be potentially liable
for performing required remedial actions to address potential environmental
pollution in the Passaic River "facility." In a separate matter, we and certain
of our predecessors conducted industrial operations at properties on that six
mile stretch of the Passaic River. The operations include one operating electric
generating station, one former generating station, and four former MGPs. Our
costs to clean up former MGPs are recoverable from utility customers under the
SBC. We have contracted to sell the site of the former generating site,
contingent upon approval by state regulatory agencies, to a third party that
would release and indemnify us for claims arising out of the site. We cannot
predict what action, if any, the EPA or any third party may take against us with
respect to this matter, or in such event, what costs we may incur to address any
such claims. However, such costs may be material.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In a response to a request dated March 31, 2000 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 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 agreed to install advanced
air pollution controls over 12 years that are expected to significantly reduce
emissions of nitrogen oxides (NOx), sulfur dioxide (SO2) particulate matter and
mercury from the Hudson and Mercer units. The agreement includes a carbon
dioxide (CO2) emissions reduction goal for PSEG Fossil's New Jersey units. This
single year CO2 reduction goal will be achieved mainly through repowering
projects. The estimated cost of the program is $355 million and such costs, when
incurred, will be capitalized as plant additions. We also agreed to pay a $1.4
million civil penalty, $6 million on supplemental environmental projects and up
to $1.5 million if reductions in CO2 levels are not achieved.
The EPA had also asserted that PSD requirements are applicable to Bergen 2, such
that we were required to have obtained a permit before beginning actual on-site
construction. We disputed that PSD/NSR requirements were applicable to Bergen 2.
As a result of the agreement resolving the NSR allegations concerning Hudson and
Mercer, the NJDEP issued an air permit for Bergen 2. Bergen 2 began operations
in June 2002.
Power
New Generation and Development
Power is developing the Bethlehem Energy Center, a 763 MW combined-cycle power
plant that will replace the 380 MW Albany (NY) Steam Station. Total costs for
this project will be approximately $465 million with expenditures to date of
approximately $79 million. Construction began in June 2002 with the expected
completion in 2004, at which time the existing station will be retired.
Power has completed construction of a 546 MW natural gas-fired, combined cycle
electric generation plant at Bergen Generation Station, at a cost of
approximately $342 million. The plant began commercial operation in June 2002.
Power is also constructing a 1,218 MW combined cycle generation plant in Linden,
New Jersey. Costs are estimated to be approximately $700 million with
expenditures to date of approximately $432 million. Completion is expected in
2003 at which time 451 MW of existing 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
(821 MW) and Lawrenceburg, Indiana (1,096 MW) at an aggregate total cost of $1.2
billion. Total expenditures to date on these projects have been approximately $1
billion. The required estimated equity investment in these projects is
approximately $400 million, with the remainder being financed with non-recourse
debt. As of June 30, 2002, approximately $212 million of equity has been
invested in these projects. In connection with these projects, ER&T has entered
into a five-year tolling agreement pursuant to which it is obligated to purchase
the output of these facilities at stated prices. Based on current prices, this
contract is currently above market. The agreement 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. Due to existing market
conditions, the Waterford project did 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 entered into an agreement to purchase Wisvest-Connecticut LLC,
which holds two electric generating stations in Connecticut, at a cost of $220
million. The agreement also calls for purchase price adjustments of up to $20
million for various expenditures made prior to closing as well as closing
adjustments for fuel and inventory. The coal-, oil- and gas-fired plants have a
total capacity of 1,019 MW. The transaction is subject to various Federal
approvals. The transfer of the two stations triggered the Connecticut Transfer
Act, which requires the commencement of any necessary remedial activities within
three years of the transfer of the property. While the cost to comply with the
Transfer Act to clean up former petroleum coke operations at the two stations is
still unknown, estimated costs are between $10 million and $20 million. No
assurances can be given as to the ultimate remediation costs at these
facilities; however, they could be material. Power expects to close on this
acquisition in the fourth quarter of 2002.
Power also has contracts with outside parties to provide upgraded turbines
for the Salem Units 1 and 2 and upgraded turbines and a power uprate for Hope
Creek to increase our generating capacity. The projects are subject to
regulatory approvals and are currently scheduled to be completed by 2004 for
Salem Unit 1 and Hope Creek and 2006 for Salem Unit 2. Power's aggregate
estimated costs for these projects are $210 million.
Power has commitments to purchase gas turbines and/or other services, to meet
its current plans to develop additional generating capacity. The aggregate
amount due under these commitments is approximately $480 million, approximately
$370 million of which is included in estimated costs for the projects discussed
above. The approximate $110 million remaining relates to obligations to purchase
hardware and services that have not been designated to any specific projects. If
Power does not contract to satisfy its commitment relating to the $110 million
in obligations by July 2003, it would be subject to penalties of up to $22
million.
Energy Holdings
Argentine Economic Crisis
Global has certain contingent obligations that are likely to occur if certain
projects in Argentina continue to default on their debt and performance
obligations. The estimated amount to cover this exposure is $7 million and has
been recorded as a component of general and administrative operating expenses.
For EDELAP, Global has a standby equity agreement to contribute equity in
support of unpaid interest and US tax liabilities to its borrower subsidiary.
Global's obligation and reimbursement of payments made on its behalf could
amount to $2 million related to this project loan. Global's Chilean distribution
company, SAESA, has guaranteed performance obligations of its subsidiary which
operates in Argentina in the amount of approximately $4 million. Finally,
Global's contingency includes $1 million of likely costs related to defense of
anticipated legal actions which may be taken against PSEG companies or directors
and officers of its Argentine operations.
Under certain circumstances, Global could be obligated to settle its share
(approximately $26 million) of a project loan for EDELAP should it or the
majority owner of the project, take certain actions including forcing or
permitting certain loan parties to declare bankruptcy. In addition, the
guarantee can be triggered by transferring the shares of certain loan parties
without lender consent. Breach of this transfer covenant can be cured by
delivering certain pledge agreements relating to the ownership of loan parties
to the lenders. Global could also be liable for any incremental direct damages
arising from the breach of these covenants. Given the likely cure of any breach
by the project sponsors, such a contingent obligation has a low probability of
being triggered, and therefore no provision has been made in the Consolidated
Financial Statements.
SAESA has guaranteed its share of a $35 million debt obligation for a 50% owned
affiliate in Argentina, Edersa. This obligation was recorded on our Consolidated
Balance Sheets as it was considered in the valuation of SAESA at the date of
purchase in August 2001. SAESA needs a waiver from lenders in existing financing
agreements to invest the funds to repay the obligation. We believe such waivers
are likely to be secured. In the event SAESA is not able to obtain the required
waiver and could not raise the necessary funds, Global may be required to make a
$35 million equity contribution to SAESA to repay the obligation. Since this
obligation has been previously recorded, there will be no impact to our
Consolidated Statement of Operations if the transaction is funded.
Other
As of June 30, 2002, Energy Holdings had $50 million, or 1%, of its assets
invested in the Turboven generation facilities, located in Venezuela. Recently,
Venezuela has been subject to a loss of capital as the country's debt has been
subject to a credit rating downgrade. In February 2002, the government of
Venezuela abandoned its crawling currency peg and allowed the Venezuelan Bolivar
to float freely with the US Dollar. The Bolivar devalued approximately 45% since
year-end 2001 from 758 Bolivars to 1 US Dollar to 1,386 Bolivars to 1 US Dollar
as of June 30, 2002. The Turboven power purchase contracts are indexed to the US
Dollar as are the fuel supply costs. This implies that, with respect to power
purchase contracts, a devaluation will not impact the level of US Dollar
revenues realized. Our near term income statement exposure relates to our net
monetary position in Bolivars. Since Turboven is a US Dollar functional entity,
any receivables and payables that are not indexed to the US Dollar must be
re-measured to the US Dollar. The impact of the re-measurement is recorded as a
loss or gain to our Consolidated Statements of Operations. The recent
devaluation of the Bolivar did not have a material adverse impact on our
financial position, results of operations or net cash flows.
In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between Global
and Harbinger GWF LLC, entered into a ten 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,
the Hanford, Henrietta and Tracy Peaking Plants. Total project cost is estimated
at approximately $335 million. The Hanford Peaking Plant, a 95 MW facility, was
completed and began operation in August 2001. The Henrietta Peaking Plant, also
a 95 MW facility, was completed and began operation in June 2002, and the Tracy
Peaking Plant, a 160 MW facility, received the permits necessary to allow the
start of construction on July 17, 2002 following significant delays in the
permitting process. This late receipt of the Tracy Peaking Plant's permits does
not allow sufficient time to complete construction before the commercial
operations date deadline of October 31, 2002 under the PPA. On February 28,
2002, GWF Energy asserted a force majeure claim under the provisions of the PPA
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. GWF Energy is in substantive negotiations with the
CDWR over this matter. We and Global are evaluating the appropriate course of
action to protect GWF Energy's 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. In the event financing does not
occur, our investment in this facility could increase to the full amount of the
project costs, noted above. For a description of turbine loans and working
capital loans from Global to GWF Energy pending completion of project financing,
see Note 13. Related-Party Transactions.
On February 25, 2002, the Public Utilities Commission of the State of California
(CPUC) and the State of California Electricity Oversight Board filed complaints
with FERC under Section 206 of the Federal Power Act against certain sellers of
electricity which, pursuant to long-term FERC authorized contracts, provide
power to the CDWR. GWF Energy is a named respondent in these proceedings. The
complaints 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 of California 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 matters and set the
contracts of GWF Energy and certain other respondents, including the ten year
PPA, for hearing. 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 entered into, and continues to engage in,
substantive negotiations with representatives of the State of California, under
oversight of the FERC settlement judge, in an attempt to resolve differences
between the parties. We cannot predict the outcome of this matter or its impact
on our financial position, results of operations and net cash flows.
In January 2002, Global completed negotiations to buy a 35% interest in the 590
MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina),
located in Poland and in June 2002 completed negotiations to increase its
ownership interest to approximately 50%. The transaction includes the obligation
to purchase additional shares in 2003 that will bring Global's aggregate
interest in Skawina to approximately 75%. Skawina supplies electricity to three
local distribution companies and heat mainly to the city of Krakow, under annual
one-year contracts. The sale is part of the Polish Government's energy
privatization program. Global has expended $31 million during 2002 for its
approximate 50% ownership interest and the total equity investment is expected
to be approximately $44 million.
