UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
T QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
| Commission File Number |
Registrants, State of Incorporation, Address, and Telephone Number |
I.R.S. Employer Identification No. | ||||
| 001-09120 | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com |
22-2625848 | ||||
| 001-00973 | PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com |
22-1212800 | ||||
| 000-49614 | PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com |
22-3663480 | ||||
| 000-32503 | PSEG ENERGY HOLDINGS LLC (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 456-3581 http://www.pseg.com |
42-1544079 | ||||
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes T No £
As of July 15, 2004, Public Service Enterprise Group Incorporated had outstanding 237,227,847 shares of its sole class of Common Stock, without par value.
As of July 15, 2004, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
PSEG Power LLC and PSEG Energy Holdings LLC are wholly-owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and are filing their respective Quarterly Reports on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
| Public Service Enterprise Group Incorporated | Yes T | No £ | ||
| Public Service Electric and Gas Company | Yes £ | No T | ||
| PSEG Power LLC | Yes £ | No T | ||
| PSEG Energy Holdings LLC | Yes £ | No T |
TABLE OF CONTENTS i
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. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings) 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. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: PSEG, PSE&G, Power and Energy Holdings ii
•
credit, commodity, interest rate, counterparty and other financial market risks;
•
liquidity and the ability to access capital and credit markets;
•
energy obligations, available supply and trading risks;
•
adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation;
•
changes in the electric industry, including changes to power pools;
•
changes in the number of market participants and the risk profiles of such participants;
•
changes in technology that may make power generation, transmission, and/or distribution assets less competitive;
•
availability of power transmission facilities that impact the ability to deliver output to customers;
•
growth in costs and expenses;
•
environmental regulations that significantly impact operations;
•
changes in rates of return on overall debt and equity markets that could adversely impact the value of pension assets and the Nuclear Decommissioning Trust Funds;
•
changes in political conditions, recession, acts of war or terrorism;
•
availability of insurance coverage at commercially reasonable rates;
•
involvement in lawsuits including liability claims and commercial disputes;
•
inability to attract and retain management and other key employees;
•
acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' structure;
•
business combinations among competitors and major customers;
•
general economic conditions, including inflation;
•
regulatory issues that significantly impact operations;
•
changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements;
•
changes in tax laws and regulations;
•
ability to service debt as a result of any of the aforementioned events;
PSE&G and Energy Holdings Power and Energy Holdings Power Energy Holdings Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and each of PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings 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 PSEG's, PSE&G's, Power's and Energy Holdings' securities, PSEG, PSE&G, Power and Energy Holdings 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. iii
•
ability to obtain adequate and timely rate relief;
•
energy transmission constraints or lack thereof;
•
adverse changes in the marketplace for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices;
•
surplus of energy capacity and excess supply;
•
generation operating performance may fall below projected levels;
•
substantial competition in the worldwide energy markets;
•
inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;
•
margin posting requirements;
•
availability of fuel and timely transportation at reasonable prices;
•
competitive position could be adversely affected by actions involving competitors or major customers;
•
changes in product or sourcing mix;
•
delays or cost escalations or unsuccessful acquisitions, construction and development;
•
changes in regulation and safety and security measures at nuclear facilities;
•
changes in political regimes in foreign countries;
•
international developments negatively impacting its business;
•
changes in foreign currency exchange rates;
•
substandard operating performance or cash flow from investments falling below projected levels, adversely impacting the ability to service its debt;
•
deteriorating credit of lessees and their ability to adequately service lease rentals; and
•
ability to realize tax benefits.
ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense Preferred Stock Dividends INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax Expense INCOME FROM CONTINUING OPERATIONS Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal, net of tax benefit of $2 and $8 for the quarter and six months ended 2003, respectively INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE Extraordinary Item, net of tax benefit of $12 for 2003 Cumulative Effect of a Change in Accounting Principle, net of tax expense of $255 for 2003 NET INCOME WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC DILUTED EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS NET INCOME DILUTED INCOME FROM CONTINUING OPERATIONS NET INCOME See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters
Ended
June 30,
For The Six Months
Ended
June 30,
As Restated,
see Note 2
As Restated,
see Note 2
2004
2003
2004
2003
(Millions, except for share data)
(Unaudited)
$
2,290
$
2,401
$
5,511
$
5,689
1,254
1,400
3,077
3,353
537
488
1,083
1,007
170
98
342
197
28
28
73
72
1,989
2,014
4,575
4,629
33
31
61
51
334
418
997
1,111
83
30
118
89
(31
)
(9
)
(54
)
(52
)
(214
)
(210
)
(437
)
(408
)
(1
)
(1
)
(2
)
(2
)
171
228
622
738
(52
)
(72
)
(232
)
(258
)
119
156
390
480
5
(5
)
5
(18
)
124
151
395
462
—
(18
)
—
(18
)
—
—
—
370
$
124
$
133
$
395
$
814
236,705
225,910
236,449
225,627
238,001
226,582
238,321
226,108
$
0.50
$
0.69
$
1.65
$
2.13
$
0.52
$
0.59
$
1.67
$
3.61
$
0.50
$
0.69
$
1.64
$
2.12
$
0.52
$
0.59
$
1.66
$
3.60
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $41 and $40 in 2004 and 2003, respectively Unbilled Revenues Fuel Materials and Supplies Energy Trading Contracts Prepayments Assets of Discontinued Operations Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Nuclear Decommissioning Trust (NDT) Funds Other Special Funds Goodwill and Other Intangibles Other Total Noncurrent Assets TOTAL ASSETS See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
253
$
452
1,490
1,549
151
261
463
527
240
227
179
101
329
164
—
298
148
84
3,253
3,663
17,826
17,392
(5,130
)
(4,970
)
12,696
12,422
4,625
4,801
4,534
4,808
983
985
436
470
606
625
274
287
11,458
11,976
$
27,407
$
28,061
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Commercial Paper and Loans Accounts Payable Derivative Contracts Energy Trading Contracts Accrued Interest Accrued Taxes Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Regulatory Liabilities Nuclear Decommissioning Liabilities Other Postemployment Benefit (OPEB) Costs Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Project Level, Non-Recourse Debt Debt Supporting Trust Preferred Securities Total Long-Term Debt SUBSIDIARIES' PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2004 and 2003— 795,234 shares COMMON STOCKHOLDERS' EQUITY Common Stock, no par, authorized 500,000,000 shares; issued; 2004—263,225,987 shares and 2003—262,252,032 shares Treasury Stock, at cost; 2004—26,028,740 shares; 2003—26,118,590 shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholders' Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
180
$
726
774
301
1,055
1,216
194
103
154
72
184
185
115
33
—
242
432
465
3,088
3,343
4,108
4,196
523
536
297
284
558
532
800
616
6,286
6,164
8,385
7,921
2,019
2,085
918
1,738
1,201
1,201
12,523
12,945
80
80
4,520
4,490
(978
)
(981
)
2,356
2,221
(468
)
(201
)
5,430
5,529
18,033
18,554
$
27,407
$
28,061
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Extraordinary Item, net of tax benefit (Gain) Loss on Disposal of Discontinued Operations, net of tax Cumulative Effect of a Change in Accounting Principle, net of tax Depreciation and Amortization Amortization of Nuclear Fuel Provision for Deferred Income Taxes (Other than Leases) and ITC Non-Cash Employee Benefit Plan Costs Leveraged Lease Income, Adjusted for Rents Received Undistributed Losses (Earnings) from Affiliates Gain on Sale of Investments Foreign Currency Transaction Gain (Loss) Unrealized Gains on Energy Contracts and Other Derivatives Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs (Under) Over Recovery of Societal Benefits Charge (SBC) Net Realized Gains and Income from Nuclear Decommissioning Trust (NDT) Funds Other Non-Cash Credits Net Change in Certain Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Proceeds from the Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Investments in Joint Ventures, Partnerships and Capital Leases Proceeds from the Sale of Investments and Return of Capital from Partnerships Other Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Issuance of Long-Term Debt Issuance of Common Stock Issuance of Treasury Stock Redemptions of Long-Term Debt Cash Dividends Paid on Common Stock Other Net Cash (Used In) Provided By Financing Activities Effect of Exchange Rate Change Net Change In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,
As Restated,
see Note 2
2004
2003
(Millions)
(Unaudited)
$
395
$
814
—
18
(3
)
9
—
(370
)
342
197
41
46
34
67
106
125
(113
)
35
17
(5
)
(46
)
(45
)
6
(6
)
(24
)
(1
)
41
(51
)
(5
)
91
(75
)
(28
)
48
35
61
(226
)
(33
)
(150
)
93
47
(57
)
(20
)
828
582
(578
)
(661
)
(14
)
(18
)
292
2
17
(30
)
(283
)
(707
)
474
421
671
840
42
42
3
—
(1,643
)
(934
)
(260
)
(244
)
(30
)
(35
)
(743
)
90
(1
)
—
(199
)
(35
)
452
150
$
253
$
115
$
84
$
145
$
456
$
391
PUBLIC SERVICE ELECTRIC AND GAS COMPANY OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM Income Tax (Expense) Benefit INCOME BEFORE EXTRAORDINARY ITEM Extraordinary Item, net of tax benefit of $12 for 2003 NET INCOME Preferred Stock Dividends EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding Public Service Electric and Gas Company included 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters Ended
June 30,
For The Six Months Ended
June 30,
2004
2003
2004
2003
(Millions)
(Unaudited)
$
1,418
$
1,342
$
3,600
$
3,490
824
919
2,243
2,426
258
224
536
510
126
63
253
129
28
28
73
72
1,236
1,234
3,105
3,137
182
108
495
353
3
3
6
13
—
—
(1
)
(1
)
(91
)
(97
)
(187
)
(194
)
94
14
313
171
(31
)
8
(125
)
(48
)
63
22
188
123
—
(18
)
—
(18
)
63
4
188
105
(1
)
(1
)
(2
)
(2
)
$
62
$
3
$
186
$
103
in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $35 and $34 in 2004 and 2003, respectively Unbilled Revenues Materials and Supplies Prepayments Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Other Special Funds Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding Public Service Electric and Gas Company included in 6
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
21
$
140
768
804
151
261
50
50
259
44
28
22
1,277
1,321
9,940
9,793
(3,348
)
(3,258
)
6,592
6,535
4,625
4,801
135
131
249
272
101
102
5,110
5,306
$
12,979
$
13,162
the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Commercial Paper and Loans Accounts Payable Accounts Payable—Affiliated Companies, net Accrued Interest Clean Energy Program Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and ITC Regulatory Liabilities OPEB Costs Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Total Long-Term Debt PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2004 and 2003—795,234 shares COMMON STOCKHOLDER'S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholder's Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See disclosures regarding Public Service Electric and Gas Company included in 7
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
142
$
423
222
—
269
286
302
431
65
72
41
110
215
195
1,256
1,517
2,636
2,715
523
536
532
509
227
216
3,918
3,976
3,061
3,044
2,019
2,085
5,080
5,129
80
80
892
892
170
170
986
986
600
414
(3
)
(2
)
2,645
2,460
7,805
7,669
$
12,979
$
13,162
the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Extraordinary Item, net of tax benefit Depreciation and Amortization Provision for Deferred Income Taxes and ITC Non-Cash Employee Benefit Plan Costs Non-Cash Interest Expense Under Recovery of Electric Energy Costs (BGS and NTC) Over Recovery of Gas Costs (Under) Over Recovery of SBC Other Non-Cash Credits Gain on Sale of Property, Plant and Equipment Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues Prepayments Accounts Payable Other Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Other Net Cash Provided By (Used In) Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from the Sale of Property, Plant and Equipment Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Issuance of Long-Term Debt Redemption of Securitization Debt Redemption of Long-Term Debt Contributed Capital Preferred Stock Dividends Other Net Cash (Used In) Provided By Financing Activities Net Change In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding Public Service Electric and Gas Company 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,
2004
2003
(Millions)
(Unaudited)
$
188
$
105
—
18
253
129
(81
)
(11
)
79
88
7
16
(2
)
(95
)
43
44
(5
)
91
5
(9
)
(1
)
(8
)
146
162
(215
)
(205
)
(146
)
(211
)
(39
)
(7
)
(22
)
(95
)
(31
)
(54
)
179
(42
)
(187
)
(215
)
1
9
(186
)
(206
)
222
278
175
150
(62
)
(58
)
(445
)
(300
)
—
170
(2
)
(2
)
—
(3
)
(112
)
235
(119
)
(13
)
140
35
$
21
$
22
$
227
$
73
$
181
$
183
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE Income Tax Expense INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE Cumulative Effect of a Change in Accounting Principle, net of tax expense of $255 for 2003 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Power LLC 9
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Quarters Ended
June 30,
For the Six Months Ended
June 30,
2004
2003
2004
2003
(Millions)
(Unaudited)
$
993
$
1,235
$
2,685
$
3,065
681
787
1,905
2,078
237
228
467
430
28
24
55
47
946
1,039
2,427
2,555
47
196
258
510
77
25
112
69
(22
)
(10
)
(42
)
(40
)
(28
)
(28
)
(69
)
(56
)
74
183
259
483
(22
)
(74
)
(98
)
(197
)
52
109
161
286
—
—
—
370
$
52
$
109
$
161
$
656
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable Accounts Receivable—Affiliated Companies, net Short-Term Loan to Affiliate Fuel Materials and Supplies Energy Trading Contracts Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC) Nuclear Decommissioning Trust (NDT) Funds Goodwill and Other Intangibles Other Special Funds Other Total Noncurrent Assets TOTAL ASSETS LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Accounts Payable Short-Term Loan from Affiliate Energy Trading Contracts Derivative Contracts Other Total Current Liabilities NONCURRENT LIABILITIES Nuclear Decommissioning Liabilities Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7) LONG-TERM DEBT Project Level, Non-Recourse Debt Long-Term Debt Total Long-Term Debt MEMBER'S EQUITY Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive (Loss) Income Total Member's Equity TOTAL LIABILITIES AND MEMBER'S EQUITY See disclosures regarding PSEG Power LLC 10
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
17
$
27
607
615
188
228
—
77
454
516
172
162
179
101
86
53
1,703
1,779
6,228
5,980
(1,433
)
(1,399
)
4,795
4,581
42
24
983
985
127
122
107
115
130
125
1,389
1,371
$
7,887
$
7,731
$
687
$
800
191
—
154
72
140
37
182
156
1,354
1,065
297
284
339
161
636
445
—
800
3,316
2,816
3,316
3,616
1,700
1,700
(986
)
(986
)
1,971
1,810
(104
)
81
2,581
2,605
$
7,887
$
7,731
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Cumulative Effect of a Change in Accounting Principle, net of tax Depreciation and Amortization Amortization of Nuclear Fuel Interest
Accretion on Nuclear Decommissioning Liabilities Provision for Deferred Income Taxes and ITC Unrealized Gains on Energy Contracts and Derivatives Non-Cash Employee Benefit Plan Costs Net Realized Gains and Income on NDT Funds Net Changes in Certain Current Assets and Liabilities: Fuel, Materials and Supplies Accounts Receivable Accounts Payable Other Current Assets and Liabilities Employee Benefit Plan Funding and Other Payments Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Short-Term Loan to Affiliate Other Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Recourse Long-Term Debt Redemption of Non-Recourse Long-Term Debt Short-Term Loan from Affiliate Repayment of Note Payable—Affiliated Company Net Cash Used In Financing Activities Net Change In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding PSEG Power LLC 11
PSEG ENERGY HOLDINGS LLC OPERATING REVENUES Electric Generation and Distribution Revenues Income from Capital and Operating Leases Other Total Operating Revenues OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense INCOME BEFORE INCOME TAXES, MINORITY INTEREST AND DISCONTINUED OPERATIONS Income Tax Expense Minority Interests in Earnings of Subsidiaries INCOME BEFORE DISCONTINUED OPERATIONS Income (Loss) from Discontinued Operations, net of tax benefit of $2 and $5 for the quarter and six months ended 2003, respectively Gain (Loss) on Disposal of Discontinued Operations, net of tax benefit of $3 for the six months ended 2003 NET INCOME Preference Units Distributions EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Energy Holdings LLC 12
PSEG ENERGY HOLDINGS LLC ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable: Trade—net of allowances of $6 and $6 in 2004 and 2003, respectively Other Accounts Receivable Affiliated Companies Notes Receivable: Affiliated Companies Other Inventory Prepayments Restricted Funds Assets of Discontinued Operations Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Capital Leases—net Corporate Joint Ventures Partnership Interests Other Investments Goodwill and Other Intangibles Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding PSEG Energy Holdings LLC 13
PSEG ENERGY HOLDINGS LLC LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable: Trade Affiliated Companies Derivative Contracts Accrued Interest Notes Payable Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment and Energy Tax Credits Derivative Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7) MINORITY INTERESTS LONG-TERM DEBT Project Level, Non-Recourse Debt Senior Notes Total Long-Term Debt MEMBER'S EQUITY Ordinary Unit Preference Units Retained Earnings Accumulated Other Comprehensive Loss Total Member's Equity TOTAL LIABILITIES AND MEMBER'S EQUITY See disclosures regarding PSEG Energy Holdings LLC 14
PSEG ENERGY HOLDINGS LLC CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: (Gain) Loss on Disposal of Discontinued Operations, net of tax Depreciation and Amortization Deferred Income Taxes (Other than Leases) Leveraged Lease (Income) Loss, Adjusted for Rents Received Unrealized Loss on Investments Change in Fair Value of Derivative Financial Instruments Undistributed Losses (Earnings) from Affiliates Gain on Sale of Investments Foreign Currency Transaction Loss (Gain) Other Non-Cash Charges Net Changes in Certain Current Assets and Liabilities: Accounts Receivable Inventory Accounts Payable Other Current Assets and Liabilities Proceeds from Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Investments in Joint Ventures, Partnerships, and Leveraged Lease Agreements Proceeds from the Sale of Investments and Return of Capital from Partnerships Proceeds from Termination of Capital Leases Short-Term Loan Receivable—Affiliated Company Restricted Cash Other Net Cash Provided By (Used In) Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Repayment of Senior Notes Proceeds from Project-Level Non-Recourse Long-Term Debt Repayment of Project-Level Non-Recourse Long-Term Debt Redemption of Preference Units Ordinary Unit Distributions Proceeds from Minority Shareholders Cash Dividends Paid on Preference Units/Preferred Stock Restricted Cash Other Net Cash (Used In) Provided By Financing Activities Effect of Exchange Rate Change Net Change In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Received Interest Paid, Net of Amounts Capitalized See disclosures regarding PSEG Energy Holdings LLC 15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company. Note 1. Organization and Basis of Presentation Organization PSEG PSEG has four principal direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). PSE&G PSE&G is an operating public utility company engaged principally in the transmission and distribution of electric energy and natural gas service in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also owns PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote entity established for the purpose of purchasing intangible transition property and issuing transition bonds. Power Power is a multi-regional wholesale energy supply business that utilizes energy trading to comprehensively manage its portfolio of electric generation assets, gas supply and storage contracts and electric and natural gas supply obligations. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of the portfolio. Fossil, Nuclear and ER&T are subject to regulation by the FERC. Energy Holdings Energy Holdings has two principal direct wholly-owned subsidiaries: PSEG Global LLC (Global), which owns and operates international and domestic projects engaged in the generation and distribution of energy, including independent power production facilities and electric distribution companies; and PSEG Resources LLC (Resources), which has primarily invested in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. During the third quarter of 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies). For additional information relating to Energy Technologies, see Note 4. Discontinued Operations and Dispositions. Services Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, environmental, health and safety, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the 16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements. Basis of Presentation PSEG, PSE&G, Power and Energy Holdings The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, PSEG's, PSE&G's, Power's and Energy Holdings' respective Annual Report on Form 10-K for
the period ended December 31, 2003 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2004. The unaudited condensed consolidated financial information furnished herein 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 Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the period ended December 31, 2003. Certain reclassifications of prior period data have been made to conform with the current presentation. Pension and Other Postemployment Benefits (OPEB) PSEG PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG and its participating affiliates' current and former employees who meet certain eligibility criteria. The following table provides the Components of Net Periodic Benefit Costs relating to all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. Components of Net Periodic Benefit Costs: Service Cost Interest Cost Expected Return on Plan Assets Amortization of Net Transition Obligation Prior Service Cost Loss (Gain) Net Periodic Benefit Costs Effect of Regulatory Asset Total Benefit Expense 17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG, PSE&G, Power and Energy Holdings PSE&G's, Power's, Energy Holdings' and Services eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. Pension costs and OPEB costs for PSEG, PSE&G, Power and Energy Holdings are detailed as follows: PSE&G Power Energy Holdings Other (A) Total Benefit Expense (A) Other amounts relate to costs at Services. Stock Compensation PSEG During the second quarter of 2004, 574,200 non-qualified stock options to purchase PSEG common stock were granted to certain key employees. Also during the second quarter of 2004, 94,400 shares of restricted stock were granted under the 2004 Long Term Incentive Plan (LTIP) to certain key executives. These shares are subject to restrictions on transfer and subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule beginning on December 31, 2004, and become fully vested on December 31, 2006. The unearned compensation related to these restricted stock grants as of June 30, 2004 is approximately $4 million and is included in Retained Earnings on the Condensed Consolidated Balance Sheets. In addition, 94,400 performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock within 45 days of January 1, 2007 based on achievement of certain financial goals. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. As of June 30, 2004, approximately 95,697 performance units were outstanding. PSEG applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock-based compensation plans. Accordingly, no compensation has been recognized for the fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Compensation expense has been recognized for the performance units and dividend equivalents. 18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table illustrates the effect on Net Income and Earnings Per Share if PSEG had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation: Net Income, as reported Add: Total stock-based employee compensation expensed during the period, net of tax Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects Pro forma Net Income Earnings Per Share: Basic—as reported Basic—pro forma Diluted—as reported Diluted—pro forma See Note 6. Earnings Per Share for further information. Goodwill and Other Intangible Assets PSEG, PSE&G, Power and Energy Holdings On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill. Under SFAS 142, goodwill is a nonamortizable asset subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. 19
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power and Energy Holdings As of June 30, 2004 and December 31, 2003, Power's and Energy Holdings' recorded goodwill and pro-rata share of goodwill in equity method investments was as follows: Consolidated Investments Energy Holdings—Global Sociedad Austral de Electricidad S.A. (SAESA)(A) Empresa de Electricidad de los Andes S.A. (Electroandes) Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO) Total Energy Holdings—Global Power—Albany Steam Station (Albany Station) Total PSEG Consolidated Goodwill Pro-Rata Share of Equity Method Investments Energy Holdings—Global Rio Grande Energia (RGE)(A) Chilquinta Energia S.A. (Chilquinta)(A) Luz del Sur S.A.A (LDS) Kalaeloa Pro-Rata Share of Equity Investment Goodwill Total PSEG Goodwill PSEG, PSE&G, Power and Energy Holdings In addition to goodwill, as of June 30, 2004 and December 31, 2003, PSEG, PSE&G, Power and Energy Holdings had the following recorded intangible assets: As of June 30, 2004: Defined Benefit Pension Plan(B) Emissions Allowances(C) Various Access Rights(B) Transmission Rights(D) Other(D) Total Intangibles As of December 31, 2003: Defined Benefit Pension Plan(B) Emissions Allowances(C) Various Access Rights(B) Transmission Rights(D) Other(D) Total Intangibles 20
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Nuclear Decommissioning Trust (NDT) Funds Power Power maintains
an independent external trust to provide for decommissioning
of its nuclear facilities upon termination of operation. The trust contains
two separate funds: a qualified fund and a nonqualified fund. Power's policy
restricts the trust from investing directly in securities or other obligations
of PSEG or its affiliates, or its successors or assigns, and from investing
in securities of any entity owning one or more nuclear power plants. During
the second quarter of 2004, Power moved to a yield-based strategy for its nonqualified
fund to take advantage of a lower tax rate. This change resulted in the realization
of gains during the second quarter of 2004. See Note 11. Other Income and
Deductions for additional information. The fair value of the NDT Funds was $983 million as of June 30, 2004, including $231 million of Cash and Cash Equivalents. Note 2. Restatement of Financial Statements PSEG and Energy Holdings Subsequent to the issuance of the Condensed Consolidated Financial Statements for the quarter ended June 30, 2003 and in preparation of the Consolidated Financial Statements for the year ended December 31, 2003, management determined that the recorded amount of Energy Holdings' investment in RGE was overstated due to a miscalculation of the amount of foreign currency translation adjustments and that certain amounts related to this investment had been erroneously recorded as translation adjustments instead of foreign currency transactions. The impact on previously reported Net Income of PSEG and Energy Holdings of the adjustments related to RGE resulted in an increase of $3 million and $4 million for the quarter and six months ended June 30, 2003, respectively. As a result, the accompanying Condensed Consolidated Financial
Statements of PSEG and Energy Holdings for the quarter and six months ended June 30, 2003 have been restated from the amounts previously reported to reflect the correct amount of foreign currency translation adjustments and to record the effects of foreign currency transactions in earnings rather than as an adjustment to Accumulated Other Comprehensive Loss. In addition to the adjustments described above, certain other adjustments, previously considered to be immaterial individually and in the aggregate, were also recorded in the restated Condensed Consolidated Financial Statements for the quarter and six months ended June 30, 2003. The impact on previously reported Net Income of PSEG and Energy Holdings of these additional adjustments resulted in no change for the quarter ended June 30, 2003 and an increase of $4 million for the six months ended June 30, 2003. 21
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The effects on the financial statements of all adjustments and their related tax effects are detailed as follows: PSEG Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense Income from Continuing Operations Loss from Discontinued Operations, including Loss on Disposal, net of tax Net Income Earnings Per Share (Basic) Income from Continuing Operations Net Income Earnings Per Share (Diluted) Income from Continuing Operations Net Income Energy Holdings Electric Generation and Distribution Revenues Other Operating Revenues Energy Costs Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense Minority Interests in Earnings of Subsidiaries Income before Discontinued Operations Loss from Discontinued Operations, net of tax Net Income The amounts as previously reported do not reflect certain reclassifications due to the presentation of Energy Holdings' investment in Carthage Power Company (CPC), a generating facility in Tunisia, as a discontinued operation, as discussed in Note 4. Discontinued Operations and Dispositions and the effects of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities” (FIN 46), as discussed in Note 3. Recent Accounting Standards, and other reclassifications that have been made to conform with the current presentation. Note 3. Recent Accounting Standards SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) PSEG, PSE&G, Power and Energy Holdings Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement 22
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently depreciate that asset retirement cost to expense over its useful life. In periods subsequent to the initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion are charged to Operation and Maintenance expense on the Condensed Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows are adjustments to the carrying amount of the related asset. PSEG and Power As a result of adopting SFAS 143, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $370 million, after-tax, in the first quarter of 2003. Of this after-tax amount, $292 million related to nuclear decommissioning and $78 million related to the reversal of cost of removal liabilities for the fossil units. FIN 46R and FIN 46 PSEG, PSE&G, Power and Energy Holdings FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities (VIEs)”, (FIN 46R) amends FIN 46 and clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. PSEG, PSE&G, Power and Energy Holdings adopted the provisions of FIN 46 as of July 1, 2003. There was no effect on Power due to the adoption of these rules. The adoption of FIN 46R did not impact the implementation of FIN 46 (discussed below) by PSEG, PSE&G, Power and Energy Holdings or have any other effects on their respective financial statements. The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts and Energy Holdings to consolidate its investments in four real estate partnerships. Prior period financial statements have been reclassified for comparability in accordance with FIN 46. PSEG PSEG's Condensed Consolidated Balance Sheets reflect its equity investment in the capital trusts, which were previously eliminated in consolidation resulting in recording equal amounts of additional assets and long-term debt of $36 million as of June 30, 2004 and December 31, 2003. The invested cash was loaned back to PSEG in connection with the issuance of the preferred securities. 23