Global owns a 60% interest in Carthage Power Company (CPC), a 471 MW gas-fired
combined-cycle electric generation facility located in Rades, Tunisia. CPC has
entered into a 20-year power purchase contract for the sale of 100% of the
output to Societe Tunisienne de l' Electricite et du Gaz, (STEG). The contract
called for the plant to be operational by November 24, 2001, however, due to
delays in construction, this deadline was not met. STEG is declaring that it is
entitled to liquidated damages at the rate of $67,000 dollars a day since
November 24, 2001 in accordance with the terms of the power purchase contract.
CPC is contesting STEGs claim and the two parties are currently under
negotiation to settle this dispute. The facility was built by Alstom Centrales
Energetiques SA, (Alstom) an independent contractor, who was also obligated to
complete construction by November 24, 2001. CPC believes it is entitled to
reimbursement from Alstom for damages owed to STEG resulting from construction
delays, however, no assurances can be given.
We and our equity method investees are involved in various legal actions arising
in the normal course of business. We do not expect that there will be a material
adverse effect on our financial condition, results of operations and net cash
flows as a result of these proceedings, although no assurances can be given.
Note 7. 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 condition. 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 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.
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or values
of instruments with similar terms, credit ratings, remaining maturities and
redemptions at June 30, 2002 and December 31, 2001, respectively.
June 30, 2002 December 31, 2001
----------------------- -------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ --------- ------------ ----------
(Millions of Dollars)
Long-Term Debt:
PSEG.............................................. $ -- $ -- $ 275 $ 275
Energy Holdings................................... 2,821 2,712 2,773 2,835
PSE&G............................................. 3,173 3,351 3,172 3,290
Transition Funding................................ 2,420 2,536 2,472 2,575
Power............................................. 3,314 3,434 2,685 2,835
Preferred Securities Subject to Mandatory Redemption:
PSE&G Cumulative Preferred Securities............. -- -- -- --
Monthly Guaranteed Preferred Beneficial Interest
in PSE&G's Subordinated Debentures................ 60 61 60 60
Quarterly Guaranteed Preferred Beneficial Interest
in PSE&G's Subordinated Debentures................ 95 96 95 96
Quarterly Guaranteed Preferred Beneficial Interest
in PSEG's Subordinated Debentures................. 525 498 525 520
Energy Trading Contracts
We maintain a strategy of entering into trading positions to optimize the value
of our portfolio of generation assets and supply obligations. We do not engage
in the practice of simultaneous trading for the purpose of increasing trading
volume or revenue. We engage in physical and financial transactions in the
electricity wholesale markets and execute an overall risk management strategy to
mitigate the effects of adverse movements in the fuel and electricity markets.
We actively trade energy and energy-related products, including electricity,
natural gas, electric capacity, fixed transmission rights, coal and emission
allowances, in the spot, forward and futures markets, primarily in PJM, and
electricity in the Super Region, which extends from Maine to the Carolinas and
the Atlantic Coast to Indiana and natural gas in the producing region as well as
the Super Region. These contracts also involve financial transactions including
swaps, options and futures.
Our energy trading contracts are recorded under EITF 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
98-10). This requires energy trading contracts to be marked-to-market with the
resulting realized and unrealized gains and losses included in current earnings.
Our energy trading segment for the quarter and six months ended June 30, 2002
recorded net margins of $18 million and $48 million, respectively, which
includes margins generated by gas contracts as shown below:
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2002 2001 2002 2001
--------------------------------- ---------------------------------
(Millions of Dollars) (Millions of Dollars)
Realized Gains.............................. $16 $27 $17 $74
Unrealized Gains............................ 5 10 35 14
-------------- --------------- -------------- --------------
Gross Margin.............................. 21 37 52 88
-------------- --------------- -------------- --------------
Broker Fees and Other Trading-Related Exp... (3) (1) (4) (3)
-------------- --------------- -------------- --------------
Net Margin ............................... $18 $36 $48 $85
============== =============== ============== ==============
As of June 30, 2002 and December 31, 2001, the fair value of the energy
contracts in our trading segment was $47 million and $10 million, respectively,
described below, substantially all of which relates to contracts having terms of
two years or less and substantially all of which were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to the energy commodities in our energy trading segment are
summarized in the following table:
June 30, 2002 December 31, 2001
----------------------------- --------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
----------------------------- ---------------------------------
(Millions) (Millions)
Futures and Options NYMEX............ 47 10 $1 -- 16 $(1)
Physical forwards.................... 151 -- 10 41 9 (3)
Options -- OTC....................... 2 379 11 8 717 (19)
Swaps................................ -- 1,920 10 -- 1,047 24
Emission Allowances.................. -- -- 15 -- -- 9
----------------------------- ---------------------------------
Totals............................... 200 2,309 $47 49 1,789 $10
============================= =================================
We routinely enter into exchange traded futures and options transactions for
electricity and natural gas as part of our energy trading operations. Generally,
exchange-traded futures contracts require deposit of margin cash, the amount of
which is subject to change based on market movement and in accordance with
exchange rules. The amount of the margin deposits as of June 30, 2002 was
approximately $3 million.
Derivative 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) of New Jersey's regulated distribution utilities for
the one-year period 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 more than 75% of its generation capacity in the
PJM market. On February 15, 2002, the BPU approved the BGS auction results.
Subsequently, a portion of the contracts with those bidders was reassigned to
Power. Therefore, for a limited portion of the New Jersey retail load, Power
will be a direct suppplier.
In order to hedge a portion of our forecasted energy purchases to meet our BGS
requirements, Power entered into forward purchase contracts, futures, options
and swaps. Power has also forecasted the energy delivery from its generating
stations based on the forward price curve movement of energy and, as a result,
entered into swaps, options and futures transactions to hedge the price of gas
to meet its gas purchases requirements for generation. These transactions
qualify for hedge accounting treatment under SFAS 133. As of June 30, 2002, the
fair value of these hedges was $(8.6) million with offsetting charges to Other
Comprehensive Income (OCI) of $5.1 million (after-tax). These hedges will mature
in 2003.
Also, prior to May 2002, PSE&G had entered into gas forwards, futures, options
and swaps to hedge its forecasted requirements for natural gas, which was
required under an agreement with the BPU in 2001. PSE&G accounted for these
transactions in accordance with SFAS 71. Accordingly, these commodity contracts
were 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. All settlements were included in
inventory and passed on to customers as part of the average cost of gas.
Effective with the gas contract transfer on May 1, 2002, Power assumed all of
these derivatives entered into by PSE&G. Power accounts for the derivatives
pertaining to residential customers in a similar manner as PSE&G did. Gains or
losses from these transactions will be recovered from PSE&G's customers.
Derivatives relating to commercial and industrial customers will be accounted
for in accordance with SFAS 133, where appropriate. Gains or losses on these
derivatives will be deferred and reported as a component of OCI. The accumulated
OCI will be reclassified to earnings in the period in which the hedged
transaction affects earnings.
As of June 30, 2002, Power had approximately 303 MMBTU of gas forwards, futures,
options and swaps to hedge forecasted requirements with a fair value of
approximately $(10) million. As of December 31, 2001, PSE&G had approximately
330 MMBTU of gas forwards, futures, options and swaps to hedge forecasted
requirements with a fair value of approximately $(137) million. The maximum term
of these contracts is approximately one year.
Generation
We also enter into certain other contracts for our generation business which are
derivatives but do not qualify for hedge accounting under SFAS 133 nor are
classified as energy trading contracts under EITF 98-10. Most of these contracts
are option contracts on gas purchases for generation requirements. The changes
in fair market value of these derivative contracts are recorded in the income
statement at the end of each reporting period in our generation segment.
For our generation business for the quarter and six months ended June 30, 2002,
we recorded gains and losses on certain derivative contracts of $(6) million and
$26 million, respectively, as shown below:
For the Three Months Ended For the Six Months Ended
June 30, June 30,
--------------------------------- ---------------------------------
2002 2001 2002 2001
--------------------------------- ---------------------------------
(Millions of Dollars) (Millions of Dollars)
Realized (Losses) Gains................ $(5) $-- $8 $--
Unrealized (Losses) Gains.............. (1) (8) 18 (8)
--------------- -------------- -------------- ---------------
Gross Margin......................... $(6) $(8) $26 $(8)
=============== ============== ============== ===============
As of June 30, 2002 and December 31, 2001, the fair value of our energy
contracts in our generation segment was $7 million and $(12) million,
respectively, substantially all of which related to contracts having terms of
two years or less and substantially all of which were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to the energy commodities in our generation segment are
summarized in the following table:
June 30, 2002 December 31, 2001
-------------------------- --------------------------
Notional Fair Notional Fair
(MMBTU) Value (MMBTU) Value
----------- -------- ----------- -----------
(Millions) (Millions)
Futures and Options NYMEX............ 6 $1 -- --
Options-- OTC........................ 103 5 86 $(11)
Swaps................................ -- 1 84 (1)
----------- -------- ----------- -----------
Totals............................... 109 $7 170 $(12)
=========== ======== =========== ===========
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal course of
business. Our policy is to manage interest rate risk through the use of fixed
rate debt, floating rate debt, interest rate swaps, interest rate caps and
interest rate lock agreements. As of June 30, 2002, a hypothetical 10% change in
market interest rates would result in a consolidated change of $17 million in
annual interest costs related to short-term and floating rate debt consisting of
$4 million, $6 million, $3 million and $4 million at PSEG, PSE&G, Power and
Energy Holdings, respectively.
We construct a hypothetical swap to mirror all the critical terms of the
underlying debt and utilize regression analysis to assess the effectiveness of
the actual swap at inception and on an ongoing basis. The assessment will be
done periodically to ensure the swaps continue to be effective. PSEG determines
the fair value of interest rate swaps through counterparty valuations, internal
valuations and the Bloomberg swap valuation function. There have been no
material changes in the techniques or models used in the valuation of interest
rate swaps during the periods presented. There is minimal impact of counterparty
credit risk the fair value of the hedges since our policies require that our
counterparties have investment grade credit ratings.
We have entered into interest rate swaps to lock in fixed interest rates on
certain of our construction loans to hedge forecasted future interest payments.