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table displays the securities, and their original issuance amounts, held by the trusts that have been deconsolidated. PSEG PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures 7.44% Floating Rate 7.25% 8.75% PSEG Participating Units 10.25% Total PSEG PSEG now records interest expense (previously eliminated against the interest income of the trust) instead of preferred securities dividends (since the preferred dividends are paid by the trusts that are no longer consolidated). For PSEG, these amounts totaled $14 million for each of the quarters ended June 30, 2004 and 2003 and $28 million for each of the six-month periods ended June 30, 2004 and 2003. PSE&G In December 2003, PSE&G redeemed its trust preferred securities. For PSE&G, interest expense related to these trusts totaled $3 million and $6 million for the quarter and six months ended June 30, 2003, respectively. In addition, PSE&G reviewed its Non-Utility Generation (NUG) contracts to determine if the entities involved were VIEs and, if so, if PSE&G was the primary beneficiary. These entities own power plants that sell their output to PSE&G, which PSE&G is contractually obligated to purchase at a variable price that correlates with certain major operating costs of the plants. As a result, PSE&G assumes some of the variability inherent in the operation of these plants. PSE&G attempted to obtain the information necessary to conduct the analysis of the cash flow variability required under FIN 46R from two facility owners where PSE&G held a potentially significant variable interest based on the NUG contracts. The respective facility owner's refused to provide the information based on their respective belief that the data was competitive and proprietary. As a result, PSE&G is unable to determine whether these entities should be consolidated under FIN 46R and applies the scope exception to FIN 46R that exempts entities that conduct exhaustive efforts to obtain the necessary information. PSE&G incurred costs related to these two specific NUG contracts of approximately $1 million and $2 million for the quarters ended June 30, 2004 and 2003, respectively, and approximately $3 million and $5 million for the six months ended June 30, 2004 and 2003, respectively. PSE&G cannot determine the maximum exposure from these two contracts due to the inability to obtain the necessary information. PSE&G's exposure relates to the potential for increases in the variable pricing components of the contract in the event rate recovery is not provided. PSE&G sells the electricity purchased under all of its NUG contracts at market prices in the PJM Interconnection, L.L.C. (PJM) spot market and recovers
the difference between the variable contract price and market price through the Non-Utility Generation Market Transition Charge (NTC). 24
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Holdings Energy Holdings evaluated its interests in four real estate partnerships previously accounted for under the equity method of accounting. Management determined that these entities were VIEs and further determined that Energy Holdings was the primary beneficiary and, therefore, was required to consolidate these entities. The current presentation reflects these entities on a fully consolidated basis and all prior periods were restated in accordance with FIN 46. The consolidation of the real estate partnerships on the Condensed Consolidated Balance Sheets resulted in an increase of approximately $31 million in assets and liabilities. There was no material impact of consolidating the real estate partnerships on Operating Revenues or Operating Expenses. Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11) PSEG and Power The EITF has previously discussed the income statement presentation of gains and losses on contracts held for trading purposes in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). In its discussion of EITF 03-11, EITF reached a consensus that gains and losses (realized and unrealized) on all derivative instruments within the scope of FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) should be shown net when recognized in the Consolidated Statement of Operations, whether or not settled physically,
if the derivative instruments are “held for trading purposes” as defined in EITF 02-3. These rules, which are effective for transactions occurring after September 30, 2003, required PSEG and Power to reduce revenues and costs by approximately $37 million and $82 million for the quarter and six months ended June 30, 2004, respectively, since these transactions are required to be recorded as net revenue. EITF Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1) PSEG, PSE&G, Power and Energy Holdings EITF 03-1 further defines the meaning of an “other-than-temporary impairment” and its application to debt and equity securities. Impairment occurs when the fair value of a security is less than its cost basis. When such a condition exists, the investor is required to evaluate whether the impairment is other-than-temporary as defined in EITF 03-1. When an impairment is other-than-temporary, the unrealized loss recorded in Accumulated Other Comprehensive Income must be charged to earnings. PSEG, PSE&G, Power and Energy Holdings do not expect any material effects from the adoption of EITF 03-1 on their respective financial statements. FASB Staff Position (FSP) 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2) PSEG, PSE&G, Power and Energy Holdings FSP 106-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Drug Act) for employers who sponsor postretirement health care plans that provide prescription drug benefits. FSP 106-2 also requires those 25
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS employers to provide certain disclosures regarding the effect of the federal subsidy provided by the Medicare Drug Act. The Medicare Drug Act generally permits plan sponsors that provide retiree prescription drug benefits that are “actuarially equivalent” to the benefits of Medicare Part D to be eligible for a non-taxable federal subsidy. FSP 106-2 is effective for periods beginning after June 15, 2004. Upon adoption of FSP 106-2 on July 1, 2004, there was not a material impact on PSEG's, PSE&G's, Power's or Energy Holdings' condensed consolidated financial statements. Note 4. Discontinued Operations and Dispositions Energy Holdings Discontinued Operations CPC In December 2003, Global entered into a definitive purchase and sale agreement related to the sale of its majority interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In May 2004, Global completed the sale of its majority interest in CPC for approximately $43 million in cash. The assets sold consisted primarily of accounts receivable, property, plant and equipment and other assets. The buyer also assumed certain accounts payable, accrued liabilities and debt obligations. In December 2003, Global recognized an estimated loss on disposal of $23 million for the initial write-down of its carrying amount of CPC to its fair value less cost to sell. During the first quarter of 2004, Energy Holdings re-evaluated the carrying value of CPC's assets and liabilities and determined that an additional write-down to fair value of $2 million was required, offsetting the $2 million of income from operations of CPC during the first quarter of 2004. In May 2004, the actual loss on the sale of CPC totaled $18 million. Accordingly, the accompanying Condensed Consolidated Statements of Operations for the quarter and six months ended June 30, 2004 include a gain on disposal of $5 million and $3 million, respectively. The operating results of CPC for the quarters and six months ended June 30, 2004 and 2003 are summarized below. Operating Revenues Pre-Tax Operating (Loss) Income Net (Loss) Income The carrying amounts of the assets and liabilities of CPC as of December 31, 2003 are summarized in the following table: Current Assets Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Total Liabilities 26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Technologies' Investments In June 2002, Energy Holdings adopted a plan to sell its heating, ventilating and air conditioning (HVAC)/mechanical operating companies. The HVAC/mechanical operating companies met the criteria for classification as components of Discontinued Operations. During the first quarter of 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies' assets and liabilities and determined that an additional write-down to fair value of $9 million, net of a $3 million tax benefit, was required. The sale of the HVAC/mechanical operating companies and Energy Technologies was complete as of September 30, 2003. The operating results of Energy Technologies for the quarter and six months ended June 30, 2003 are as follows: Operating Revenues Pre-Tax Operating Loss Net Loss Dispositions LDS In April 2004, Global sold a portion of its shares in LDS, in the Lima stock exchange, reducing its ownership from 44% to 38% and received gross proceeds of approximately $28 million. Global realized an after-tax gain of approximately $7 million in the quarter ended June 30, 2004 related to the LDS sale recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations. Resources In March 2004, Resources entered an agreement in principle with Midwest Generation LLC, an indirect subsidiary of Edison Mission Energy (EME), to terminate its lease investment in the Collins generating facility in Illinois. In April 2004, Resources closed on the termination of the lease agreement and received gross proceeds of approximately $184 million (approximately $84 million, after-tax) of cash that allowed it to substantially recover its investment in this lease. In connection with the agreement, in the first quarter of 2004, Resources recorded an after-tax charge of approximately $17 million to reduce its carrying value of the Collins lease. PSE&G In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In June 2003, a proposed settlement was filed with the Administrative Law Judge (ALJ) who recommended approval of the settlement to the BPU. In July 2003, PSE&G received an oral decision from the BPU approving the proposed settlement with certain modifications. As a result of the oral decision and subsequent summary written order, in the second quarter of 2003, PSE&G recorded certain adjustments in connection with the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund to customers
related to revenues previously collected in rates for nuclear decommissioning. Because this amount reflects the final accounting for PSEG's generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB Opinion No. 30, “Reporting the Results of 27
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71”. PSEG Diluted Earnings Per Share is calculated by dividing Net Income by the weighted average number of common stock shares outstanding, including shares issuable upon exercise of stock options outstanding under PSEG's equity compensation plans. The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating Diluted Earnings Per Share: EPS Numerator: Earnings (Millions) Continuing Operations Discontinued Operations Extraordinary Item Cumulative Effect of a Change in Accounting Principle Net Income EPS Denominator (Thousands): Weighted Average Common Shares Outstanding Effect of Stock Options Effect of Forward Contracts (PEPS) Total Shares Earnings Per Share: Continuing Operations Discontinued Operations Extraordinary Item Cumulative Effect of a Change in Accounting Principle Net Income There were approximately 3.5 million and 5.4 million stock options excluded from the weighted average common shares calculation used for Diluted Earnings Per Share due to their antidilutive effect for the quarters ended June 30, 2004 and 2003, respectively. There were approximately 3.1 million and 6.1 million stock options excluded from the weighted average common shares calculation used for Diluted Earnings Per Share due to their antidilutive effect for the six months ended June 30, 2004 and 2003, respectively. There were approximately 9.2 million participating units excluded from the weighted average common shares calculation used for Diluted Earnings Per Share due to their antidilutive effect for the quarter and six months ended June 30, 2003. Dividend payments on common stock for the quarter ended June 30, 2004 were $0.55 per share and totaled approximately $130 million. Dividend payments on common stock for the six months ended June 30, 2004 were $1.10 per share and totaled approximately $260 million. Dividend payments on common stock for the quarter ended June 30, 2003 were $0.54 per share and totaled approximately $122 million. Dividend payments on common stock for the six months ended June 30, 2003 were $1.08 per share and totaled approximately $244 million. 28
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7. Commitments and Contingent Liabilities Old Dominion Electric Cooperative (ODEC) PSE&G and Power In 1992, PSE&G entered into a ten-year wholesale power contract with ODEC to begin on January 1, 1995 and end on December 31, 2004. The contract was assigned by PSE&G to Power in conjunction with the generation-related asset transfer in August 2000. The contract provided for PSE&G to supply ODEC with capacity and energy for a bundled rate that includes a component to recover a charge for use of the PSE&G transmission system. In November 1997, FERC issued the PJM Restructuring Order, which required PSE&G to modify its contract with ODEC to remove a transmission rate. FERC reasoned that PSE&G's transmission rate (which FERC imputed to the contract) together with Delmarva Power and Light Company's transmission
charge for delivery of the subject capacity and energy represented “pancaked” transmission rates in violation of FERC transmission pricing policy. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rates to ODEC by approximately $6 million per year, effective April 1, 1998. In 2000,
FERC issued its order denying PSE&G's request for rehearing. Thereafter,
PSE&G successfully appealed the matter. In December 2002, based on a U.S.
Court of Appeals ruling in PSE&G's favor, FERC issued its Order on Remand
which reversed its November 1997 order, thereby reinstating the original contract
terms. Since ODEC did not seek rehearing, that order became final. This allowed
Power to collect amounts for April 1998 through December 2002 pursuant to the
original contract. Power billed ODEC for this amount in January 2003. Power
has been billing, recording and receiving payment of the original contract rate
for services provided since January 2003. ODEC is paying such increased rates
currently under protest, but has refused to pay past due amounts, aggregating
$31 million, including interest. On October 22, 2003, FERC issued its Order
Denying Motion to Reopen Proceeding dismissing ODEC's untimely petition
to reopen the matter, thereby affirming the prices in the original contract
and denying ODEC's request for reconsideration and its request for a stay.
ODEC sought rehearing of that order on November 21, 2003. ODEC has withheld
payment of the amounts due for the period prior to January 2003. Accordingly,
on November 26, 2003, Power filed suit against ODEC for breach of contract in
U.S. District Court in Newark, New Jersey. On January 29, 2004, ODEC filed a
motion to dismiss claiming that the ongoing FERC proceeding must be completed
before any judicial intervention. On February 13, 2004, Power filed a motion
for summary judgment. On July 13, 2004, FERC denied ODEC's request for a
rehearing of its October 2003 Order Denying Motion to Reopen Proceeding. ODEC
has indicated its plans to appeal FERC's July 13, 2004 Order Denying Rehearing. Guaranteed Obligations Power Power has unconditionally guaranteed payment by its subsidiary, ER&T, in certain commodity-related transactions in the ordinary course of business. These payment guarantees were provided to counterparties in order to obtain credit under physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of June 30, 2004 and December 31, 2003 was $1.7 billion and $1.4 billion, respectively.
In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T's contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The 29
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS probability of all contracts at ER&T being simultaneously “out-of-the-money” is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $418 million and $228 million as of June 30, 2004 and December 31, 2003, respectively. Of the $418 million exposure, $123 million was recorded on Power's Condensed Consolidated Balance Sheets as of June 30, 2004. Of the $228 million exposure, $167 million is recorded on Power's Condensed Consolidated Balance Sheets as of December 31, 2003. In addition, many of these agreements contain margin and/or other collateral requirements that, as of June 30, 2004, would require Power to post additional collateral of up to $636 million if Power were to lose its investment grade credit rating and all counterparties with whom Power is “out-of-the money” under such contracts, were entitled to and called for collateral. An increase in energy prices causes a commensurate increase in collateral requirements for Power. As of June 30, 2004, Power had recorded Accounts Payable margin received of approximately $82 million and recorded Accounts Receivable
margin paid of approximately $112 million. As of June 30, 2004, letters of credit issued by Power were outstanding in the amount of approximately $100 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations. Energy Holdings Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects in an aggregate amount of approximately $163 million and $180 million as of June 30, 2004 and December 31, 2003, respectively. As of June 30, 2004 and December 31, 2003, the guarantees of payment include a $42 million standby equity commitment for Elektrownia Skawina S.A. (Skawina) in Poland expiring in August 2007 and a $25 million contingent guarantee related to debt service obligations of Chilquinta expiring in 2011. As of December
31, 2003, Energy Holdings had guaranteed a $10 million equity commitment for ELCHO in Poland that expired in April 2004. Additional guarantees consist of a $35 million and $37 million leasing agreement guarantee for Prisma 2000 S.p.A. (Prisma) in Italy as of June 30, 2004 and December 31, 2003, respectively, $22 million and $24 million of performance and payment guarantees related to Energy Technologies as of June 30, 2004 and December 31, 2003, respectively, that are supported by letters of credit and expire in May 2005, and various other guarantees comprising the remaining $39 million and $35 million as of June 30, 2004 and December 31, 2003, respectively, expiring through 2010. In September 2003, Energy Holdings completed the sale of Energy Technologies and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies. As of June 30, 2004, there were $80 million of such bonds outstanding, of which $5 million related to uncompleted construction projects. These performance bonds are not included in the $163 million of guaranteed obligations discussed above. Environmental Matters PSEG, PSE&G and Power Hazardous Waste The New Jersey Department of Environmental Protection (NJDEP) adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. These 30
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective 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. However, neither PSE&G nor Power anticipate that compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows. Passaic River Site The U.S. Environmental Protection Agency (EPA) has determined that a six mile stretch of the Passaic River in 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 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating and one former generating station and four former Manufactured Gas Plants (MGPs). PSE&G's costs to clean up former MGPs are recoverable from utility customers through the Societal Benefits Charge (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities
for liabilities arising out of the site in connection with the sale. The Essex Generating Station (Essex Site) was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site. In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances were being released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G's ongoing gas operations. The EPA has estimated that its study would require five to seven years to complete and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power will evaluate recoverability of any disbursed amounts from its insurance carriers. Also, in 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 30 other PRPs, have executed an agreement with the EPA that provides for sharing the costs of the study between the government organizations and the PRPs. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. However, such costs could be material. PSE&G MGP Remediation Program PSE&G is currently working with the NJDEP under a program to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former MGP sites (Remediation Program). 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 31
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS estimated. Experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since the inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through SBC charges to utility customers. Expenditures beyond 2006 cannot be reasonably estimated based on available information and are therefore not accrued. As of June 30, 2004, PSE&G's estimated net liability for remediation costs through 2006 totaled $123 million. For further discussion related to this matter, see “Passaic River Site” above. Power Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government is seeking to order companies it alleges not to be in compliance to install the best available air pollution control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation. The EPA
and the NJDEP issued a demand to PSE&G in March 2000 under the CAA requiring
information to assess whether projects completed since 1978 at the Hudson and
Mercer coal burning units were implemented in accordance with applicable PSD/NSR
regulations. Power completed its response to the requests for information and,
in January 2002, reached an agreement with New Jersey and the Federal government
to resolve allegations of noncompliance with Federal and New Jersey PSD/NSR
regulations. Under that agreement, over the course of 10 years, Power must install
advanced air pollution controls that are designed to reduce emissions of Nitrogen
Oxide (NOx),
Sulfur Dioxide (SO2),
particulate matter and mercury. The estimated cost
of the program at this time includes approximately $110 million for installation
of selective catalytic reduction systems (SCRs) at Mercer, approximately
$80 million of which has been spent,
as well as approximately $300 million to $350 million at the Hudson unit and
$150 million to $200 million for other pollution control equipment at Mercer
to be installed by December 31, 2012. Power
also paid a $1.4 million civil penalty and has agreed to spend up to $6 million
on supplemental environmental projects. The agreement resolving the NSR allegations
concerning the Hudson and Mercer coal-fired units also resolved a dispute over
Bergen 2 regarding the applicability of PSD requirements and allowed construction
of the unit to be completed and operations to commence. Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications to the unit. A decision has not yet been made as to the Hudson unit's continued operation beyond the December 31, 2006 deadline for installation of pollution control equipment. The related costs associated with the pollution control modifications for the Hudson unit have not been included in Power's capital expenditure projections. In March
2004, the third-party contractor retained by Power to design, construct and
install the SCRs at Mercer, required under the agreement with the EPA and the
NJDEP, revised its construction schedule to indicate that substantial completion
of the SCR for one of the Mercer units would not occur until after the date
specified in the agreement. Power notified the EPA and NJDEP and agreed with
the agencies to resolve the delayed operation of one of the SCRs by early operation
of the other SCR. Power assumed responsibility for completion of the construction
and terminated the third-party contractor. The SCRs are in the final stages
of construction and both Mercer units are currently in operation. 32
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Generation and Development Power and Energy Holdings Completion of the projects discussed below, within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete. Power Power is constructing the Bethlehem Energy Center, which will replace the Albany Station. Total costs for this project are expected to be approximately $500 million with expenditures to date of approximately $377 million. Construction began in 2002 with the expected completion date in mid-2005, at which time the existing station will be retired. Power is constructing a natural gas-fired generation plant in Linden, New Jersey. Power is currently investigating and assessing corrosion that was recently detected on the tubes in both steam turbine condensers. Power anticipates that the tubes will need to be replaced which will delay the scheduled commercial operation date to 2006. Including the replacement of the tubes, the total costs are currently estimated at approximately $830 million with expenditures to date of approximately $682 million. Power has constructed a natural gas-fired generation plant in Lawrenceburg, Indiana, which achieved commercial operation in June 2004. Power also has contracts with outside parties to purchase upgraded turbines for the Salem Nuclear Generating Station (Salem) Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek Generating Station (Hope Creek) to modestly increase its generating capacity. Salem Unit 1's turbine replacement was completed in June 2004 and increased output by 63 MW. The power uprate for Hope Creek is currently scheduled to be completed by 2006, assuming timely approval from the Nuclear Regulatory Commission (NRC). The remaining turbine replacements are currently scheduled to be complete during planned refueling outages in 2006 for Hope Creek and 2008 for Salem Unit 2. Power's aggregate estimated share of the costs for these projects
are $228 million, with expenditures to date of approximately $135 million. Power has entered into a long-term contractual services agreement with a vendor to provide the outage and service needs for certain of Power's generating units at market rates. The contract covers approximately twenty-five years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered. Energy Holdings Poland In 2002, Global acquired a controlling interest in the electric and thermal coal-fired Skawina plant. In accordance with the purchase agreement, Global is obligated to offer to purchase an additional 12% from Skawina's employees in 2004, increasing Global's potential ownership interest to approximately 75%. The transaction will require an additional investment of approximately $8 million and is expected to close in the third quarter of 2004. In addition, as of June 30, 2004, Global had approximately $42 million of equity commitment guarantees related to the modernization of the plant for environmental upgrades over an eight-year period, which could increase Global's total equity investment to $99 million. However, Global expects that cash generated from Skawina's operations will be sufficient to fund all
such modernization costs. Other There are additional minor capital projects at certain of Global's subsidiaries that are expected to be funded locally. Included in these projects is a 45 MW generation project at SAESA, which is 33
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS designed to reduce risk associated with SAESA's electric supply commitments, with completion expected in 2004 at an estimated total cost of approximately $15 million. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G and Power PSE&G is required to obtain all of its basic generation energy supply needs through the New Jersey BGS auctions for its customers that are not served by a third-party supplier. PSE&G has entered into contracts with Power, as well as with third-party suppliers, to purchase BGS for PSE&G's anticipated load requirements. In addition, PSE&G has a full requirements contract with Power under which Power will provide PSE&G with its gas supply through 2007. Power Power's objective is to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. As part of this objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDCs) with a portion of their BGS requirements, through the New Jersey BGS auction process. In addition to the BGS related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania, Connecticut and Maryland, as well as other firm sales and trading positions and commitments, including 34-month contracts ending May 31, 2006, to supply energy and capacity to third parties supplying electricity to New Jersey EDCs. Minimum Fuel Purchase Requirements Power Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $370 million through 2009. Power has various multi-year requirements-based purchase commitments that total approximately $97 million per year to meet Salem's and Hope Creek's nuclear fuel needs, of which Power's share is approximately $70 million per year through 2008. Power has been advised by Exelon Generation LLC (Exelon), the co-owner and operator of the Peach Bottom Atomic Power Station (Peach Bottom), that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom through 2008, of which Power's share is approximately $35 million per year. In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations. As of June 30, 2004, the total minimum requirements under these contracts were approximately $756 million through 2016. Nuclear Fuel Disposal Power Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of 34
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2010. Pursuant
to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor
facility storage pools or in independent spent fuel storage installations located
at reactors or away-from-reactor sites for at least 30 years beyond the licensed
life for reactor operation (which may include the term of a revised or renewed
license). Adequate spent fuel storage capacity is
estimated to be available
through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has
commenced construction of an on-site storage facility that will satisfy the
spent fuel storage needs of both Salem and Hope Creek through the end of their
current respective license lives. Exelon has advised Power that it has a licensed
and operational on-site storage facility at Peach Bottom that will satisfy Peach
Bottom's spent fuel storage requirements until at least 2014. Exelon
had previously advised Power that it had signed an agreement with the DOE applicable
to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting
from the DOE's delay in accepting spent nuclear fuel for permanent storage.
Under this agreement, Power's portion of Peach Bottom's Nuclear Waste
Fund fees were reduced by approximately $18 million through August 31, 2002,
at which point the credits were fully utilized and covered the cost of Exelon's
on-site storage facility. In September 2002, the U.S. Court of Appeals for the
Eleventh Circuit issued an opinion upholding a petition seeking to set aside
the receipt of these credits by Exelon. On August 14, 2003, Exelon received
a letter from the DOE demanding repayment of previously received credits from
the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5
million of accrued interest (100% share). Power continues
to believe that it is the Federal government's obligation to pay for storage
related costs due to DOE's failure to take possession of the spent nuclear
fuel. Further, Power also believes
that any current payments potentially required relating to the past Nuclear
Waste Fund fees (with the exception of approximately $1.5 million of accrued
interest) will ultimately be recovered and, accordingly, no amounts have been
accrued. Exelon has advised Power that it filed suit in January 2004 in the
U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession
of spent nuclear fuel in 1998. In
September 2001, Power filed a complaint in the U.S. Court of Federal Claims
seeking damages caused by the DOE not taking possession of spent nuclear fuel
in 1998. No assurances can be given as to any damage recovery or the ultimate
availability of a disposal facility. In May 2004, in a case involving another
utility seeking to recover damages for DOE's failure to take possession
of nuclear fuel, the U.S. Court of Federal Claims denied recovery of costs of
that utility to store nuclear fuel on-site. An appeal is expected. In
October 2001, Power filed a complaint in the U.S. Court of Federal Claims, along
with a number of other plaintiffs, seeking $28 million in relief from past overcharges
by the DOE for enrichment services. No assurances can be given as to any damage
recovery. Spent Fuel Pool Leakage Power The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building's concrete structure. Power is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs could be material. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter. 35
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Elevated concentrations of tritium in the shallow groundwater near Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power is conducting a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power has conducted initial remedial pilot studies and submitted a workplan to the NJDEP in July 2004 for the proposed remedy. The costs necessary to address this groundwater contamination issue are not known fully, however, such costs are not expected to be material. Other PSEG and PSE&G Investment Tax Credits (ITC) As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets' regulatory lives, which were terminated upon New Jersey's electric industry restructuring. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G's generation assets that were transferred to Power and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. PSE&G was directed by the BPU to seek a ruling from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax
normalization rules of the Internal Revenue Code. PSE&G filed a private letter ruling request with the IRS in 2002, which is still pending. In 2003, the IRS proposed regulations for comment that, if adopted, would allow utilities to elect retroactive application over periods equivalent to the ones in place prior to deregulation. While PSEG cannot predict the outcome of this matter, a requirement to refund such amounts to customers could have a material adverse impact on PSEG's and PSE&G's financial condition, results of operations and net cash flows. Placement of Gas Meters In 2003, a proposed class action lawsuit was filed against PSE&G and PSEG in the Superior Court of New Jersey alleging that PSE&G's installation of outdoor gas meters within three feet of driveways or garages at residential locations is negligent. The suit also requested the court to order PSE&G to establish a fund for the purpose of remediating the allegedly improper meter installations. In June 2004, the parties to the lawsuit entered into a settlement in which PSE&G committed to enhance the protection of certain identified outdoor gas meter sets over a three-year period. PSE&G anticipates that the cost of such work will be immaterial. As a result of this settlement, the claims were dismissed
with prejudice. Energy Holdings Peru LDS The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, has claimed past-due taxes for the period between 1999-2001, plus penalties and interest, resulting from an interpretation of the law that allowed LDS to restate its assets to fair market value for tax purposes and take advantage of the resulting higher tax deductions from depreciation. SUNAT also claimed past due taxes, penalties and interest for the 1996-1998 period related to this issue. 36
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS SUNAT claimed that the revaluation study, performed in 1994, was not performed correctly and was therefore invalid. It is LDS's position that laws and regulations did not define the methodology to be used in these matters and its study was based on generally accepted practices and the only constraint was not to exceed market value. LDS's total potential liability relating to this matter is approximately $45 million, of which $18 million is currently recorded at LDS. Global's share of the net potential liability related to the claim by SUNAT is estimated at $10 million. In January 2004, the Fiscal Court in Peru ruled in favor of LDS in respect of the 1996-1998 period and ruled that the LDS studies are valid. However, the ruling allows SUNAT to present its own study to challenge the LDS studies. No assurances can be given as to the ultimate outcome of this matter. Oman Dhofar Power Company (Salalah) Since commencing
operations in May 2003, Salalah has experienced four service interruptions.
The commercial agreement for the project includes a provision for penalties
to be paid in some circumstances to the customer when there is a service interruption.
Energy Holdings believes
that letters of credit and agreed retentions of up to $3 million provided by
the contractors are sufficient to cover the potential penalty claims for 2003. Brazil RGE In 2004, the Brazilian tax authorities issued assessments to RGE claiming certain taxes, penalties and interest related to a financing transaction. Energy Holdings' share of the maximum claim amount is approximately $8 million. There is no reserve recorded on the Condensed Consolidated Financial Statements as of June 30, 2004 as RGE believes it has valid legal defenses to these claims, although no assurances can be given. PSEG, PSE&G, Power and Energy Holdings The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their respective results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term “hedge” to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance
the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices. 37
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivative Instruments and Hedging Activities Energy Trading Contracts Power Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil, weather derivatives and emission allowances in the spot, forward and futures markets, primarily in PJM, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region. Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures. Power marks its derivative energy trading contracts to market in accordance with SFAS 133, as amended, with changes in fair value charged to the Condensed Consolidated Statement of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results. Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. Commodity Contracts Power 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, market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs. Cash Flow Hedges Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. These derivative transactions are designated and effective as cash flow hedges under SFAS 133, as amended. As of June 30, 2004, the fair value of these hedges was $(287) million, $(170) million after-tax. As of December 31, 2003, the fair value of these hedges was $(37) million, $(22) million after-tax. During the next 12 months, $78 million of unrealized losses (after-tax) on these commodity derivatives in Accumulated Other Comprehensive Loss is expected
to be reclassified to earnings. As defined in SFAS 133, hedge ineffectiveness associated with these hedges was insignificant. The expiration date of the longest dated cash flow hedge is in 2008. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation 38
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of June 30, 2004 and December 31, 2003 was $22 million and $7 million, respectively. Interest Rates PSEG, PSE&G, Power and Energy Holdings PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG's policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives. Fair Value Hedges PSEG and Power In March 2004, Power issued $250 million of 3.75% Senior Notes due in 2009. PSEG used an interest rate swap to convert Power's fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of June 30, 2004, the fair value of the hedge was $(6) million and there was no ineffectiveness related to the hedge. Energy Holdings In April 2003, Energy Holdings issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings used interest rate swaps to convert $200 million of this fixed-rate debt into variable-rate debt. The interest rate swaps are designated and effective as fair value hedges. The fair value changes of these interest rate swaps are fully offset by the fair value changes in the underlying debt. As of June 30, 2004 and December 31, 2003, the fair value of these hedges was $(4) million and $(1) million, respectively, and there was no ineffectiveness related to these hedges. Cash Flow Hedges PSEG, PSE&G, Power and Energy Holdings PSEG, PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. The fair value changes of these derivatives are initially recorded in Accumulated Other Comprehensive Income (OCI). As of June 30, 2004, the fair value of these cash flow hedges was $(137) million, including $(12) million, $(37) million, and $(88) million at PSEG, PSE&G, and Energy Holdings, respectively. As of December 31, 2003, the fair value of these cash flow hedges was $(186) million, including $(16) million, $(51) million, $(7) million and $(112) million at PSEG, PSE&G, Power and Energy Holdings. The $(37) million
at PSE&G as of June 30, 2004 is not included in Accumulated Other Comprehensive Loss and is deferred and expected to be recovered from PSE&G's customers. During the next 12 months, $27 million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified to earnings, including $4 million and $23 million at PSEG and Energy Holdings, respectively. As of June 30, 2004, hedge ineffectiveness associated with these hedges was immaterial. 39
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Other Derivatives Energy Holdings Foreign subsidiaries and affiliates of Energy Holdings have entered into interest rate forward contracts, which effectively converted variable-rate debt to fixed-rate debt. Since these contracts have not been designated as fair value hedges, changes in the fair value of these derivative instruments are recorded directly to Interest Expense. The fair value of these instruments as of June 30, 2004 and December 31, 2003, was immaterial. Foreign Currencies Energy Holdings Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso.