We have elected to use the Hypothetical Derivative Method to measure
ineffectiveness of the hedges as described under Derivative Implementation Group
(DIG) Issue No. G7. Ineffectiveness may occur if the actual draw down of the
debt and the notional amount of the swap during the construction phase are
different. The amount of ineffectiveness, if any, is recorded in earnings at the
end of the reporting period. The impact of ineffectiveness on net income should
be minimal because the interest rate swaps and the underlying debt are indexed
to the same benchmark interest rate. Therefore, interest rate fluctuations
should be offset.
The following table shows details of the interest rate swaps at PSEG, PSE&G,
Power and Energy Holdings and their associated values that were open at June 30,
2002:
- -----------------------------------------------------------------------------------------------------------------------
Accumulated
Total Fair Other
Project Notional Pay Receive Market Comprehensive Maturity
Underlying Securities Percent Amount Rate Rate Value Loss Date
(A) (B)
- -----------------------------------------------------------------------------------------------------------------------
(Millions of dollars, where applicable)
PSEG:
Enterprise Capital Trust II 100% $150.0 5.98% 3-month $(9.6) $5.7 2008
Securities LIBOR
PSE&G:
Transition Funding Bonds (Class 100% $497.0 6.29% 3-month (32.2) *** 2011
A-4) LIBOR
Power:
Construction Loan - Waterford 100% $177.5 4.16% 3-month (1.7) 1.0 2005
LIBOR
Energy Holdings:
Construction Loan - Tunisia 60% $56.8 6.96% 6-month (5.1) 2.0 2009
(US$) LIBOR
Construction Loan - Tunisia 60% $71.5 5.19% 6-month (1.6) 0.6 2009
(EURO) EURIBOR*
Construction Loan - Poland 55% $127.3 8.40% 6-month (38.1) 13.2 2010
(US$) LIBOR
Construction Loan - Poland 55% $57.1 13.23% 6-month (29.6) 9.7 2010
(PLN) WIBOR**
Construction Loan - Oman 81% $70.3 6.27% 6-month (11.5) 6.1 2018
LIBOR
Construction Loan - Kalaeloa 50% $55.4 6.60% 3-month (2.0) 1.3 2007
LIBOR
Construction Loan - Guadalupe 50% $125.1 6.57% 3-month (4.3) 2.8 2004
LIBOR
Construction Loan - Odessa 50% $136.6 7.39% 3-month (6.2) 4.0 2004
LIBOR
---------- ---------- ---------
Total Energy Holdings $700.1 $(98.4) $39.7
---------- ---------- ---------
Total PSEG $1,524.6 $(141.9) $46.4
========== ========== =========
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
*** Offsetting charges were recorded to Regulatory Asset/Liability.
(A) Represents 100% of Derivative Instrument.
(B) Net of Tax and Minority Interest.
- -----------------------------------------------------------------------------------------------------------------------
We expect to reclass approximately $19 million of losses on open positions
related to interest rate swaps from OCI to earnings during the next twelve
months. As of June 30, 2002, there was a $46 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 partnership investments in certain capital and leveraged buyout funds
investing in securities at fair value where market quotations and an established
liquid market of underlying securities in the portfolio are available.
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. For investments where there is not a liquid market,
Resources relies on the valuation by the investment fund manager to determine if
the fund has experienced an other than temporary impairment for which a loss
would need to be recorded. During the quarter ended June 30, 2002, Resources
recognized such a loss of approximately $26 million pre-tax. As of June 30,
2002, Resources had investments in leveraged buyout funds of approximately $90
million, of which $21 million was comprised of public securities with available
market prices and $69 million were private investments. Comparably, as of
December 31, 2001, Resources had investments in leveraged buyout funds of
approximately $130 million, of which $35 million was comprised of public
securities with available market prices and $95 million were private
investments.
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 to foreign currency risk 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 and purchase of options to limit downside on
earnings translation.
As of June 30, 2002, Global and Resources had international assets of
approximately $2.870 billion and $1.425 billion, respectively. For further
analysis of our international assets, see Note 9. Financial Information by
Business Segments.
Resources' international investments are primarily leveraged leases of assets
located in Austria, Australia, Belgium, China, Germany, the Netherlands, New
Zealand and the United Kingdom with associated revenues denominated in US
Dollars and therefore, not subject to foreign currency risk.
Global's international investments are primarily in projects that presently, or
are expected to, generate or distribute electricity in 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 Dollar, there is a corresponding change in Global's
investment value in terms of the US Dollar. Such change is reflected as an
increase or decrease in the investment value and Other Comprehensive Loss or
OCI, a separate component of Stockholder's Equity. As of June 30, 2002, net
foreign currency devaluations have reduced the reported amount of our total
Stockholder's Equity by $276 million, of which $184 million and $84 million were
caused by the devaluation of the Brazilian Real and the Chilean Peso,
respectively. For the net foreign currency devaluations for the quarter and six
months ended June 30, 2002 and 2001, see Note 10. Comprehensive Income.
In May 2002, Energy Holdings purchased foreign currency call options in order to
hedge its average 2002 earnings denominated in Brazilian Reais and in Peruvian
Nuevo Sols for the remainder of 2002. As of June 30, 2002, there were six call
options outstanding on the Brazilian Real, one expiring in each month through
December 2002. The aggregate notional value of these contracts was approximately
$17 million as of June 30, 2002. The fair value of those options as of June 30,
2002 was $1 million. In addition, there were six call options outstanding on the
Peruvian Nuevo Sol, one expiring in each month through December 2002. The
aggregate notional value of these contracts was approximately $48 million as of
June 30, 2002. The fair value of those options as of June 30, 2002 was
negligible. These options are not considered hedges for accounting purposes and,
as a result, changes in their fair value are recorded directly to earnings.
The fair value of foreign currency derivatives, designated and effective as cash
flow hedges, are initially recorded in OCI. Reclassification of unrealized gains
or losses on cash flow hedges of variable-rate debt instruments from OCI into
earnings occurs as payments are made on the derivative instruments and generally
offsets the change in the value of the hedged item. We estimate reclassifying $1
million of foreign exchange gains from foreign currency cash flow hedges,
including our pro-rata share from our equity method investees, from OCI to our
Consolidated Statements of Operations over the next 12 months. For the quarter
and six months ended June 30, 2002, losses of less than $1 million were
transferred from OCI to our Consolidated Statements of Operations.
Note 8. Income Taxes
A tax (benefit) expense has been recorded for the results of continuing
operations. An analysis of that provision (benefit) expense is as follows:
Quarter Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2002 2001 2002 2001
----------- ---------- ------------ ---------
Pre-Tax (Loss) Income..................................... $ (348) $ 236 $ (54) $649
Tax Computed at the Federal Statutory Rate at 35%......... (122) 83 (19) 227
Increases (decreases) from Federal statutory rate
attributable to:
State Income Taxes after Federal Benefit.............. 10 15 29 39
Rate Differential of Foreign Operations............... (6) (4) (8) (17)
Plant Related Items................................... (3) (5) (7) (10)
Other................................................. -- (4) (2) 2
----------- ---------- ------------ ---------
Total Income Tax (Benefit) Expense........................ $ (121) $ 85 $ (7) $ 241
----------- ---------- ------------ ---------
Effective Income Tax Rate............................ (34.7)% 36.2% (12.9)% 37.1%
Permanent differences are proportionally higher relative to pre-tax results from
continuing operations resulting in a relatively low effective tax rate for the
six months ended June 30, 2002.
Note 9. Financial Information by Business Segments
Information related to the segments of our business is detailed below:
Energy (B) Energy Consolidated
Generation Trading PSE&G Resources (A) Global Technologies (C) Other Total
---------- ------- -------- ---------- ------------ ------------ --------- ------------
(Millions of Dollars)
For the Quarter Ended
June 30,2002:
- --------------------------------------
Operating Revenues................... $565 $445 $1,230 $26 $134 $-- $(618) $1,782
(Loss) Income from Continuing
Operations........................... 73 10 7 (5) (309) (1) (2) (227)
Loss From Discontinued Operations.... -- -- -- -- (12) (25) -- (37)
Segment (Loss) Earnings.............. 73 10 7 (5) (321) (26) (2) (264)
For the Quarter Ended
June 30, 2001:
- --------------------------------------
Operating Revenues................... $588 $571 $1,311 $51 $37 -- $(511) $2,047
Income (Loss) from Continuing
Operations........................... 82 22 31 14 3 -- (1) 151
Loss From Discontinued Operations.... -- -- -- -- 1 $(9) -- (8)
Segment Earnings (Loss).............. $82 $22 $31 $14 $4 $(9) $(1) $143
For the Six Months Ended
June 30, 2002:
- --------------------------------------
Operating Revenues................... $1,110 $858 $2,889 $78 $241 $-- $(1,106) $4,070
Income Before Discontinued Operations,
Extraordinary Items, and Cumulative
Effect of a Change in Accounting
Principle........................... 175 28 74 9 (322) (1) (10) (47)
Loss From Discontinued Operations.... -- -- -- -- (9) (28) -- (37)
Cumulative Effect of a Change in
Accounting Principle................. -- -- -- -- (88) (32) -- (120)
Segment (Loss) Earnings.............. $175 $28 $74 $9 $(419) $(61) $(10) $(204)
For the Six Months Ended
June 30, 2001:
- --------------------------------------
Operating Revenues................... $1,149 $1,146 $3,263 $84 $126 -- $(1,017) $4,751
Income Before Discontinued Operations,
Extraordinary Items, and Cumulative
Effect of a Change in Accounting
Principle............................ 155 51 140 17 52 (1) (6) 408
Loss From Discontinued Operations.... -- -- -- -- -- (11) -- (11)
Extraordinary Loss on Early
Retirement of Debt................... -- -- -- -- (2) -- -- (2)
Cumulative Effect of a Change in
Accounting Principle................. -- -- -- -- 9 -- -- 9
Segment Earnings (Loss).............. $155 $51 $140 $17 $59 $(12) $(6) $404
As of June 30, 2002:
- --------------------------------------
Total Assets......................... $5,383 $1,132 $12,597 $3,144 $3,567 $227 $(704) $25,346
As of December 31, 2001:
- --------------------------------------
Total Assets......................... $4,713 $790 $12,963 $3,026 $4,074 $290 $(426) $25,430
(A) For a discussion of the charge relating to Argentina, see Note 3. Asset
Impairments.
(B) For a discussion of the charges relating to Discontinued Operations at
Energy Technologies, see Note 3. Asset Impairments and Note 4. Discontinued
Operations.