With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations. As of June 30, 2004, net cumulative foreign currency devaluations have reduced the total amount of Energy Holdings' Member's Equity by $276 million, including $238 million caused by the devaluation of the Brazilian Real. As of December 31, 2003, net cumulative foreign currency devaluations have reduced the total amount of Energy Holdings' Member's Equity by $193 million, including $228 million caused by the devaluation of the Brazilian Real. Cash Flow Hedges Affiliates of Energy Holdings purchase forward-exchange contracts as hedges of anticipated payments to contractors for projects under construction. These contracts are designed to hedge against the risk that the future cash payments will be adversely affected by changes in foreign currency rates. As of June 30, 2004 and December 31, 2003, Energy Holdings' pro-rata share of the fair value on the forward-exchange contracts was $8 million and $5 million, respectively. There was no ineffectiveness associated with these hedges. Hedges of Net Investments in Foreign Operations Energy Holdings In April 2004 and March 2004, Energy Holdings entered into three cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure in the U.S. Dollar to Chilean Peso exchange rate. As of June 30, 2004, the fair value of the cross-currency swaps was $3 million. The effective portion of the change in fair value is recorded in Cumulative Translation Adjustment within Accumulated Other Comprehensive Loss. 40
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Equity Securities Energy Holdings For the quarter and six months ended June 30, 2004, Resources recognized a $1 million (pre-tax) gain and $2 million (pre-tax) loss, respectively, related to non-publicly traded equity securities, which are held within its investments in certain venture capital and leveraged buyout funds. For the quarter ended June 30, 2003, Resources recognized a $10 million (pre-tax) loss due to an other than temporary impairments of non-publicly traded equity securities. For the six months ended June 30, 2003, Resources had a $4 million (pre-tax) loss, which is comprised of the $10 million other than temporary impairment, which was partially offset by a $6 million gain recognized on the publicly traded equity securities within those funds. As of June 30, 2004, Resources had investments in leveraged buyout funds of approximately $45 million,
of which $22 million was comprised of public securities with available market prices and $23 million was comprised of privately-held interests in certain companies. As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $75 million, of which $26 million was comprised of public securities with available market prices and $49 million was comprised of privately held interests in certain companies. Note 9. Comprehensive Income, Net of Tax For the Quarter Ended June 30, 2004: Net Income (Loss) Other Comprehensive (Loss) Income Comprehensive Income (Loss) For the Quarter Ended June 30, 2003: Net Income (Loss) Other Comprehensive Income Comprehensive Income (Loss) For the Six Months Ended June 30, 2004: Net Income (Loss) Other Comprehensive Loss Comprehensive Income (Loss) For the Six Months Ended June 30, 2003: Net Income (Loss) Other Comprehensive Income Comprehensive Income (Loss) Note 10. Changes in Capitalization PSE&G In June 2004, PSE&G issued $175 million two-year floating rate Medium-Term Notes secured by an equal amount of its First and Refunding Mortgage Bonds. The interest is set quarterly at LIBOR 41
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS plus 0.125%. The proceeds of this issuance were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014. In June 2004 and March 2004, Transition Funding repaid approximately $30 million and $32 million, respectively, of its transition bonds. In May 2004, $286 million of 6.50% Series PP First and Refunding Mortgage Bonds matured. Power In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds, together with other available cash, were used to fund the repayment of $800 million of project finance debt of certain of Power's subsidiaries. Energy Holdings In May 2004, Energy Holdings redeemed $75 million of preference units owned by PSEG and paid a distribution to PSEG of $75 million. During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007, reducing the aggregate amount of that security outstanding to $309 million. In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity, utilizing cash on hand and redeemed $75 million of preference units owned by PSEG. 42
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 11. Other Income and Deductions Other Income: For the Quarter Ended June 30, 2004: Interest Income NDT Funds Realized Gains NDT Interest and Dividend Income Change in Derivative Fair Value Other Total Other Income For the Quarter Ended June 30, 2003: Interest Income NDT Funds Realized Gains NDT Interest and Dividend Income Foreign Currency Income Other Total Other Income For the Six Months Ended June 30, 2004: Interest Income Disposition of Property NDT Funds Realized Gains NDT Interest and Dividend Income Change in Derivative Fair Value Other Total Other Income For the Six Months Ended June 30, 2003: Interest Income Disposition of Property NDT Funds Realized Gains NDT Interest and Dividend Income Foreign Currency Income Other Total Other Income 43
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Other Deductions: For the Quarter Ended June 30, 2004: NDT Funds Realized Losses and Expenses Foreign Currency Losses Loss on Early Extinguishment of Debt Other Total Other Deductions For the Quarter Ended June 30, 2003: NDT Funds Realized Losses and Expenses Minority Interest Change in Derivative Fair Value Other Total Other Deductions For the Six Months Ended June 30, 2004: Donations NDT Funds Realized Losses and Expenses Foreign Currency Losses Loss on Early Extinguishment of Debt Minority Interest Other Total Other Deductions For the Six Months Ended June 30, 2003: Donations NDT Funds Realized Losses and Expenses Minority Interest Change in Derivative Fair Value Total Other Deductions 44
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS An analysis of the tax provision expense is as follows: For the Quarter Ended June 30, 2004: Income (Loss) before Income Taxes Tax computed at the statutory rate Increase (decrease) attributable to flow through of certain tax adjustments: State Income Taxes after Federal Benefit Rate Differential of Foreign Operations Plant Related Items Lease Rate Differential Other Total Income Tax Expense (Benefit) Effective income tax rate For the Quarter Ended June 30, 2003: Income (Loss) before Income Taxes Tax computed at the statutory rate Increase (decrease) attributable to flow through of certain tax adjustments: State Income Taxes after Federal Benefit Rate Differential of Foreign Operations Plant Related Items Other Total Income Tax (Benefit) Expense Effective income tax rate For the Six Months Ended June 30, 2004: Income (Loss) before Income Taxes Tax computed at the statutory rate Increase (decrease) attributable to flow through of certain tax adjustments: State Income Taxes after Federal Benefit Rate Differential of Foreign Operations Plant Related Items Lease Rate Differential Other Total Income Tax Expense (Benefit) Effective income tax rate For the Six Months Ended June 30, 2003: Income (Loss) before Income Taxes Tax computed at the statutory rate Increase (decrease) attributable to flow through of certain tax adjustments: State Income Taxes after Federal Benefit Rate Differential of Foreign Operations Plant Related Items Other Total Income Tax Expense (Benefit) Effective income tax rate 45
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 13. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below: For the Quarter Ended June 30, 2004: Total Operating Revenues Income (Loss) from Continuing Operations Income from Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets For the Quarter Ended June 30, 2003: Total Operating Revenues Income (Loss) from Continuing Operations Loss from Discontinued Operations, net of tax Extraordinary Item, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets For the Six Months Ended June 30, 2004: Total Operating Revenues Income (Loss) from Continuing Operations Income from Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets For the Six Months Ended June 30, 2003: Total Operating Revenues Income (Loss) from Continuing Operations Loss from Discontinued Operations, net of tax Extraordinary Item, net of tax Cumulative Effect of a Change in Accounting Principle, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets As of June 30, 2004: Total Assets Investments in Equity Method Subsidiaries As of December 31, 2003: Total Assets Investments in Equity Method Subsidiaries (footnotes on next page) 46
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (footnotes from previous page) Note 14. Related-Party Transactions The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. BGSS and BGS Contracts PSE&G and Power Effective May 1, 2002, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements. In addition, Power was a participant in the BGS auctions held in February 2003 and February 2004. As a result of this participation, Power entered into contracts to supply energy, capacity and ancillary services to PSE&G. The amounts which Power charged to PSE&G for BGS and BGSS, and the related receivable are presented below: BGS BGSS Market Transition Charge (MTC) PSE&G and Power Power charged PSE&G approximately $53 million and $101 million for the MTC for the quarter and six months ended June 30, 2003, respectively. Effective August 1, 2003, Power ceased charging the MTC. Affiliate Loans PSEG and Power As of June 30, 2004 and December 31, 2003, Power had a (payable to) receivable from PSEG of approximately $(191) million and $77 million, respectively, reflecting short-term funding activity with 47
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG. Interest that Power paid to, or received from, PSEG related to the short-term funding activity was immaterial. PSEG and Energy Holdings As of June 30, 2004 and December 31, 2003, Energy Holdings had a note receivable due from PSEG of $169 million and $300 million, respectively, reflecting the investment of its excess cash with PSEG. Interest income Energy Holdings received from PSEG related to this intercompany transaction was immaterial. Energy Holdings Loans to Texas Independent Energy, L.P. (TIE) Global and its partner, TECO Energy, Inc. (TECO), own and operate two 1,000 MW electric generation facilities in Texas through TIE, a 50/50 joint venture. As of June 30, 2004, Global had outstanding approximately $68 million of loans to TIE that earn interest at an annual rate of 12% and that are scheduled to be repaid in quarterly installments through 2012. The quarterly loan installments due to Global are expected to be repaid out of the project cash flows or additional contributions from project partners in the event of insufficient project cash flows. As of June 30, 2004, approximately $12 million has been repaid to Global. For each of the quarters ended June 30, 2004 and 2003, Global recorded approximately $2 million of interest income related to this loan. For each of the six-month periods ended June 30, 2004 and
2003, Global recorded approximately $4 million of interest income related to this loan. In March 2003, Global funded $14 million of convertible preferred equity to the two TIE projects as part of its negotiations with project lenders to amend the projects' credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global's option into an approximate 13% additional equity interest. There were insufficient operating funds at TIE to meet the payments required by June 30, 2004 under the loan agreement and, as a result, the partners were required to contribute capital into the project. However, TECO did not provide funds to fulfill its portion of the obligation and therefore TIE is in default on the loan. For additional information regarding TIE, see Note 16. Subsequent Events. Other As of June 30, 2004, Global had loans outstanding with its affiliates of approximately $59 million, including $19 million of accrued interest related to its projects in Italy. 48
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Services PSE&G, Power and Energy Holdings Services provides and bills administrative services to PSE&G, Power and Energy Holdings as follows: PSE&G Power Energy Holdings These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings each believes that the costs of services provided by Services approximates market value for these services. Power During the six months ended June 30, 2004, Power sold certain maintenance facilities to Services at net book value, resulting in proceeds of approximately $4 million. Tax Sharing Agreement PSEG, PSE&G, Power and Energy Holdings PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of PSE&G, Power and Energy Holdings. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows: PSE&G Power Energy Holdings All of Power's Senior Notes and pollution control bonds aggregating a total of $3.3 billion are fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries, as well as Power's non-guarantor subsidiaries. 49
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Operating Revenues Operating Expenses Operating Income (Loss) Other Income Other Deductions Equity Earnings (Losses) of Subsidiaries Interest Expense Income Taxes Net Income (Loss) Operating Revenues Operating Expenses Operating Income Other Income Other Deductions Equity Earnings (Losses) of Subsidiaries Interest Expense Income Taxes Net Income (Loss) Operating Revenues Operating Expenses Operating Income (Loss) Other Income Other Deductions Equity Earnings (Losses) of Subsidiaries Interest Expense Income Taxes Net Income (Loss) Operating Revenues Operating Expenses Operating Income Other Income Other Deductions Equity Earnings (Losses) of Subsidiaries Interest Expense Income Taxes Cumulative Effect of a Change in Accounting Principle, net of tax Net Income (Loss) 50
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Net Cash (Used In) Provided By Operating Activities Net Cash Provided By (Used In) Investing Activities Net Cash (Used In) Provided By Financing Activities Net Cash Provided By (Used In) Operating Activities Net Cash (Used In) Provided By Investing Activities Net Cash Provided By (Used In) Financing Activities Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Note Payable—Affiliated Company Long-Term Debt Member's Equity Total Liabilities and Member's Equity Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Note Payable—Affiliated Company Long-Term Debt Member's Equity Total Liabilities and Member's Equity Energy Holdings TIE In June 2004, Global notified TECO of its intent to convert a fractional amount of its preferred equity into common equity in TIE on July 1, 2004, and thereby gain majority control of the TIE 51
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS partnership. Subsequent to this notification, TECO indicated a desire to transfer its entire interest in TIE to Global. On July 27, 2004, Global signed an agreement to acquire all of TECO's interests in TIE, for a nominal value. With this purchase, which is subject to regulatory approvals, Global will own 100% of TIE. For additional information, see Note 14. Related-Party Transactions. Changes in Capitalization In July 2004, Energy Holdings redeemed $75 million of preference units owned by PSEG. 52
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL Following are the significant changes in or additions to information reported in the 2003 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2004 affecting the consolidated financial condition and the results of operations. This discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes. This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no representations as to any other company. As discussed in Note 2. Restatement of Financial Statements of the Notes, the Condensed Consolidated Financial Statements of PSEG and Energy Holdings have been restated for the quarter and six months ended June 30, 2003. The following discussion gives effect to this restatement. PSEG PSEG's business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global LLC (Global) and PSEG Resources LLC (Resources). Based on results of the second quarter of 2004 and expectations for the balance of the year, PSEG has revised its original projections for 2004 Income from Continuing Operations from a range of $3.60 to $3.80 per share to a range of $3.15 to $3.35 per share. The reduction in the earnings projection was primarily due to lower than expected earnings from Power, discussed below. PSEG is preparing its annual business plan for 2005 and no longer expects 2005 earnings to be flat to its original 2004 guidance of $3.60 to $3.80 per share. PSEG cannot provide any
guidance beyond 2004 until its planning process is completed. However, it appears that several 2004 factors will carry over into 2005, including higher nuclear and fossil operations and maintenance costs, more modest revenue from trading activities and ongoing impacts from the transformer outage, discussed below. Given the volatility of the power sector, the competitiveness of the wholesale markets, current historically low capacity prices and the uncertainty of investment opportunities, it has become more difficult to accurately predict future results. As a result
of the reduced earnings projections, combined with the timing of certain tax
benefits, PSEG anticipates that it will have cash requirements, after dividends
and capital expenditures, of approximately $100 million for
2004, not including net proceeds from asset sales. PSEG expects operating cash
flows beyond 2004 to be sufficient to fund its investments and meet dividend
requirements and may employ any excess cash to reduce debt, invest in its businesses,
increase dividends or repurchase stock over the long-term. PSEG's Board of Directors has approved a quarterly dividend rate of $0.55 per share for the first three quarters of 2004. This reflects an indicated annual dividend rate of $2.20 per share. Dividend payments on common stock for the quarter and six months ended June 30, 2004 totaled approximately $130 million and $260 million, respectively. PSEG will continue to evaluate its dividend payments and will consider modest increases in the future. Beginning on June 1, 2004, a greater portion of Power's Operating Revenues are earned through load serving supply contracts with its affiliate, PSE&G. Power's Operating Revenues related to the contracts are eliminated against the corresponding Energy Costs at PSE&G when preparing PSEG's Condensed Consolidated Statements of Operations. As a result, there will be a decrease in PSEG's future Operating Revenues and Energy Costs as compared to current levels. 53
PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. As such, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. In February 2004, the BPU approved the results of the New Jersey's third annual basic generation service (BGS) auction process and PSE&G successfully secured contracts to provide the electricity requirements for its customer's needs. The cost of energy supply, for both gas and electricity, is passed through from PSE&G to its customers. PSE&G has revised its expected Income from Continuing Operations for 2004 to range from $340 million to $360 million, a $20 million increase over its original projections primarily due to increased sales volumes due to electric load growth in its territory and favorable weather conditions compared to the original assumptions used in PSE&G's projections. PSE&G's future success will be dependent, in part, on its ability to maintain a reasonable rate of return under its regulated rate structure, continue cost containment initiatives and continue recovery of its regulatory assets. PSE&G's focus is to maintain system reliability and safety levels while it enhances the operations of its electric and gas transmission and distribution systems. Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana (Super Region). Power's principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading and enhance its ability to produce low cost energy through efficient nuclear operations and pursue modest growth in the Super Region based on market conditions. Power has revised its expected Income from Continuing Operations for 2004 from a range of $400 million to $450 million to a range of $300 million to $350 million primarily due to a series of factors related to its nuclear and fossil operations, impacts due to recent market pricing and electric transmission congestion, including replacement power costs, and results of its trading operations. With respect to nuclear operations, Power's results were negatively impacted by unanticipated and extended outages at its Hope Creek and Salem stations. These outages were the result of necessary repair and maintenance work, which is expected to improve long-term operating performance. For the
quarter and six month periods ended June 30, 2004, the aggregate capacity factor of Power's nuclear generating stations was approximately 77% and 85%, respectively, as compared to planning assumptions of approximately 89% and 93%, respectively. For the entire year, Power anticipates a capacity factor of 86%. In addition, Power's fossil operations were negatively impacted by unanticipated outages at its Hudson station and extended outages at its Mercer station. The Mercer extension was due to a delay in the return to service following the installation of new technology to reduce NOx emissions. The outages referenced above have caused an increase of approximately $9 million in Operation and Maintenance expenses. The outages
mainly occurred in April and May during warmer weather periods that led
to increased prices and increased electric demand
volumes. During the second quarter of 2004, market
prices were over $42 per MWh, more than 20% higher than the comparable period
in 2003. These outages required the purchase of replacement power in the market
to satisfy Power's contracted obligations to serve load and supply power,
which increased Energy Costs by approximately $65 million for the quarter, including
approximately $20 million
for congestion costs. Congestion costs result from the transmission system being
unable to use available lower-cost power due to physical constraints on the
system. During much of this period, the price of replacement power was significantly
impacted by higher than expected congestion costs. Power believes that a large
portion of the congestion costs was related to the derating of an electric transformer
maintained by PSE&G, which is
in the PJM Interconnection, L.L.C. (PJM) system, and
is being replaced, with an
expected return to service
in June 2005 as posted
on the PJM OASIS website. 54
As a result, the cost to serve load in the area
around the transformer being replaced has increased disproportionally to the
revenues earned from Power's generating facilities. Further impacting forecasted
2004 results for Power is the reduction in the year-to-date trading results
versus expectations. Year-to-date events, coupled
with the anticipated expansion of the Hope Creek refueling outage scheduled
for later this year, have contributed to the revision in expected Income from
Continuing Operations. The Waterford
and Lawrenceburg facilities in the Midwest have experienced a very low capacity
factor due to oversupply in the market, and therefore have only provided modest
revenue. Power cannot predict when these market conditions will improve. Some of
the issues discussed above are expected to carry over into 2005 and beyond.
Power's future success as an energy provider
depends, in part, on its ability to meet its obligations under its full requirements
contracts efficiently and profitably and the efficient operation of its low-cost
nuclear and coal generation facilities. Power's ability to meet its forecasts
will continue to be impacted by low capacity prices due to the oversupply of
electric generation capacity and the resulting competition combined with volatile
prices and conditions in energy and fuel markets, including increasing commodity
and transportation costs. Events such as those experienced in the first half
of the year will have a negative impact on Power's results of operations.
The amounts related to the outages discussed above may not be indicative of
any future costs, which could be higher or lower depending upon various factors,
including seasonality, availability of alternate generation and sources, congestion,
demand, fuel prices and hedging activities. Power's objective is to enter into load serving supply contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. To achieve its objective, Power entered into 12-month and 36-month contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their BGS requirements through the BGS auction process. In addition to these contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania, Connecticut and Maryland and other firm sales and trading positions and commitments. Power expects to take advantage of similar opportunities elsewhere in the Super Region. Energy Holdings Energy Holdings, through Global, owns and operates generation and distribution facilities in international and U.S. markets. The generation plants sell power under long-term agreements, as well as on a merchant basis, while the distribution companies are rate-regulated enterprises. Through Resources, Energy Holdings invests in energy-related financial transactions, including leveraged leases, which are designed to produce predictable earnings and cash flows. Energy Holdings continues to limit its capital spending during 2004 to existing contractual commitments and to place an emphasis on improved performance of existing businesses. Energy Holdings continues to expect Income from Continuing Operations for 2004 to range from $130 million to $150 million. Global's success depends, in part, on its ability to mitigate risks presented by its international strategy, such as the economic, regulatory and political conditions in certain countries where Global has investments. Global may restructure certain projects and is reviewing its portfolio, seeking to opportunistically monetize investments that may no longer have a strategic fit. In keeping with this strategy, during the second quarter of 2004, Global completed the sale of its investment in Carthage Power Company (CPC), a generating
facility in Rades, Tunisia and sold a portion of its shares in Luz del Sur S.A.A. (LDS), a power distribution company in Peru. Resources has shifted its focus from new investments to maintaining its current investment portfolio. Resources' objective is to produce predictable cash flows, earnings and related tax benefits while monitoring credit concerns with respect to certain lessees in its portfolio. Resources' ability to realize tax benefits associated with its leveraged lease investments is dependent upon operating gains generated by its affiliates. In April 2004, Resources closed on the termination of its lease with Edison Mission Energy (EME) in the Collins generating facility. This transaction strengthened the credit quality of Resources' remaining exposure with EME. 55
During 2004, Energy Holdings has used cash from operations and proceeds from the termination of the Collins lease and other asset sales to meet its scheduled debt maturity of $267 million in February 2004, pay $300 million of ordinary unit distributions and preferred unit redemptions to PSEG through July 2004 and for the early retirement of $41 million of debt, reducing its next maturity in 2007 to $309 million. The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2004 and 2003 are presented below: Earnings (Losses) PSE&G Power Energy Holdings: Resources Global Other (A) Other (B) PSEG Income from Continuing Operations Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal (C) Extraordinary Item (D) Cumulative Effect of a Change in Accounting PSEG Net Income PSE&G Power Energy Holdings: Resources Global Other (A) Other (B) PSEG Income from Continuing Operations Income (Loss) from Discontinued Operations, including Gain (Loss) on Disposal (C) Extraordinary Item (D) Cumulative Effect of a Change in Accounting PSEG Net Income (footnotes continued on next page) 56
(footnotes continued from previous page) The $37 million, or $0.19 per share, decrease in Income from Continuing Operations for the quarter was primarily due to lower earnings at Power primarily due to the loss of Market Transition Charge (MTC) revenues effective August 1, 2003, at the expiration of the transition period, and due to higher replacement power, congestion costs and other outage related costs in the current period, discussed above, partially offset by higher net realized gains from Power's Nuclear Decommissioning Trust (NDT) Funds and improved earnings at PSE&G primarily relating to increased electric base rates which were effective August 1, 2003, following
the conclusion of the electric base rate case and seasonality in those rates. The $90 million, or $0.48 per share, decrease in Income from Continuing Operations for the six months was primarily due to lower earnings at Power, for the reasons discussed above, and lower earnings at Resources, resulting from the termination of the Collins lease, partially offset by improved earnings at PSE&G primarily relating to increased electric base rates and seasonality in those rates. Included in PSEG's Net Income for the six months ended June 30, 2003 was an after-tax benefit in the amount of $370 million due to the required remeasurement of Power's nuclear and fossil decommissioning obligations under SFAS 143, which was adopted on January 1, 2003. In addition, PSE&G recorded an $18 million, after-tax, extraordinary charge in the second quarter of 2003 related to the outcome of its electric base rate case. Also contributing to the change in Net Income was Energy Holdings' Income from Discontinued Operations of $5 million for the quarter and six months ended June 30, 2004, as compared to Loss from Discontinued Operations of $5 million and $18 million, after tax, for the quarter and six months ended June 30, 2003. PSEG Operating Revenues Energy Costs Operation and Depreciation and Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense PSEG's results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation. For additional information on intercompany transactions, see Note 14. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow. 57
PSE&G Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Benefit (Expense) Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services. Commodity PSE&G makes no margin on commodity sales as the costs are passed through to customers with deferred accounting for the difference between costs and revenues. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for commercial and industrial customers and annually through the Basic Gas Supply Service (BGSS) tariff for residential customers. In addition, for residential customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted. Gas commodity revenues decreased $50 million and $39 million for the quarter and six months, respectively. Electric commodity prices, which are set in the annual BGS auction
process, increased $20 million and $9 million for the quarter and six months ended June 2004, respectively. Delivery Electric delivery revenues increased $119 million and $174 million for the quarter and six months ended June 2004, respectively. The base rate changes in August 2003 increased revenues by $92 million and $138 million, respectively. The balance of the increase was driven by increased sales of 7% and 5% for the quarter and six months, respectively. Less than one percent of the sales increases were weather-related. Gas delivery revenues decreased $15 million and $38 million for the quarter and six months ended June 2004, respectively. The decreases were the result of lower sales of about 4% in each period primarily due to weather. Heating degree days were 40% and 9% lower for the quarter and six months, respectively. The electric rate changes that took effect in August 2003 generally maintained the overall revenue seasonality for residential customers but significantly increased the summer/winter differential for commercial and industrial customer classes. Increases in residential tariffs were about the same amount year round while virtually all of the increase for the commercial and industrial classes occurs in the summer months. As a result, the impact of the $160 million annual base rate increase was $47 million and $63 million for the quarter and six months ended June 30, 2004, respectively, as compared to the same period in the prior year. Energy Costs Energy Costs represent the cost of electric and gas purchases necessary to meet customer load. The difference between energy costs incurred and associated commodity revenues is deferred for future collection or refund to customers. 58
The $40 million decrease in electric costs for the quarter was caused by $92 million in lower costs due to lower BGS and Non-Utility Generation (NUG) volumes offset by $52 million in higher prices for BGS and NUG purchases. The $106 million decrease in electric costs for the six months was caused by $193 million in lower costs due to lower BGS and NUG volumes offset by $86 million in higher prices for BGS and NUG purchases. The $55 million decrease in gas costs for the quarter was caused by a combination of a $114 million or 35% decrease in sales volumes offset by a $59 million or 29% increase in gas prices. The $77 million decrease in gas costs for the six months was caused by a combination of a $252 million or 21% decrease in sales volumes offset by $173 million or 19% increase in gas prices. Operation and Maintenance The $34 million increase for the quarter was primarily due to an $18 million reduction in real estate taxes recorded in 2003 and the reversal of a $10 million reserve against a regulatory asset in 2003 that is being recovered. Demand Side Management (DSM) amortization increased $9 million, driven by increased electric expense recovery offset by decreased gas volumes. Offsetting these increases were $4 million in lower labor and fringe benefits, due primarily to better pension fund performance in 2003 resulting in lower 2004 employer contributions. The $26 million increase for the six months was primarily due to a reduction in real estate taxes of $18 million recorded in 2003 and the reversal of a $10 million reserve against a regulatory asset in 2003 that is being recovered. DSM amortization increased $16 million, driven by increased electric expense recovery offset by decreased gas volumes. Offsetting these increases were $10 million in decreased labor and fringe benefits, $5 million due to lower incentive compensation awards and lower overtime and $5 million due to lower 2004 employer pension contributions. Additional decreases include $7 million in shared services costs due to reduced technology spending and decreased gas bad debt expense of $2 million resulting from decreased sales volumes. Depreciation and Amortization The $63 million increase for the quarter was due primarily to a $57 million reduction in amortization of an excess electric distribution depreciation reserve regulatory liability, an $11 million increase in the amortization of various regulatory assets and $3 million due to increased plant in service. These increases were offset by a $7 million decrease from the use of a lower book depreciation rate for electric distribution plants, which took effect in August 2003 following the conclusion of the electric base rate case. The $124 million increase for the six months was due primarily to a $114 million reduction in amortization of an excess electric distribution depreciation reserve regulatory liability, a $17 million increase in the amortization of various regulatory assets and $6 million due to increased plant in service. These increases were offset by a $13 million decrease from the use of a lower book depreciation rate for electric distribution plants, which took effect in August 2003 following the conclusion of the electric base rate case. Other Income The $7 million decrease for the six months was due primarily to a decrease in gains on property sales of $11 million, due to lower property sales in 2004. This decrease was offset by a $4 million increase in interest income related to an affiliate loan. Interest Expense The decreases of $6 million and $7 million for the quarter and six months, respectively, were primarily due to lower interest rates and lower levels of long-term debt outstanding. For the six months, the decrease was partially offset by increased interest associated with carrying charges on certain regulatory assets. 59
Income Tax Expense The increases of $39 million and $77 million for the quarter and six months, respectively, were primarily due to higher pre-tax income in 2004 combined with lower tax benefits primarily attributable to the excess depreciation reserve adjustment in 2003. Extraordinary Item PSE&G recorded an $18 million, after-tax, extraordinary charge in the second quarter of 2003 related to the outcome of its electric base rate case. See Note 5. Extraordinary Item of the Notes for additional information. Power Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Expense Operating Revenues The $242 million decrease for the quarter was due to decreases of $161 million in generation revenues, $59 million in gas supply revenues and a decrease of $22 million in trading revenues. The $380 million decrease for the six months was due to decreases of $365 million in generation revenues and $43 million in trading revenues, which was offset by a $28 million increase in gas supply revenues. Generation The $161 million decrease in generation revenues for the quarter was primarily due to $64 million in lower revenues due mainly to decreased load being served under the fixed-priced BGS contracts, which was partially offset by revenues from new contracts and higher sales into the various power pools. Also contributing to the decrease for the quarter was the loss of MTC revenues and NDT revenues effective August 1, 2003, at the expiration of the transition period, which amounted to approximately $53 million and $7 million, respectively. In addition, Power adopted Emerging Issues Task Force (EITF) Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, “Accounting
for Derivative Instruments and Hedging Activities”, and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11), which requires gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 to be shown net when recognized in the Condensed Consolidated Statement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3, which is effective on a prospective basis for transactions occurring after September 30, 2003. Since prior periods were not restated, the effect of adopting EITF 03-11 reduced
Power's revenues by approximately $37 million for the quarter, with an equal reduction in Energy Costs, as compared to the same period in 2003. The $365 million decrease in generation revenues for the six months was primarily due to $167 million in lower revenues due to decreased load being served under the fixed-priced BGS contracts and the change to seasonal rates, which was partially offset by revenues from new contracts and higher sales into the various power pools. Also contributing to the decrease for the six months was the loss of MTC 60