(C) Our other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation), Enterprise Group
Development Company (EGDC), and intercompany eliminations, including
transactions between Power and PSE&G relating to BGS, MTC and BGSS which
amounted to approximately $600 million and $500 million for the quarters
ended June 30, 2002 and 2001, respectively and approximately $1.1 billion
and $1.0 billion for the six months ended June 30, 2002 and 2001,
respectively. The net losses primarily relate to financing and certain
administrative and general costs at the parent corporations.
Our geographic information is disclosed below. The foreign assets and operations
noted below are solely related to Energy Holdings.
Revenues (1) Identifiable Assets (2)
------------------------------------------------------ --------------------------------
Quarter Ended Six Months Ended
June 30, June 30, June 30, December 31,
------------------------- -------------------------
2002 2001 2002 2001 2002 2001
----------- ---------- ---------- ----------- ----------- -----------------
(Millions of Dollars)
United States......... $1,670 $1,999 $3,832 $4,652 $21,051 $20,666
Foreign Countries..... 112 48 238 99 4,295 4,764
----------- ---------- ---------- ----------- ----------- -----------------
Total............ $1,782 $2,047 $4,070 $4,751 $25,346 $25,430
=========== ========== ========== =========== =========== =================
Identifiable assets in foreign countries include:
Chile.................................................................... $996 $880
Netherlands.............................................................. 954 911
Argentina................................................................ -- 737
Peru .................................................................... 445 520
Tunisia ................................................................. 277 245
India (3)................................................................ 271 288
Poland................................................................... 252 166
Brazil................................................................... 228 282
Other.................................................................... 872 735
------------- -----------------
Total................................................................ $4,295 $4,764
============= =================
(1) Revenues are attributed to countries based on the locations of the
investments.
(2) Assets are comprised of investment in corporate joint ventures and
partnerships that are accounted for under the equity method and companies
in which we have a controlling interest for which the assets are
consolidated on our financial statements. Amount is net of tax
and foreign currency translation adjustment of $306 million and
$283 million as of June 30, 2002 and December 31, 2001, respectively.
(3) Approximately $230 million related to our Tanir Bavi operation, which was
discontinued as of June 30, 2002.
Note 10. Comprehensive Income
Comprehensive (Loss) Income, Net of Tax:
Quarter Ended Six Months Ended
June 30, June 30,
---------------------- ----------------------
2002 2001 2002 2001
--------- --------- --------- --------
(Millions of Dollars)
Net (loss) income.................................................... $(264) $143 $(204) $404
Foreign currency translation (A)..................................... (19) (36) (86) (38)
Reclassification Adjustment for losses included in net income........ 63 -- 69 --
Change in Fair Value of Derivative Instruments (B)................... (29) (39) (37) (44)
Cumulative effect of a change in accounting principle
(net of tax of $14 and minority interest of $12)............... -- -- -- (15)
Reclassification adjustments for net amounts included in Net Income
(C)............................................................... 1 21 7 21
Current Period change in Fair Value of Financial Instruments......... 1 -- -- --
Pension Adjustments, net of tax...................................... -- 2 (1) 2
Other................................................................ (2) 1 (2) 3
--------- --------- --------- --------
Comprehensive income $(249) $92 $(254) $333
========= ========= ========= ========
(A) Net of tax of $29 million and $4 million for the quarters ended June 30,
2002 and 2001, respectively, and $39 million and $4 million for six months
ended June 30, 2002 and 2001, respectively.
(B) Net of tax of $23 million and $26 million for the quarter and six months
ended June 30, 2002, respectively. Net of tax of $26 million and $30
million for the quarter and six months ended June 30, 2001, respectively.
(C) Net of tax and minority interest of $(1) million and $(1) million for the
quarter and $(6) million and $(4) million for the six months ended June 30,
2002, respectively. Net of tax and minority interest of $(15) million and
$(1) million for the quarter and $(15) million and $(1) million for the six
months ended June 30, 2001, respectively.
Note 11. Other Income and Deductions
Quarter Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
2002 2001 2002 2001
--------- --------- -------- ---------
(Millions of Dollars)
Other Income
Interest Income............................................. $4 $12 $9 $28
Gain on Disposition of Property............................. 1 - 1 2
Change in Derivative Fair Value............................. - - 2 1
Income from Minority Interests.............................. 4 - 5 -
Other 1 - 1 -
--------- --------- -------- ---------
Total Other Income.............................................. $10 $12 $18 $31
========= ========= ======== =========
Other Deductions
Donations................................................... $- $- $- $(1)
Change in Derivative Fair Value............................. (8) - - -
Other....................................................... (1) (1) (1) (1)
--------- --------- -------- ---------
Total Other Deductions.......................................... $(9) $(1) $(1) $(2)
========= ========= ======== =========
Note 12. Related Party Transactions
Loans to Texas Independent Energy, L.P. (TIE)
In April 1999, Global and its partner, Panda Energy International, Inc.,
established TIE, a 50/50 joint venture, to develop, construct, own, and operate
electric generation facilities in Texas. As of June 30, 2002 and December 31,
2001, Global's investments in the TIE partnership included $75 million and $165
million, respectively, of loans that earn interest at an annual rate of 12% that
are expected to be repaid over the next 10 years.
Loans to GWF Energy
Pending completion of project financing of the Henrietta and Tracy peaking
plants discussed in Note 6. Commitments and Contingent Liabilities, 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 which began on May 31, 2002,
with final maturity no later than December 31, 2002. Global has also provided
GWF Energy $52 million of working capital loans as of June 30, 2002, to fund
construction costs pending completion of project financing. Such loans bear
interest at 20% per annum.
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Following are the significant changes in or additions to information reported in
our 2001 Annual Report on Form 10-K and Amended Quarterly Report on Form 10-Q/A
for the quarter ended March 31, 2002, affecting our consolidated financial
condition and the results of operations. This discussion refers to our
Consolidated Financial Statements (Statements) and related Notes to Consolidated
Financial Statements (Notes) and should be read in conjunction with such
Statements and Notes.
Overview of the Quarter and Six Months Ended June 30, 2002
Net losses for the quarter ended June 30, 2002 were $264 million or $1.28 per
share of common stock, based on 207 million average shares outstanding. Net
losses for the six months ended June 30, 2002 were $204 million or $0.99 per
share of common stock, based on 207 million average shares outstanding. These
results include after-tax charges of $380 million or $1.84 per share and $531
million or $2.57 per share for the quarter and six months ended June 30, 2002,
respectively, related to the asset impairment of investments in Argentina and
losses from operations of those impaired assets, discontinued operations of
Energy Technologies and a generating facility in India and goodwill impairment
charges. For the six months ended June 30, 2002, as a result of adopting SFAS
142 on January 1, 2002, an after-tax impairment loss of $120 million or $0.58
per share was recognized, as of the date of adoption, as the cumulative effect
of a change in accounting principle. The after-tax charges discussed above are
summarized in the following table:
Quarter Ended Six Months
June 30, 2002 Ended June 30, 2002
------------------------ ------------------------
(Millions EPS (Millions EPS
of Dollars) of Dollars)
------------------------ ------------------------
Global
Argentina - EDEERSA and Assets Held for Sale to AES
Write-down of Investment............... $343 $1.66 $374 $1.81
Goodwill impairment.................... -- -- 36 0.18
--------------------- ------------------------
Total Argentina................................. 343 1.66 410 1.99
--------------------- ------------------------
India - Tanir Bavi
Discontinued Operations................ 12 0.06 9 0.04
Goodwill impairment.................... -- -- 18 0.09
--------------------- ------------------------
Total Tanir Bavi................................ 12 0.06 27 0.13
--------------------- ------------------------
Brazil - RGE
Goodwill impairment.................... -- -- 34 0.16
--------------------- ------------------------
SubTotal for Global.................................. 355 1.72 471 2.28
--------------------- ------------------------
Energy Technologies
Discontinued Operations................ 25 0.12 28 0.14
Goodwill impairment.................... -- -- 32 0.15
--------------------- ------------------------
SubTotal Energy Technologies......................... 25 0.12 60 0.29
--------------------- ------------------------
Total.......................................... $380 $1.84 $531 $2.57
===================== ========================
For the quarter and six months ended June 30, 2002, excluding these charges,
earnings were $116 million or $0.56 per share and $327 million or $1.58 per
share. Comparable earnings for the quarter and six months ended June 30, 2001
were $151 million or $0.72 per share and $408 million or $1.96 per share,
respectively. The decrease in earnings for the quarter and six months ended June
30, 2002, excluding these charges, as compared to the same periods in 2001
resulted primarily from unexpected losses in Resources' leveraged buyout
portfolio, lower energy trading margins at Power, higher Operation and
Maintenance and other expenses at Power and lower margins at PSE&G. These
decreases were partially offset by higher BGS margins at Power and gains related
to Global's withdrawal from its interest in the Eagle Point Cogeneration
Partnership (Eagle Point).
Earnings (Losses)
--------------------------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2002 2001 2002 2001
----------- ------------ ----------- ------------
(Millions of Dollars)
Generation....................................... $74 $83 $176 $155
Energy Trading................................... 9 21 27 51
PSE&G............................................ 7 31 74 140
Resources ....................................... (5) 14 9 17
Global (A)....................................... (309) 4 (321) 52
Energy Technologies.............................. -- (1) (1) (1)
Other (B)........................................ (3) (1) (11) (6)
----------- ------------ ----------- ------------
(Loss) Income from Continuing Operations (227) 151 (47) 408
Loss on Early Extinguishment of Debt............. -- -- -- (2)
Loss from Discontinued Operations, including
Loss on Disposal.............................. (37) (8) (37) (11)
Cumulative Effect of a Change in
Accounting Principle (C)..................... -- -- (120) 9
----------- ------------ ----------- ------------
Total PSEG ...................................... (264) 143 (204) 404
----------- ------------ ----------- ------------
Total PSEG Excluding Charges (D)................. $116 $151 $327 $408
=========== ============ =========== ============
Contribution to Earnings Per Share (Basic and Diluted)
--------------------------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
2002 2001 2002 2001
----------- ------------ ----------- ------------
Generation....................................... $0.36 $0.40 $0.85 $0.74
Energy Trading................................... 0.04 0.10 0.13 0.25
PSE&G............................................ 0.03 0.15 0.36 0.67
Resources ....................................... (0.02) 0.07 0.04 0.08
Global (A)....................................... (1.49) 0.02 (1.55) 0.25
Energy Technologies.............................. -- -- (0.01) (0.01)
Other (B)........................................ (0.02) (0.02) (0.05) (0.02)
----------- ------------ ----------- ------------
(Loss) Income from Continuing Operations (1.10) 0.72 (0.23) 1.96
Loss on Early Extinguishment of Debt............. -- -- -- (0.01)
Loss from Discontinued Operations, including
Loss on Disposal.............................. (0.18) (0.04) (0.18) (0.05)
Cumulative Effect of a Change in
Accounting Principle (C)..................... -- -- (0.58) 0.04
----------- ------------ ----------- ------------
Total PSEG....................................... (1.28) 0.68 (0.99) 1.94
----------- ------------ ----------- ------------
Total PSEG Excluding Charges (D)................. $0.56 $0.72 $1.58 $1.96
=========== ============ =========== ============
(A) Includes after-tax impairments and losses on operations of impaired assets
of $343 million or $1.66 per share and $374 million or $1.81 per share for
the quarter and six months ended June 30, 2002, respectively.
(B) Other activities include amounts applicable to PSEG (parent corporation),
Energy Holdings and EGDC. Losses primarily result from after-tax effect of
interest on certain financing transactions and certain other administrative
and general expenses at parent companies.
(C) Relates to the adoption of SFAS 142 for 2002 and the adoption of SFAS 133
for 2001.
(D) Excludes after-tax charges previously presented in the summary table of $380
million or $1.84 per share and $531 million or $2.57 per share for the
quarter and six months ended June 30, 2002, respectively.
Future Outlook
As a result of the lower than expected results in the second quarter of 2002, in
conjunction with the effects of the warm weather on PSE&G's gas sales in the
first quarter of 2002, we have revised our previous full year earnings-per-share
projection of $3.90 to $4.10 downward by 5% to a range of $3.70 to $3.90,
excluding the charges described above. For 2002, Power is expected to earn $460
million to $500 million, PSE&G is expected to earn $175 million to $185 million
and Energy Holdings is expected to earn $145 million to $155 million, excluding
the previously discussed charges.
Power is expected to be the primary 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, in New Jersey's recent basic generation
service (BGS) auction is expected to have a meaningful effect on our earnings
for the remainder of the year and should help to partially 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, 2002. At
the same time, PSE&G was able to secure all of its power supply for the one-year
period at competitive prices.
While Global realized substantial growth in 2001, significant challenges which
began developing during the fourth quarter of 2001 have continued into 2002.
These challenges include the Argentine economic, political and social crisis,
the soft power market in Texas and California, recent developments in India 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.
Over the long term, we continue to target a 7% earnings per share growth
rate. For 2003, we expect earnings per share to increase to a range of $4.00 to
$4.20, driven by the assumptions that: Power will continue to benefit from its
performance as a wholesale BGS provider with the new one year BGS contract
beginning August 1, 2002 and next year's contract beginning August 1, 2003;
PSE&G will have a successful outcome to its recently filed electric rate case
seeking a $250 million increase in electric rates beginning in August
2003, and benefit from more normal weather; Global, with its major risks in
Argentina and India behind it, significant cost-cutting measures in place and
limited spending planned over the next 18 to 24 months, expects improvements in
earnings through its focus on increasing the return on its existing assets; and
Resources, with recent and planned investments and less exposure to its
investment in the KKR leveraged buyout funds, expects to continue to be a steady
contributor to earnings and cash flows.
Factors Affecting Future Outlook
As a result of more than 70% of our earnings coming from unregulated businesses,
the continued changes in political, legislative, regulatory and economic
conditions in the many countries in which we do business, the inherent price
volatility of the commodities in our businesses, and many other factors, it is
much more difficult to accurately forecast our future earnings. Some of the key
sensitivities and risks of our businesses are discussed below.
Power's success as a wholesale BGS provider will depend, in part, on its ability
to meet its obligations under its full requirements contracts with the BGS
suppliers in a profitable manner. Power expects to accomplish this by producing
energy from its own generation and/or energy purchases in the market. Power also
enters into trading positions related to its generation assets and supply
obligations. To the extent it does not hedge its obligations, whether long or
short, Power will be subject to the risk of price fluctuations that could affect
its future results, such as increases in the price of energy purchased to meet
its supply obligations, the cost of fuel to generate electricity, the cost of
congestion credits that Power needs to transmit electricity and other factors.
In addition, Power is subject to the risk of subpar operating performance of its
fossil and nuclear generating units. To the extent there are unexpected outages
at Power's generating facilities, changes in environmental or nuclear
regulations or other factors which impact the production of such units or the
ability to generate and transmit electricity in a cost-effective manner, it may
cost us more to produce electricity or we may be required to purchase higher
cost energy to replace the energy we anticipated producing. These risks can be
exacerbated by, among other things, changes in demand in electricity usage, such
as those due to extreme weather and economic conditions.
Power's future revenue stream is also uncertain. Due to the timing of the New
Jersey BGS auction process, the majority of Power's revenues for August 1, 2003
and thereafter cannot be accurately predicted. Also, certain of Power's new
projects, such as our investments in the Lawrenceburg and Waterford projects in
the Midwest and the plants we are acquiring from Wisvest in Connecticut, are
also subject to the risk of changes in future energy prices as Power has not
entered into forward sale contracts for the majority of their expected
generation capacity. Also, since the majority of our generation facilities are
concentrated in the Northeast region, changes in future energy supply and demand
and energy-related prices in this region could materially affect our results.
Also, changes in the rules and regulation of these markets by FERC, particularly
changes in the ability to maintain market based rates, could have an adverse
impact on our results. As a result of these variables and risks, we cannot
predict the impact of these potential future changes on our forecasted results
of operations, financial position, or net cash flows, however such impact could
be material.
In addition, our earnings projections assume that we will continue to use energy
trading to optimize the value of our portfolio of generating assets and supply
obligations. This will depend, in part, on our, as well as our counterparties',
ability to maintain sufficient creditworthiness and to display a willingness to
participate in energy trading activities at anticipated volumes. Potential
changes in the mechanisms of conducting trading activity, such as the continued
availability of energy trading exchanges, could positively or negatively affect
trading volumes and liquidity in these energy trading markets compared to the
assumptions of these factors embedded in our business plans. Recently, the
energy trading markets have experienced a noticeable slowdown in the second
quarter that has affected our second quarter results and our 2002 earnings
projections. However, to date, the failure of certain internet-based energy
trading exchanges has not had a significant impact on liquidity in energy
trading markets where we conduct our business. As a result of these variables,
we cannot predict the impact of these potential future changes on our forecasted
results of operations, financial position, or net cash flows, however such
impact could be material.
PSE&G's success will be dependent, in part, on its ability to obtain a
reasonable outcome, which cannot be assured, to its recently filed electric rate
case as well as its ability to continue to recover the regulatory assets it has
deferred and the investments it plans to make in its electric and gas
transmission and distribution systems. As of June 30, 2002, as required by the
Final Order, PSE&G has had rate reductions totaling 9% since August 1, 1999 and
will have an additional 4.9% rate reduction effective August 1, 2002, which will
be in effect until July 31, 2003. This additional rate reduction reduces the MTC
rate and will therefore reduce Power's revenues once effective.
Energy Holdings' success will be dependent, in part, on its ability to mitigate
risks presented by its international strategy. The economic and political
conditions in certain countries where Global has investments present risks that
may be different than those found in the United States including: renegotiation
or nullification of existing contracts, changes in law or tax policy,
interruption of business, risks of nationalization, expropriation, war, and
other factors. Operations in foreign countries also present risks associated
with currency exchange and convertibility, inflation and repatriation of
earnings. In some countries in which Global has interests, economic and monetary
conditions and other factors could affect Global's ability to convert its cash
distributions to US Dollars or other freely convertible currencies, or to move
funds offshore from such countries. Furthermore, the central bank of any such
country may have the authority to suspend, restrict or otherwise impose
conditions on foreign exchange transactions or to approve distributions to
foreign investors. Although Global generally seeks to structure power purchase
contracts and other project revenue agreements to provide for payments to be
made in, or indexed to, United States Dollars or a currency freely convertible
into US Dollars, its ability to do so in all cases may be limited.
The international risks discussed above can potentially be magnified due to the
volatility of foreign currencies. The foreign exchange rates of the Brazilian
Real, Chilean Peso and Peruvian Sol have recently weakened due to various
political and economic factors. This could result in comparatively lower
contributions from our distribution investments in US Dollar terms. While we
still expect Latin America to contribute significantly to our earnings in the
future, the political and economic risks associated with this region could have
a material adverse impact on our remaining investments in the region.
Certain of Global's projects are also subject to the risk of changing future
energy prices, including its investment in two 1,000 MW facilities in Texas
which have performed below expectations due to lower energy prices than we had
anticipated, primarily resulting from the over-supply of energy in the Texas
power market. Global expects this trend to continue until the 2004-2005 time
frame when market prices are expected to increase, as older less efficient
plants in the Texas power market are expected to be retired and the demand for
electricity is expected to increase and has included these assumptions within
its business plans. However, no assurances can be given as to the accuracy of
these estimates and changes in these estimates could have a material impact on
its forecasted results of operations, financial position, or net cash flows.
Energy Holdings, through Resources, also faces risks with regard to the
creditworthiness of its counterparties, as well as the risk of a change in the
current tax treatment of its investments in leveraged leases. The manifestation
of either of these risks could cause a materially adverse effect on its strategy
and its forecasted results of operations, financial position, or net cash flows.
See Item 3. Qualitative and Quantitative Disclosures about Market Risk for
further discussion.
In addition, we have exposure to the equity and debt markets through our
substantial use of short-term financing, the effect of lower assumed rate of
returns and lower fund balances on our pension and other postretirement benefit
plan (OPEB) expenses, the potential impact to Resources' investment in the KKR
leveraged buyout funds, and other equity and debt investments held by us. Also,
increases in the cost of capital, which could result from market and lender
concerns regarding us, our industry, the United States and international
economic conditions and other factors, could make it more difficult for us to
enter into profitable investments. We are also subject to credit risk,
particularly within our unregulated businesses. See Item 3. Qualitative and
Quantitative Disclosures about Market Risk for further discussion.