and NDT revenues, which amounted to $101 million and $15 million, respectively, and the adoption of EITF 03-11, which reduced revenues by approximately $82 million for the six months. Gas Supply The $59 million decrease in gas supply revenues for the quarter was primarily due to decreased sales volumes due to warmer weather in the second quarter in 2004 as compared to the same period in 2003, which was partially offset by higher gas prices under the BGSS contract. The $28 million increase in gas supply revenues for the six months was primarily due to higher gas prices, which was partially offset by decreased sales volumes in the second quarter, as discussed above. Trading The decreases in trading revenues of $22 million and $43 million for the quarter and six months, respectively, were primarily due to market conditions. Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation, as well as purchased energy in the market and gas purchases to meet Power's obligation under its BGSS contract with PSE&G. The $106 million decrease in Energy Costs for the quarter was primarily due to a $68 million decrease in gas supply costs primarily due to decreased volumes due to warmer weather in the second quarter and a $59 million decrease in purchased power due to decreased load being served under the BGS contracts, which was offset by increased replacement power purchases and higher purchased power for new contracts. Also contributing to the decrease for the quarter was a reduction of approximately $37 million related to the adoption of EITF 03-11, as discussed above. Partially offsetting the decreases was higher fuel costs for generation of approximately $59 million, primarily related to higher gas prices. The $173 million decrease for the six months was primarily due to a $180 million decrease in purchased power due to decreased load being served under the BGS contracts, which was offset by increased replacement power costs and higher purchased power for new contracts. Also contributing to the decrease for the quarter was a reduction of approximately $82 million related to the adoption of EITF 03-11, as discussed above. Partially offsetting these decreases was higher fuel costs for generation of approximately $89 million, primarily related to higher gas prices. Gas supply costs for the six months were relatively flat as increased prices were offset by lower volumes in the second quarter due to warmer weather than the same period in 2003. Operation and Maintenance The $9 million increase in Operation and Maintenance expenses for the quarter was primarily due to higher maintenance costs due to the outages at Salem, Hope Creek and Mercer, higher costs related to the Waterford facility, which was placed into service in August 2003, and higher labor and fringe benefits. The $37 million increase in Operation and Maintenance expenses for the six months was primarily due to a $16 million increase related to the outages at Hope Creek, Salem and Mercer, increased co-owner billings of $8 million related to Power's jointly-owned facilities, $4 million of higher operation and maintenance costs related to the Waterford facility and $3 million of higher labor and fringe benefits. Depreciation and Amortization The $4 million and $8 million increases in Depreciation and Amortization for the quarter and six months, respectively, were primarily due to the Waterford facility being placed into service in August 2003 and the Lawrenceburg facility being placed into service in June 2004. 61
Other Income The $52 million and $43 million increases in Other Income for the quarter and six months, respectively, were primarily due to increased realized gains and income related to the NDT Funds. Other Deductions The $12 million increase in Other Deductions for the quarter was primarily due to higher realized losses related to the NDT Funds. The $2 million increase in Other Deductions for the six months was primarily due to an $8 million write-off of unamortized issuance costs related to the extinguishment of project financing related to Power's Waterford and Lawrenceburg facilities offset by $6 million in lower realized losses related to the NDT Funds. Interest Expense The $13 million increase in Interest Expense for the six months was due to new long-term debt financing of $300 million issued in December 2003, the early settlement of an interest rate swap related to the extinguishment of project financing related to Power's Waterford and Lawrenceburg facilities in the first quarter of 2004 and higher interest related to an affiliate loan. Partially offsetting these increases was higher capitalized interest primarily due to higher rates in 2004 versus 2003. Income Tax Expense The $52 million and $99 million decreases in Income Tax Expense for the quarter and six months, respectively, were due primarily to lower pre-tax income. Cumulative Effect of a Change in Accounting Principle Power recorded an after-tax benefit in the amount of $370 million due to the required remeasurement of Power's nuclear and fossil decommissioning obligations under SFAS 143, which was adopted on January 1, 2003. See Note 3. Recent Accounting Standards of the Notes for additional information. Energy Holdings Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense The variances in Operating Revenues, Energy Costs, Operation and Maintenance, Depreciation and Amortization and Income from Equity Method Investments are primarily attributed to Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO) placing a new generation facility in Poland in service in November 2003 and Dhofar Power Company S.A.O.C. (Salalah), a generation facility in Oman, beginning commercial operation in May 2003. The variances for these items also relate to favorable foreign currency exchange rates and higher energy sales volumes at SAESA and the fact that GWF Energy LLC (GWF Energy), which owns three generation facilities in California, was accounted for 62
under the equity method of accounting in 2004 due to a change in ownership interest as compared to 2003 when GWF Energy was consolidated. Operating Revenues The increase of $6 million for the quarter was due to higher revenues at Global of $14 million including a $20 million increase from ELCHO, a $6 million increase from Salalah, and a $6 million increase from SAESA, partially offset by a decrease of $13 million related to GWF Energy. Offsetting the increase at Global was lower revenues at Resources of $10 million primarily due to a reduction in leveraged lease income of $6 million related to the termination of the Collins lease with Midwest Generation
LLC in April 2004 combined with unrealized losses in Long-Term Investments. The increase of $29 million for the six months was due to higher revenues at Global of $52 million including a $36 million increase from ELCHO, a $22 million increase from Salalah, and an $18 million increase from SAESA, partially offset by a decrease of $22 million due to lower revenues related to GWF Energy. Offsetting the increase at Global was lower revenues at Resources of $23 million, primarily due to a realized loss of $17 million and a reduction in leveraged lease income of $6 million related
to the termination of the Collins lease. Energy Costs The increase of $7 million for the quarter was primarily due to load increases of $4 million and $3 million from ELCHO and SAESA, respectively. The increase of $18 million for the six months was primarily due to load increases of $6 million, $8 million and $5 million from ELCHO, SAESA and Salalah, respectively, offset by a decrease of $1 million from GWF Energy. Operation and Maintenance The increase of $9 million for the quarter was primarily due to increases of $5 million, $3 million and $2 million from ELCHO, SAESA, and Salalah, respectively, offset by a decrease of $2 million from GWF Energy. The increase of $23 million for the six months was primarily due to increases of $8 million, $5 million, $4 million and $3 million from ELCHO, SAESA, Salalah and Electroandes, respectively, offset by a decrease of $4 million from GWF Energy. Depreciation and Amortization The increase of $2 million for the quarter was primarily due to increases of $2 million, $1 million and $2 million from ELCHO, SAESA and Salalah, respectively, offset by a decrease of $3 million from GWF Energy. The increase of $7 million for the six months was primarily due to increases of $6 million, $1 million and $5 million from ELCHO, SAESA and Salalah, respectively, offset by a decrease of $5 million from GWF Energy. Income from Equity Method Investments The increase of $2 million for the quarter was primarily driven by the use of the equity method for GWF Energy in 2004, as discussed above. The increase of $10 million for the six months was primarily driven by $6 million related to GWF Energy and a $4 million increase from Rio Grande Energia S.A. (RGE), a distribution company in Brazil, primarily due to the write-off of certain deferred assets in 2003. 63
Other Income The decreases of $1 million and $4 million for the quarter and six months, respectively, are due primarily to the absence of foreign currency transaction gains in 2004 for RGE and SAESA. Other Deductions The increases of $8 million and $5 million for the quarter and six months, respectively, are due to a foreign currency transaction loss of $6 million and a loss on extinguishment of debt of $3 million, partially offset by changes in fair value relating to Energy Holdings' derivative instruments of $1 million and $4 million for the quarter and six months, respectively. Interest Expense The increases of $14 million and $29 million for the quarter and six months, respectively, are due to an increase in non-recourse debt at the project level with higher interest rates, offset in part by the repayment of lower rate debt at Energy Holdings during 2003 and 2004. Income Tax Expense The decreases of $12 million and $10 million for the quarter and six months, respectively, are primarily due to lower pretax income. In addition, the decrease for the quarter is due to a lower effective rate for Global due to a change in mix of domestic and international earnings. Income (Loss) From Discontinued Operations CPC On May 21, 2004, Global completed the sale of its interest in CPC for approximately $43 million in cash and recognized a gain on disposal of $5 million. See Note 4. Discontinued Operations and Dispositions of the Notes for additional information. Energy Technologies In September 2003, Energy Holdings completed the sale of the remaining companies of Energy Technologies. See Note 4. Discontinued Operations and Dispositions of the Notes for additional information. Other To supplement the Condensed Consolidated Financial Statements presented in accordance with accounting principles generally accepted in the U.S. (GAAP), PSEG and Energy Holdings use the non-GAAP measure of Earnings Before Interest and Taxes (EBIT). PSEG's and Energy Holdings' management reviews EBIT internally to evaluate the performance and manage operations and believe that the inclusion of this non-GAAP financial measure provides consistent and comparable measures to help shareholders understand current and future operating results. PSEG and Energy Holdings urge shareholders to carefully review the GAAP financial information included as part of this Quarterly Report. 64
Global The following table summarizes Global's capital at risk, net contributions to EBIT and non-recourse interest in the following regions for the quarter and six months ended June 30, 2004 and 2003. Region: North America Latin America Asia Pacific Europe India and Oman Global G&A—Unallocated Total Total Global EBIT Interest Expense Income Taxes Minority Interests Income from Continuing Operations LIQUIDITY AND CAPITAL RESOURCES The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG's three direct operating subsidiaries, PSE&G, Power and Energy Holdings. Operating Cash Flows PSEG PSEG's operating cash flow increased approximately $246 million for the six months ended June 30, 2004, as compared to the six months ended June 30, 2003, due primarily to increases of $221 million at PSE&G and $217 million at Energy Holdings, offset by a $207 million decrease at Power. PSE&G PSE&G's operating cash flow increased approximately $221 million for the six months ended June 30, 2004, as compared to the six months ended June 30, 2003, due to higher net income (primarily related to the increase in electric base rates), additional recoveries of regulatory assets and reduced benefit plan contributions. Power Power's operating cash flow decreased approximately $207 million for the six months ended June 30, 2004, as compared to the six months ended June 30, 2003, due primarily to decreased income 65
from continuing operations, primarily due to lower sales volumes and higher replacement power and maintenance costs combined with the loss of the MTC revenues, effective August 1, 2003. Energy Holdings Energy Holdings' operating cash flow increased approximately $217 million for the six months ended June 30, 2004, as compared to the six months ended June 30, 2003, due primarily to a tax payment of $115 million made in 2003 related to two terminated leveraged lease transactions at Resources in 2002 and increased tax benefits received from PSEG in 2004. Common Stock Dividends Dividend payments on common stock for the quarter ended June 30, 2004 were $0.55 per share and totaled approximately $130 million. Dividend payments on common stock for the six months ended June 30, 2004 were $1.10 per share and totaled approximately $260 million. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. Debt Covenants PSEG, PSE&G, Power and Energy Holdings PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders could refuse to continue to advance funds in the event of a material adverse change in the borrower's business or financial condition. However, the PSEG and PSE&G credit agreements' material adverse change clauses do not apply when the borrowing is used to repay its commercial paper obligations. As explained in detail below, some of these credit agreements also contain maximum debt-to-equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios noted below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity measure. The debt underlying the trust preferred securities of PSEG, which is presented in Long-Term Debt in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities
(VIEs)” (FIN 46), is not included as debt when calculating these ratios, as provided for in the various credit agreements. PSEG Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of June 30, 2004, PSEG's ratio of debt to capitalization (as defined above) was 58.3%. PSE&G Financial covenants contained in PSE&G's credit facilities include a ratio of long-term debt (excluding securitization debt and long-term debt maturing within one year) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of June 30, 2004, PSE&G's ratio of long-term debt to total capitalization (as defined above) was 52.9%. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of 66
earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1, and/or against retired Mortgage Bonds. As of June 30, 2004, PSE&G's Mortgage coverage ratio was 4:1. PSEG and Power Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. For PSEG, the covenant described above in PSEG is applicable. For Power, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted to add back the $986 million Basis Adjustment (see Condensed Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of June 30, 2004, Power's ratio of debt to capitalization (as defined above) was 50.4%. Energy Holdings In April 2003, Energy Holdings issued $350 million of Senior Notes which contain financial covenants that include debt incurrence tests consisting of a debt service coverage test and a ratio of consolidated recourse indebtedness to recourse capitalization test. These covenants require that Energy Holdings not incur additional consolidated recourse indebtedness, other than certain permitted indebtedness, unless, on a pro forma basis, giving effect to the incurrence of the additional consolidated recourse indebtedness: (i) the debt service coverage ratio would be at least 2:1; and (ii) the ratio of consolidated recourse indebtedness to recourse capitalization would not exceed 60%. Certain permitted indebtedness, such as permitted refinancings and borrowings are excluded from the requirements under this debt incurrence
test. The provisions of the Senior Notes also restrict Energy Holdings from selling assets with a net book value greater than 10% of its assets in any four consecutive quarters, unless the proceeds are used to reduce debt of Energy Holdings or its subsidiaries or are retained by Energy Holdings. Energy Holdings entered into a $200 million three-year bank revolving credit agreement in October 2003 with a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges shall not be less than 1.75. As of June 30, 2004, Energy Holdings' coverage of this covenant was 2.51. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA not greater than 5.25. As of June 30, 2004, Energy Holdings' ratio under this covenant was 3.79. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings' membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction
of certain financial covenants. Cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Cash proceeds in excess of 10% of total assets of Energy Holdings during any 12-month period must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources. Credit Ratings PSEG, PSE&G, Power and Energy Holdings The current
ratings of securities of PSEG and its subsidiaries are shown below and reflect
the respective views of the rating agencies. Any downward revision or withdrawal
may adversely affect the market price of PSEG's, PSE&G's, Power's
and Energy Holdings' securities and serve to increase those companies'
cost of capital and limit their access to capital. All ratings have a stable
outlook unless otherwise noted. (N) denotes a negative outlook and (NW)
denotes a negative watch. There is no assurance that the ratings will continue
for any given period of time or that they will not be revised by the rating
agencies, if, in their respective judgments, circumstances so warrant. Each
rating given by an agency should be evaluated independently of the other agencies'
ratings. The ratings should not be construed as an indication to buy, hold or
sell any security. 67
The financial
objectives for PSEG include improving the credit ratings for each of PSEG and
Power and maintaining the credit ratings for each of PSE&G and Energy Holdings.
To accomplish this, PSEG expects to improve its funds from operations and interest
coverage ratios and continue to lower its leverage ratio over the planning period.