Results of Operations
Operating Revenues
Electric
Electric revenues decreased $7 million or 1% for the quarter ended June 30, 2002
from the comparable period in 2001. The decrease was primarily due to a decrease
in our PSE&G segment revenues of $45 million primarily due to recovery of
approximately $19 million of lost sales associated with DSM programs through the
societal benefits charge (SBC). In addition, lower distribution sales volumes
reduced revenues by approximately $6 million due primarily to our industrial
customers and there was an approximate $12 million decrease in miscellaneous
electric revenues primarily relating to replacement capacity charges
(approximately $8 million) and fiber optics (approximately $2 million). There
were also decreases in our Generation segment revenues of $23 million primarily
related to a $9 million decrease in revenues from ancillary services and an $8
million decrease in Market Transition Charge (MTC) revenues relating to a 2%
electric rate reduction that went into effect in August 2001. Partially
offsetting these decreases was the inclusion of $61 million of revenues related
to various majority-owned acquisitions and plants going into operation at our
Global segment in the second quarter of 2001.
Electric revenues increased $39 million or 2% for the six months ended June 30,
2002 from the comparable period in 2001. The increase was primarily due to the
inclusion of $132 million of revenues related to various majority-owned
acquisitions and plants going into operation at our Global segment in the second
quarter of 2001. Offsetting this increase were decreases at our PSE&G segment
and Generation segment of approximately $54 million and $39 million,
respectively. The decrease in our PSE&G segment revenue primarily related to $19
million lost revenue recovery discussed above, lower distribution sales volumes
which reduced revenues by approximately $25 million due primarily to our
industrial customers and an approximate $14 million decrease in miscellaneous
electric revenues primarily relating to replacement capacity charges
(approximately $9 million) and fiber optics (approximately $2 million). The
decrease in our Generation segment revenue was primarily due to the effects of
two 2% rate reductions that occurred in February 2001 and August 2001, which
reduced revenues by approximately $36 million for the six months ended June 30,
2002 as compared to the same period in the prior year. These rate reductions
reduce the MTC revenues that PSE&G remits to Power as part of its BGS contract.
Gas
Gas revenues decreased $42 million or 12% and $309 million or 22% for the
quarter and for the six months ended June 30, 2002 from the comparable periods
in 2001, respectively, primarily due to the effects decreased commodity rates
(approximately $55 million and $270 million for the quarter and six months,
respectively) offset by increased gas base rates (approximately $10 million and
$36 million for the quarter and six months, respectively). In addition, the
effects of warmer weather in the first quarter of 2002, as compared to the same
period in 2001, decreased revenues for the six months ended June 30, 2002 by
approximately $80 million.
Trading
Trading revenues decreased by $227 million or 40% and $389 million or 34% for
the quarter and six months ended June 30, 2002 from the comparable periods in
2001, respectively, due to lower energy trading volumes, lower prices as
compared to 2001, and sales on emission credits recorded in the first quarter of
2001. The majority of our trading gains have been realized, which has provided
increased liquidity and cash flow. See Note 7. Financial Instruments, Energy
Trading and Risk Management for further discussion.
Other
Other revenues increased $11 million or 13% and decreased $22 million or 10% for
the quarter and six months ended June 30, 2002 from the comparable periods in
2001. The increase for the quarter was due to a $36 million increase in our
Global segment, excluding the electric revenues discussed above, primarily from
$39 million of gains from its withdrawal from Eagle Point. This increase was
partially offset by a decrease of $26 million in revenues at Resources primarily
relating to a net change of $32 million in the carrying value of publicly traded
and non-publicly traded securities in a leveraged buyout fund which was
partially offset by higher leveraged lease income from continued investments in
such transactions.
The decrease for the six months was primarily due to a $16 million decrease
in revenues at our Global segment and a $6 million decrease in revenues at our
Resources segment. The decrease at Global primarily relates to a net reduction
of $22 million in revenues associated with certain partnership interests. The
decrease at Resources related to a net change of $23 million in the carrying
value of publicly traded and private securities in a certain leveraged buyout
fund which was partially offset by $17 million of higher leveraged lease income
from continued investments in such transactions.
Operating Expenses
Electric Energy Costs
Electric Energy Costs increased $13 million or 5% and $8 million or 2% for the
quarter and six months ended June 30, 2002 from the comparable 2001 periods,
respectively, primarily due to additional electric energy costs of $28 million
and $58 million for the quarter and six months ended June 30, 2002,
respectively, related to various majority-owned acquisitions and plants going
into operation at our Global segment in the second quarter of 2001. In addition,
outages at Hudson, Salem and Hope Creek generating stations precipitated the
purchases of electricity on the open market to meet our generation needs. These
increases were partially offset by the lower cost of fuel, particularly natural
gas and the continued strong performance of our low-cost nuclear generating
plants.
Gas Costs
Gas Costs decreased $60 million or 25% and $320 million or 31% for the quarter
and six months ended June 30, 2002 from the comparable 2001 periods,
respectively, primarily due to lower demand as a result of the warmer weather
and decreased commodity rates (approximately $55 million and $270 million for
the quarter and six months, respectively) that became effective in January 2002.
In addition, lower demand due to warmer weather in the first quarter of 2002 as
compared to the same period in 2001, decreased costs by approximately $40
million for the six months ended June 30, 2002.
Trading Costs
Trading Costs decreased $200 million or 37% and $343 million or 32% for the
quarter and six months ended June 30, 2002 from the comparable 2001 periods,
respectively, primarily due to lower trading volumes (see corresponding
decreases in trading revenues). See Note 7. Financial Instruments, Energy
Trading and Risk Management for further discussion.
Operations and Maintenance
Operations and Maintenance expense increased $10 million or 2% and $24 million
or 3% for the quarter and six months ended June 30, 2002 from the comparable
2001 periods. The increase for the quarter and the six months was primarily due
to additional expenditures related to plants going into operation at our Global
segment.
Depreciation and Amortization
Depreciation and Amortization expense increased $16 million or 13% and $44
million or 19% for the quarter and six months ended June 30, 2002 from the
comparable 2001 periods. The increase was primarily due to an increase in
depreciable assets and a full periods' recognition of amortization of the
regulatory asset recorded for PSE&G's stranded costs which commenced in February
2001, combined with an increase in gas depreciation expense recorded in
accordance with PSE&G's increased gas base rates.
Interest Expense
Interest Expense increased $19 million or 11% and $49 million or 14% for
the quarter and six months ended June 30, 2002, respectively, from the
comparable 2001 periods 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 (SPEs), 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. All special purpose entities are consolidated
in our Consolidated Financial Statements, except for certain subsidiaries that
are less than majority owned by us and therefore are not permitted to be
consolidated in our financial statements under generally accepted accounting
principles.
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 material obligation on the parent-level investor to repay any debt incurred
by the project borrower. However, in some cases, certain obligations relating to
the investment being financed, including additional equity commitments, are
guaranteed by Global, Energy Holdings, and/or Power. Further, the consequences
of permitting a project-level default include loss of any invested equity by the
parent.
Over the next several years, we and our subsidiaries will be required to
refinance maturing debt, and expect to incur additional debt and provide equity
to fund investment activity. Any inability to obtain required additional
external capital or to extend or replace maturing debt and/or existing
agreements at current levels and reasonable interest rates may adversely affect
our financial condition, results of operations and net cash flows.
Debt Covenants, Cross Default Provisions, Material Adverse Clause Changes, and
Ratings Triggers
Our 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, after giving effect to any applicable grace
and/or cure periods, 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. In
the event of any likely default or failure to satisfy covenants or conditions,
we, or the relevant subsidiary, would seek to renegotiate terms of the
agreements with the lenders. No assurances can be given as to whether these
efforts would be successful. 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.
Our debt indentures and credit agreements and those of our subsidiaries do not
contain any material "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. Similarly, Power may also have to provide credit support for
certain of its equity commitments if Power loses its investment grade rating.
Credit Ratings
The current ratings of securities of PSEG and its subsidiaries are shown below
and reflect the respective views of the rating agencies, from whom an
explanation of the significance of their ratings may be obtained. There is no
assurance that these ratings will continue for any given period of time or that
they will not be revised or withdrawn entirely by the rating agencies, if, in
their respective judgments, circumstances so warrant. Any downward revision or
withdrawal may adversely effect the market price of PSEG's, Energy Holdings',
Power's and PSE&G's securities and serve to increase those companies' cost of
capital.
Moody's(1) Standard & Poor's(1)(3) Fitch(2)
---------- ----------------------- ---------
PSEG:
Preferred Securities Baa3 BB+ BBB
Commercial Paper P2 A2 Not Rated
PSE&G:
Mortgage Bonds A3 A- A
Preferred Securities Baa1 BB+ A-
Commercial Paper P2 A2 F1
Power:
Senior Notes Baa1 BBB BBB+
Energy Holdings:
Senior Notes Baa3 BBB- BBB-
PSEG Capital:
Medium-Term Notes Baa2 BBB- Not Rated
(1) Recently affirmed in the second quarter of 2002 and noted an outlook of
Stable.
(2) Recently affirmed in the second quarter of 2002 and noted an outlook of
Stable, except for PSE&G Mortgage Bonds, which was noted as negative.
(3) Standard and Poor's has established an overall corporate credit rating of
BBB for us and each of our subsidiaries listed above.
Short-Term Liquidity
We and our subsidiaries have revolving credit facilities to provide liquidity
for our $1 billion commercial paper program and PSE&G's $400 million commercial
paper program and for various funding purposes. The following table summarizes
the various revolving credit facilities of PSEG, PSE&G and Energy Holdings as of
June 30, 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 2003 200 CP Support
3-year Credit Facility June 2005 200 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
* Availability varies based on market conditions.
As of June 30, 2002, our consolidated total short-term debt outstanding was
$1.693 billion, including $744 million of commercial paper at PSEG, $279 million
of non-recourse short-term financing at Global and $349 million and $321 million
outstanding under credit facilities and through the uncommitted bilateral
agreement at PSEG and Energy Holdings, respectively. In addition, we have a
total of $1.415 billion of long-term debt due within one year, comprised of $973
million at PSE&G, including $127 million related to Transition Funding and $442
million at Energy Holdings.
In the ordinary course of business, we and our subsidiaries have financial
commitments for debt maturities and general corporate purposes. On April 16,
2002, we 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
was declared effective by the Securities and Exchange Commission (SEC) on July
3, 2002. It is our intention to issue securities from this shelf registration
before year-end. Due to our short-term liquidity needs and the timing of certain
preferred equity, equity-linked and long-term debt issuances that we are
contemplating, we currently have a significant reliance on short-term debt
financing, including the commercial paper markets, to meet our financing needs.
PSEG
In 2002, we began issuing new shares under our Dividend Reinvestment and
Employee Stock Purchase Plan (DRASPP), rather than purchasing them on the open
market.
Dividend payments on Common Stock for the quarter and six months ended June 30,
2002 were $0.54 and $1.08 per share and totaled approximately $111 million and
$223 million, respectively. 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 may 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 June 30, 2002, the ratio of debt to
capitalization was 0.682 to 1. This ratio can be maintained at this level for
the remainder of the year, absent any preferred or common equity issuances.
However, we currently plan to issue equity-linked securities before year-end,
which will lower this ratio. Also, 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 forecasts do not indicate that we will
exceed the required ratio of debt to total capitalization in our credit
facilities, even if we do not issue any preferred stock or equity-linked
securities. However, no assurances can be given and, if an event of default were
to occur, it could materially impact our results of operations, cash flow and
financial position.
On May 21, 2002, $275 million of Floating Rate Notes matured.
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements, provided that its ratio of earnings
to fixed charges calculated in accordance with its Mortgage is at least 2:1,
and/or against retired Mortgage Bonds. At June 30, 2002, PSE&G's Mortgage
coverage ratio was 3:1. As of June 30, 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 and $204 million against
retired mortgage bonds. 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 six months ended June 30, 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.
In June 2002, Power issued $600 million of 6.95% Senior Unsecured Notes due
2012. The proceeds were used to repay short-term funding from us, including
amounts related to the Gas Contract Transfer from PSE&G in May 2002.
Energy Holdings
As of June 30, 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 $12 million are outstanding as of June 30, 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
June 30, 2002, the latest 12 months CFADS coverage ratio was 4.8 and the ratio
of recourse indebtedness to recourse capitalization was 0.50 to 1.0.
PSEG Capital has a $650 million Medium-Term Note program which provides for the
private placement of Medium-Term Notes. This Medium-Term Note 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 June 30, 2002 and December 31, 2001, total debt outstanding
under the Medium-Term Note program was $382 million and $480 million,
respectively.
In June 2002, $98 million of PSEG Capital Corp. Medium-Term Notes matured. These
Medium-Term Notes were refunded with proceeds from a private placement of $135
million which reopened the 8.625% Series of Energy Holdings Notes due February
2008.
In July 2002, an additional $100 million of PSEG Capital MTNs with an average
borrowing rate of 6.95% matured. These MTNs were refunded with proceeds from
borrowings under Energy Holdings bank facilities with current interest costs of
approximately 2.7%.
Remaining maturities under the PSEG Capital Corp program are $30 million
maturing in October 2002 and $252 million maturing in May 2003. These issues
will be refunded with proceeds of borrowings at Energy Holdings and cash from
operations.
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.
Our subsidiaries have substantial commitments as part of their growth strategies
and ongoing construction programs. We expect that the majority of each
subsidiaries' capital requirements over the next five years will come from
internally generated funds, with the balance to be provided by the issuance of
debt at the subsidiary or project level and equity contributions from us.
Projected construction and investment expenditures for our subsidiaries for the
next five years are as follows:
2002 2003 2004 2005 2006
-------- --------- --------- --------- ---------
(Millions of Dollars)
Power..................... $ 960 $ 700 $ 340 $ 250 $ 230
Energy Holdings........... 600 400 350 350 350
PSE&G..................... 485 440 440 450 465
-------- --------- --------- --------- ---------
Total................. $ 2,045 $1,540 $ 1,130 $ 1,050 $ 1,045
======== ========= ========= ========= =========
Approximately 90% of the forecasted expenditures related to Energy Holdings are
discretionary. The majority of Energy Holdings forecasted capital expenditures
relate to Resources, pursuant to the shift in Global's strategy to limit capital
expenditures over the next 18 to 24 months to current contractual commitments
and shift their focus to increasing the efficiency and returns of its existing
assets.
For the six months ended June 30, 2002, we made net plant additions of $888
million. The majority of these additions, $496 million, primarily related to
Power for developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem,
NY (Albany) sites and adding capacity to the Bergen and Linden stations in New
Jersey. In addition, PSE&G had net plant additions of $196 million related to
improvements in its transmission and distribution system, gas system and common
facilities. Also, Energy Holdings' subsidiaries made investments totaling
approximately $359 million for the six months ended June 30, 2002, respectively.
These investments include an approximate 50% interest of a coal-fired generation
facility, currently under construction in Poland, and additional investments in
existing generation and distribution facilities and projects by Global and
investment in capital leases by Resources. Partially offsetting these
investments was an $88 million loan repayment from TIE. For a discussion of the
loans to TIE, see Note 12. Related Party Transactions. The $874 million of net
plant additions and $359 million of investments were included in our forecasted
expenditures for the year.
Accounting Matters
For a discussion of EITF 02-3, SFAS 142, SFAS 143 and SFAS 144, see Note 2.
Accounting Matters and Note 6. 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 June 30, 2002, this deferred amount was $185 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.
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 June 30, 2002, $324
million had been amortized and recorded as a reduction of depreciation expense
pursuant to the Final Order, of which $74 million relates to 2002. The remaining
$245 million will be amortized through July 31, 2003.
See Note 5. 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 7. Financial
Instruments, Energy Trading and Risk Management.
Presentation - EITF 99-19 provided guidance on the issue of whether a company
should report revenue based on the gross amount billed to the customer or the
net amount retained. The guidance states that whether a company should recognize
revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We report swaps,
futures, option premiums, firm transmission rights, transmission congestion
credits, and purchases and sales of emission allowances on a net basis. One of
the primary drivers of our determination that these contracts should be
presented on a gross basis was that we retain counterparty risk. Beginning in
the third quarter of 2002, we will report all energy trading revenues and energy
trading costs on a net basis under EITF 02-3. For additional information, see
Note 2. Accounting Matters.
SFAS 133 - Accounting for Derivative Instruments and Hedging Activities
- -----------------------------------------------------------------------
SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in OCI, net of tax, 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.
Prior to May 2002, PSE&G had entered into gas forwards, futures, options
and swaps to hedge its forecasted requirements for natural gas, which was
required under an agreement with the BPU in 2001. Effective with the gas
contract transfer on May 1, 2002, we also acquired all of the derivatives
entered into by PSE&G. We account for these derivative instruments pertaining to
residential customers in a similar manner as PSE&G did. Gains or losses from
these derivatives will be recovered from PSE&G's customers. Derivatives relating
to commercial and industrial customers will be accounted for in accordance with
SFAS 133, where appropriate. Gains or losses on these derivatives will be
deferred and reported as a component of OCI. The accumulated OCI will be
reclassified to earnings in the period in which the hedged transaction affects
earnings.
For additional information regarding Derivative Financial Instruments, See Note
7. 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.
Accounting for the Effects of Goodwill
- --------------------------------------
Our 2002 earnings have been materially impacted by the application of SFAS 142.
This new standard, effective January 1, 2002, requires the existence of any
goodwill impairment be disclosed in the second quarter and recorded by the
fourth quarter of 2002, applied retroactively to the first quarter. The basic
difference between previous accounting guidance and this new standard is that
the new standard allows for certain valuation methodologies to test for
impairment, including a discounted cash flow method, compared to an undiscounted
cash flow method which was utilized under the previous standard. The new test
must be completed using data as of January 1, 2002. Any amounts impaired using
data as of that date will be recorded as a "Cumulative Effect of an Accounting
Change". Any amounts impaired under the new test using data after the initial
adoption date will be recorded in Operating Expenses. The discounted cash flow
tests require broad assumptions and significant judgment to be exercised by
management. This includes projections of future commodity prices, customer
rates, customer demand, operating costs, rate relief from regulators, customer
growth and many other items. While we believe that our assumptions are
reasonable, actual results will likely differ from our projections.
We have finalized our evaluation of the effect of adopting SFAS 142 on the
recorded amount of our goodwill. For further detail regarding the goodwill
impairments noted above, see Note 2. Accounting Matters and Note 3. Asset
Impairments.
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. For
further detail on charges taken in the second quarter of 2002, see Note 3. Asset
Impairments and Note 4. Discontinued Operations.
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", "forecast","projections", 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 if our operating performance or cash flow from minority interests falls
below projected levels, we may not be able to service our debt.
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 regulatory issues significantly impact 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;
o changes in technology may make our power generation assets less
competitive; 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.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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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 (BGS contract),
owned generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. We estimate VAR 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 and a trip limit of $40 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 June 30, 2002 was approximately $25
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.
Credit Risk
Counterparties expose us to credit losses in the event of non-performance or
non-payment. We have a credit management process which is used to assess,
monitor and mitigate counterparty exposure for us and our subsidiaries. In the
event of non-performance or non-payment by a major counterparty, there may be a
material adverse impact on our and our subsidiaries' financial condition,
results of operations or net cash flows. As of June 30, 2002 over 97% of the
credit exposure (mark to market plus net receivables and payables) for Power's
trading business was with investment grade counterparties. As of June 30, 2002,
Power's trading business had over 80 active counterparties.
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We 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 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.
Resources also has credit risk related to its investments in leveraged
leases, which totaled approximately $1.6 billion, net of deferred taxes of $1.3
billion, as of June 30, 2002. These investments are significantly concentrated
in the energy related industry and have some exposure to the airline industry.
Although over 86% of its investments are with investment grade counterparties,
recent events in the industry have pressured the credit ratings of several of
the members of the industry, including certain of our counterparties in these
leveraged lease investments. The largest non-investment grade leases in
Resources' portfolio are with Dynegy Inc., whose credit rating was recently
downgraded to below investment grade. As of June 30, 2002, the leases with
Dynegy had a gross investment balance of approximately $161 million. In many of
these investments, Resources has protected its equity investment by providing
for the direct right to assume the debt obligation. Debt assumption would be at
Resources' sole discretion, and normally only would occur if an appraisal of the
leased property yielded a value that exceeds the present value of the debt
outstanding. Should Resources ever directly assume a debt obligation, the fair
value of the underlying asset and the associated debt would be recorded on the
balance sheet instead of the net equity investment in the lease. In the events
described above, the lease would essentially change from being classified as a
capital lease to a conventional operating lease. As of June 30, 2002, Resources
determined that the collectibility of the minimum lease payments under its
leveraged lease investments is still reasonably predictable and therefore
continues to account for these investments as leveraged leases.
Foreign Operations
As of June 30, 2002, Global and Resources had approximately $2.870 billion and
$1.425 billion, respectively, of international assets. As of June 30, 2002,
foreign assets represented 17% of our consolidated assets and the revenues
related to those foreign assets contributed 6% to consolidated revenues for the
quarter and six months ended June 30, 2002. For discussion of foreign currency
risk and asset impairments related to our investments in Argentina, see Note 3.
Asset Impairments, Note 6. Commitments and Contingent Liabilities and Note 7.
Financial Instruments, Energy Trading and Risk Management,
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PART II. OTHER INFORMATION
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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 and
Amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002, is
updated below.
In addition, see information on the following proceedings at the pages
indicated:
(1) March 31, 2002 Form 10-Q, Page 44. See Page 9. 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.
(2) Form 10-K Page 100. See Page 17. PSE&G's MGP Remediation Program.
(3) Form 10-K Page 100. See Pages 17. Investigation and additional
investigation by the EPA regarding the Passaic River site. Docket No.
EX93060255.
(4) Form 10-K Page 102. See Page 21. Complaint filed with the FERC 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.
(5) March 31, 2002 Form 10-Q, Page 44. See Page 54. Con Edison complaint filed
against PSE&G at FERC pursuant to Section 206 of the Federal Power Act.
Docket No. EL02-23-000.
(6) Form 10-K, Pages 26 and 27. See Page 54. DOE not taking possession of spent
nuclear fuel, Docket No. 01-551C.
(7) Form 10-K, pages 26 and 27. See Page 55. DOE Overcharges, Docket No.
01-592C.
(8) New Matter. See Page 55. PSE&G electric rate case filed with the BPU.
(9) New Matter. See Page 56. FERC Order related to PJM Restructuring.
(10) Form 10-K, page 33. In July 2002, the New Jersey Supreme Court upheld the
decision of the Appellate Division of the New Jersey Superior Court which
had unanimously affirmed a lower court's order granting summary judgment
in the shareholder derivative litigation, Docket No. C-68-96.
ITEM 5. OTHER INFORMATION
Certain information reported under PSEG's 2001 Annual Report on Form 10-K and
Amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002 is
updated below. References are to the related pages on the Form 10-K and Form
10-Q/A as printed and distributed.
Affiliate Standards
Form 10-K, page 15. On February 8, 2002 and March 27, 2002, the BPU issued
orders adopting the Competitive Service Audit reports on the state's electric
and gas utilities. The audit report generally concluded that PSE&G was in
compliance with the BPU's affiliate standards, and the BPU ordered
implementation of 24 of the auditor's recommendations, to which PSE&G did not
specifically object. On July 1, 2002, PSE&G filed its Affiliate Standards
compliance plan in accord with the BPU's regulations. Also in July 2002, the BPU
commenced its next regular audit of the state's electric and gas utilities'
competitive activities. The audit is expected to continue through the Spring of
2003.
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. On April 17, 2002, the BPU issued the final order approving
the transfer of PSE&G's gas supply business, including its interstate capacity,
storage and gas supply contracts to ER&T. ER&T entered into a BGSS contract with
PSE&G as required under the above BPU order. The transfer took place on May 1,
2002 at the book value of approximately $183 million. The initial term of the
contract ends on March 31, 2004 and PSE&G has the option to extend the term for
an additional three years. Under this agreement, ER&T will provide the full
requirements needed by PSE&G to render service under its BGSS tariff rate
schedules.
On May 1, 2002, the New Jersey Ratepayer Advocate filed a motion for
reconsideration of the BPU's approval of the transfer. PSE&G has opposed this
motion. This matter is currently pending before the BPU.
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 PSE&G's adjustment clauses that
are periodically trued-up to actual costs and reset. Effective with the gas
contract transfer, PSE&G pays 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 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 July 9, 2002 Congress
affirmed the President's decision. The DOE must still license and construct the
facility. No assurances can be given regarding the final outcome of this matter.
Con Edison Complaint
March 31, 2002 Form 10-Q, Page 44. On November 15, 2001, Consolidated
Edison, Inc. (Con Edison) filed a complaint against PSE&G at 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 in April 2002, FERC found sufficient reason to set the
complaint for hearing. An initial decision issued by an administrative law judge
in April 2002 upheld PSE&G's claim that the contracts do not require the
provision of "firm" transmission service to Con Edison but also accepted Con
Edison's contentions that PSE&G was obligated to provide service to Con Edison
utilizing all the facilities comprising its electrical system including
generation facilities and that PSE&G was financially responsible for
above-market generation costs needed to effectuate the desired power flows.
Under FERC procedures, an administrative law judge initial decision is not
binding unless and until its findings have been approved by FERC. PSE&G filed a
brief taking exception to the adverse findings of the April 25, 2002. A FERC
decision concerning the findings of the April 25, 2002 was expected on July 31,
2002. Settlement discussions between the companies with respect to this matter
have been on-going and, on July 17, 2002, representatives of the companies met
for settlement discussions mediated by a FERC administrative law judge. Based on
progress made at these discussions, Con Edison sought to extend the date for the
issuance of the FERC decision addressing the April 25, 2002 initial decision and
to extend the date for the commencement of a hearing with respect to issues in
the case not addressed by the April 25, 2002 initial decision. At present, in
the event the dispute is not settled, the FERC decision is expected on September
11, 2002 and the hearing before the administrative law judge will commence in
October 2002. The findings in the April 25, 2002 initial decision
notwithstanding, PSE&G believes it has complied with the terms of the Agreements
and will vigorously defend its position. The nature and cost of any remedy,
which is expected to be prospective only, cannot be predicted. Further, even in
the event settlement is reached with Con Edison, PSE&G could still be required
to bear substantial levels of additional costs.
Electric Base Rate Case
New Matter. On May 24, 2002, PSE&G filed an electric rate case with the BPU. In
this filing, PSE&G requested an annual $250 million rate increase for our
electric distribution business. The proposed rate increase includes $187 million
of increased revenues relating to a $1.7 billion increase in PSE&G's rate base,
which is primarily due to the investment that PSE&G has made in its electric
distribution facilities since the last rate case in 1992; $18 million in higher
depreciation rates and $45 million to recover various other expenses, such as
wages, fringe benefits, and the need to enhance the security and reliability of
the electric distribution system. The requested increase proposes a return on
equity of 11.75% for our electric distribution business.
Assuming current cost levels and a normal business environment, the proposed
rate increase would significantly impact our earnings and operating cash flows.
The non-depreciation portion of the rate increase ($232 million) would have a
positive effect our earnings and operating cash flows. The depreciation portion
of the rate increase ($18 million) would have no impact on our earnings, as the
increased operating cash flows would be offset by higher depreciation charges.
In accordance with BPU'S Final Order, which implemented parts of New Jersey's
Electric Discount and Competition Act, PSE&G was required to reduce electric
rates in four steps totaling 13.9% during the four year transition period. The
last step, a 4.9% decrease, will take effect August 1, 2002. If approved, the
proposed rate increase would be effective August 1, 2003, the end of the
transition period. While the proposed rate increase would increase electric
distribution rates by 12.8% from the July 31, 2003 level, rates would remain
2.6% lower than the levels in April 1999, when the BPU issued its Final Order.
We cannot predict the outcome of these rate proceedings at the current time.
NUG Contract Amendments
New Matter. On June 5, 2002, PSE&G amended its NUG contract with El Paso
Merchant Energy. Under federal law, PSE&G and other utilities were required to
enter into long-term NUG contracts with cogeneration facilities. PSE&G sells the
electricity it purchases under these contracts to Power at the Locational
Marginal Price (LMP) in the Pennyslvania-New Jersey-Maryland Power Pool (PJM).
Any difference between the amounts it pays under the NUG Contracts and the
amount it recovers through the Non-Utility Generation Transition Charge (NTC)
and sales at LMP are deferred as a regulatory asset or liability. Under the
amended contract, PSE&G received $102 million in return for allowing El Paso
Merchant Energy to provide electric energy and capacity from the open market, in
addition to their existing plant. This amount will be passed back to customers
through the NTC and was recorded as a regulatory liability.
Uranium Enrichment Decontamination and Decommissioning Fund
Form 10-K, page 27. In accordance with the EPAct, domestic entities that own
nuclear generating stations are required to pay into a decontamination and
decommissioning fund, based on their past purchases of U.S. government
enrichment services. Along with other nuclear generator owners, PSEG filed suit
in the U.S. Court of Claims and in the U.S. District Court, Southern District of
New York to recover these costs. In July 2002, PSEG withdrew from this lawsuit
without prejudice, due to an unfavorable decision against another nuclear
generator owner in the lawsuit.
FERC Order related to PJM Restructuring
New Matter: Atlantic City Electric Co., et al. v. Federal Energy Regulatory
Commission. On July 12, 2002, the United States Court of Appeals, D.C. Circuit,
issued an opinion in favor of PSE&G and the other utility petitioners, reversing
an order of the FERC relating to the restructuring of PJM into an Independent
System Operator. The Court agreed with PSE&G's position and ruled that FERC
lacks authority to require the utility owners to give up their statutory rights
under Section 205 of the Federal Power Act. Hence, FERC was wrong to require a
modification to the PJM ISO Agreement eliminating their rights to file changes
to rate design. The court further noted that FERC lacks authority under Section
203 of the Federal Power Act to require the utility owners to obtain approval of
their withdrawal from the PJM ISO. Hence, FERC had no right under Section 203 to
eliminate the withdrawal rights to which the utilities had agreed. Further, as
to PSE&G's situation, FERC could not accomplish a generic existing precedent, it
was first necessary to make a particularized finding with respect to the public
interest, which was not done here. This decision could be subject to an appeal
to the United States Supreme Court by the respondents, including the FERC.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
Exhibit Number Document
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12 Computation of Ratios of Earnings to Fixed Charges
(B) Reports on Form 8-K and Form 8-K/A:
Date of Report Form Items Reported
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April 26, 2002 8-K Items 5 and 7
July 11, 2002 8-K Items 5 and 7
July 17, 2002 8-K Items 5 and 7
July 29, 2002 8-K/A Items 5 and 7
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
By: PATRICIA A. RADO
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Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: July 29, 2002