Failure to meet these targets could lead to a lower credit rating. On April 12, 2004, Fitch downgraded Energy Holdings' Senior Notes rating from BBB- to BB, with a negative outlook. On July 30, 2004, S&P downgraded PSEG's and PSE&G's respective commercial paper ratings from A2 to A3 and placed PSEG, PSE&G and Power on negative outlook. Also on July 30, 2004, Fitch placed PSEG's Preferred Securities rating and Power's Senior Notes rating on negative credit watch. PSEG: Preferred Securities Commercial Paper PSE&G: Mortgage Bonds Preferred Securities (D) Commercial Paper Power: Senior Notes Energy Holdings: Senior Notes 68
Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings As of June 30, 2004, PSEG and its subsidiaries had a total of approximately $2.6 billion of committed credit facilities with approximately $1.9 billion of available liquidity under these facilities. In addition to this amount, PSEG and PSE&G have access to certain uncommitted credit facilities. PSEG had $50 million outstanding and PSE&G had $80 million outstanding under these uncommitted facilities as of June 30, 2004. Each of the credit facilities is restricted to availability and use to the specific companies as listed below. PSEG: 4-year Credit Facility 5-year Credit Facility 3-year Credit Facility Uncommitted Bilateral Agreement Bilateral Term Loan Bilateral Revolver PSE&G: 5-year Credit Facility Uncommitted Bilateral Agreement PSEG and Power: 3-year Credit Facility(A) Power: 3-year Credit Facility Energy Holdings: 3-year Credit Facility PSEG As noted
above, S&P downgraded PSEG's commercial paper rating. This will limit its
ability to access the commercial paper market, however, PSEG believes it has sufficient liquidity to
fund its short-term cash management needs. PSE&G In June 2004,
PSE&G entered into a $600 million 5-year credit facility. This facility
replaced the expiring $200 million 364-day credit facility and the $200 million
3-year credit facility that was to expire in June 2005. As noted above, S&P downgraded
PSE&G's commercial paper rating. This will limit its
ability to access the commercial paper market, however, PSE&G believes it has sufficient liquidity
to fund its short-term cash management needs. 69
Energy Holdings As of June 30, 2004, in addition to amounts outstanding under Energy Holdings' credit facilities shown in the above table, subsidiaries of Global had $36 million of non-recourse short-term financing at the project level. As of June 30, 2004, Energy Holdings had loaned $169 million of excess cash to PSEG. Power As of June 30, 2004, in addition to amounts outstanding under Power's credit facilities shown in the above table, Power had borrowed approximately $191 million from PSEG for general corporate purposes. As noted
above, S&P placed Power on negative outlook and Fitch placed Power on negative
watch. Power believes it has sufficient liquidity to meet any required posting
of collateral resulting from a downgrade. See Note 7. Commitments and Contingent
Liabilities for further information. External Financings PSEG Since 2002, PSEG has been issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing shares on the open market. During the quarter ended June 30, 2004, PSEG issued approximately 524,000 shares for approximately $21 million pursuant to these plans. For the six months ended June 30, 2004, PSEG issued approximately 974,000 shares for approximately $42 million pursuant to these plans. PSE&G In July
2004, PSE&G called for redemption, on September 1, 2004, all of its $254 million
of 7.0% Series SS First and Refunding Mortgage Bonds due 2024. In June 2004, PSE&G issued $175 million two-year floating rate Medium-Term Notes secured by an equal amount of its First and Refunding Mortgage Bonds. The interest is set quarterly at LIBOR plus 0.125%. The proceeds were primarily used to redeem $159 million of 7.375% Series TT First and Refunding Mortgage Bonds due 2014. In June 2004 and March 2004, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $30 million and $32 million, respectively, of its transition bonds. In May 2004, $286 million of 6.50% Series PP First and Refunding Mortgage Bonds matured. Power In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009 and $250 million of 5.00% Senior Notes due April 2014. The net proceeds, together with other available cash, were used to fund the repayment of $800 million of project finance debt of certain of Power's subsidiaries. Energy Holdings In July 2004, Energy Holdings redeemed $75 million of preference units owned by PSEG. In May 2004, Energy Holdings redeemed $75 million of preference units owned by PSEG and paid a distribution to PSEG of $75 million. During the second quarter of 2004, Energy Holdings repurchased approximately $41 million of its 7.75% Senior Notes due April 2007, reducing the aggregate amount of that security outstanding to $309 million. In February 2004, Energy Holdings repaid $267 million of its 9.125% Senior Notes at maturity, utilizing cash on hand and redeemed $75 million of preference units owned by PSEG. Other Comprehensive Loss PSEG, Power and Energy Holdings For the six months ended June 30, 2004, PSEG, Power and Energy Holdings had Other Comprehensive Losses of $267 million, $185 million and $79 million, respectively, due primarily to net 70
unrealized losses on derivatives accounted for as hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), unrealized gains and losses in the NDT Funds at Power and foreign currency translation adjustments at Energy Holdings. PSEG, PSE&G, Power and Energy Holdings It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings will come from their respective internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings. Except as noted below, projected construction and investment expenditures for PSEG, PSE&G, Power and Energy Holdings are consistent with amounts disclosed in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2003 and Quarterly Reports on Form 10-Q of PSEG, PSE&G, Power and Energy Holdings for the quarter ended March 31, 2004. PSE&G During the six months ended June 30, 2004, PSE&G had made approximately $187 million of capital expenditures, primarily related to improvements in its transmission and distribution system, gas system and common facilities. Power During the six months ended June 30, 2004, Power made approximately $335 million of capital expenditures, primarily related to the construction activities at the facilities in Bethlehem, New York, Linden, New Jersey, Mercer, New Jersey, Lawrenceburg, Indiana and at its Salem and Hope Creek nuclear generating stations. Energy Holdings During the six months ended June 30, 2004, Energy Holdings made approximately $63 million of capital expenditures, primarily related to capital requirements of consolidated subsidiaries financed from internally generated cash flow within its projects, or from local sources on a non-recourse basis. During the second quarter Energy Holdings revised its 2004 total projected construction and investment expenditures to approximately $90 million. The increase in expected capital expenditures for 2004 is primarily due to minor capital projects at certain of Global's subsidiaries, including a 45 MW generation project at SAESA, which are expected to be funded locally. ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES PSEG, PSE&G, Power and Energy Holdings The market risk inherent in PSEG's, PSE&G's, Power's and Energy Holdings' 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 Condensed Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings use a Risk Management Committee (RMC) comprised of executive officers that utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which 71
is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries' financial condition, results of operations or net cash flows. Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2003 or Quarterly Report on Form 10-Q for the quarter ended March 31, 2004. Commodity Contracts PSEG and Power 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, market rules and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge its anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio. Normal Operations and Hedging Activities Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to eliminate risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors. Power's derivative contracts are accounted for under SFAS 133, its amendments and related guidance. Most non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and/or SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149) for contracts entered into or modified and hedging relationships designed after June 30, 2003. Changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Income (OCI), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion
of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings. Trading Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133, its amendments and related guidance, with gains and losses recognized in earnings. VaR Models Power Power uses value-at-risk (VaR) models to assess the market risk of its commodity businesses. The daily VaR model for Power includes physical contracts and financial derivative instruments, most of which are marked to market in the financial statements. VaR measures the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses. Power routinely enters into contracts to hedge its core portfolio of owned generation, load-serving contracts and fuel supply contracts. While most of these contracts are entered into in the normal course 72
of business and receive settlement accounting treatment, some are marked to market. The risk associated with contracts that receive mark-to-market treatment, which are entered into to mitigate the risk of the core portfolio is presented in the following table as non-trading MTM VaR. The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for all mark-to-market activities both trading and non-trading. While Power actively manages its portfolio, the models assume no new positions throughout the holding periods. Power also monitors all trading, load and fuel contracts as well as expected generation through an overall portfolio VaR model with a five-day holding period, the results of which are not presented here. As of June 30, 2004, trading VaR was approximately $1 million, compared to the December 31, 2003 level of $2 million. For the Quarter Ended June 30, 2004 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End Average for the Period High Low 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End Average for the Period High Low For the Six Months Ended June 30, 2004 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End Average for the Period High Low 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End Average for the Period High Low Other Supplemental Information Regarding Market Risk Power The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry's Committee of Chief Risk Officers. For additional information, see Note 8. Risk Management of the Notes. The following table describes the drivers of Power's energy trading and marketing activities and operating revenues included in its Condensed Consolidated Statements of Operations for the quarter and six months ended June 30, 2004. Normal operations and hedging activities represent the marketing 73
of electricity available from Power's owned or contracted generation sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices. Operating Revenues Mark-to-Market Activities: Unrealized Mark-to-Market Gains (Losses) Changes in Fair Value of Open Positions Origination Unrealized Gain at Inception Changes in Valuation Techniques and Assumptions Realization at Settlement of Contracts Total Change in Unrealized Fair Value Realized Net Settlement of Transactions Subject to Mark-to-Market Broker Fees and Other Related Expenses Net Mark-to-Market Gains (Losses) Accrual Activities Accrual Activities—Revenue, Including Hedge Reclassifications Total Operating Revenues Operating Revenues Mark-to-Market Activities: Unrealized Mark-to-Market Gains (Losses) Changes in Fair Value of Open Positions Origination Unrealized Gain at Inception Changes in Valuation Techniques and Assumptions Realization at Settlement of Contracts Total Change in Unrealized Fair Value Realized Net Settlement of Transactions Subject to Mark-to-Market Broker Fees and Other Related Expenses Net Mark-to-Market Gains (Losses) Accrual Activities Accrual Activities—Revenue, Including Hedge Reclassifications Total Operating Revenues The following table indicates Power's energy trading assets and liabilities, as well as Power's hedging activity related to asset backed transactions and derivative instruments that qualify for hedge 74
accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to set off and therefore, are not necessarily indicative of amounts presented on the Condensed Consolidated Balance Sheets because balances with many counterparties are subject to offset and are shown net on the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included. Energy Contract Net Assets/Liabilities Mark-to-Market Energy Assets Current Assets Noncurrent Assets Total Mark-to-Market Energy Assets Mark-to-Market Energy Liabilities Current Liabilities Noncurrent Liabilities Total Mark-to-Market Current Liabilities Total Mark-to-Market Energy Contract Net (Liabilities) Assets The following table presents maturity of net fair value of mark-to-market energy trading contracts. Maturity of Net Fair Value of Mark-to-Market Energy Trading Contracts Trading Normal Operations and Hedging Total Net Unrealized Losses on Mark-to-Market Contracts Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power's financial results. PSEG, Power and Energy Holdings The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG's policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt
and interest rate derivatives. The table also provides an estimate of the losses that are expected to be reclassified out of Accumulated OCI and into earnings over the next twelve months. 75
Cash Flow Hedges Included in OCI Cash Flow Hedges Included in Accumulated OCI Commodities Interest Rates Foreign Currency Net Cash Flow Hedge Loss Included in Accumulated OCI Power Credit Risk Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power's counterparty credit limits are based on a variety of factors, including credit ratings, leverage, liquidity, profitability and risk management capabilities. Power has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact
on Power and its subsidiaries' financial condition, results of operations or net cash flows. As of June 30, 2004, over 72% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power's trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties is with certain companies that supply coal to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. The following table provides information on Power's credit exposure, net of collateral, as of June 30, 2004. Credit exposure, in the table below, is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company's credit risk by credit rating of the counterparties. Schedule of Credit Risk Exposure on Energy Contracts Net Assets Investment Grade—External Rating Non-Investment Grade—External Rating Investment Grade—No External Rating Non-Investment Grade—No External Rating Total The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure. As of June 30, 2004, Power's trading operations included over 175 active counterparties. 76
ITEM 4. CONTROLS AND PROCEDURES PSEG, PSE&G, Power and Energy Holdings Disclosure Controls and Procedures PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a Disclosure Committee, which is made up of several key management employees and reports directly to the Chief Financial Officer and Chief Executive Officer of each company, to monitor and evaluate these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures
as of the end of the reporting period and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these quarterly reports. Internal Controls There were no significant changes in internal controls or in other factors that could significantly affect internal controls during the most recent quarter. PSEG, PSE&G, Power and Energy Holdings are in the process of completing documentation, testing and enhancement of their respective internal controls around financial reporting to meet all requirements of the Sarbanes-Oxley Act for the year ending December 31, 2004. It should be noted that the design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and that only reasonable assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of
how remote, can be given. 77
Certain
information reported under Item 3 of Part I of the 2003 Annual Report on
Form 10-K and under Item 1 of Part II of the Quarterly Report
on Form 10-Q for the quarter ended March 31, 2004 is updated below. See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted: (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) 78
Certain information reported under the 2003 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2003 Annual Report on Form 10-K and Quarter Report on Form 10-Q for the quarter ended March 31, 2004. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed. Customer Account Services (CAS) Cost Recovery Mechanism PSE&G On July 1, 2004, PSE&G filed a petition before the BPU to implement the CAS Cost Recovery Mechanism for both the electric and gas operations. The request petitions the BPU for the approval to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G's dual billing for its delivery costs and for the third-party suppliers' commodity charges as a result of customer migration from PSE&G. Fuel Supply Power 2003
From 10-K, Page 7. Power has commitments
for aproximately 90% and 70% of its anticipated coal requirements for 2005 and
2006, respectively, at prices approximately 13% higher than 2004. There have
recently been some difficulties in the industry with the timely rail transportation
of coal, which shippers have attributed to a shortage of available
equipment. Power believes that it has sufficient contracts with enforceable
contractual rights to meet its anticipated coal needs. However, future disruptions
in transportation could potentially impact Power's ability to operate its
coal-fired plants and the availability and price of replacement power that it
might be necessary for Power to purchase. For additional information, see Note 7.
Commitments and Contingent Liabilities of the Notes. Federal Regulation Power Scarcity Pricing Mechanism In June 2004, FERC issued an order permitting the New York Independent System Operator (NYISO) to utilize existing scarcity pricing rules past their expiration date of June 23, 2004 until the NYISO can implement its enhanced version of the scarcity pricing mechanism. These rules permit significant increases in electric prices during times of scarcity. Power is evaluating the impact this ruling may have on its business. New England Power Pool (NEPOOL) Billing In June 2004, FERC issued an order to implement a change from a monthly to a weekly billing payment system for NEPOOL's hourly markets. This change is expected to reduce the collateral requirement imposed on market participants. NEPOOL estimates that the overall level of financial assurance required to participate in the NEPOOL will drop from approximately $177 million to $58 million. Power is evaluating the impact this ruling may have on its business. PSE&G, Power and Energy Holdings 2003 Form 10-K, Page 16 and March 31, 2004 Form 10-Q, Page 70. On March 19, 2004, FERC approved a settlement agreement/going forward principle in the case involving the elimination of the regional through and out rates (RTORs) in the PJM/MISO region. Under the settlement, RTORs with transactions that cross the PJM/MISO border will continue until December 1, 2004. In addition, a 79
transmission provider must file a long-term transmission pricing structure proposal by October 1, 2004, to be effective December 1, 2004 following elimination of the RTORs. The participants in this proceeding are currently working through a FERC supervised settlement process with an objective of reaching a consensus on a long-term transmission pricing structure to be filed in October 2004. This proceeding will likely result in a regional transmission rate design across the PJM/MISO region. While PSE&G and Power cannot predict the impact, if any, of this proceeding at this time, it is possible that a new regional rate design could impact PSE&G through additional risk in collection of its revenue requirements and Power through increased delivery charges. On April 16, 2004, FERC issued an order on rehearing, revising and clarifying the standards of conduct governing the relationship between transmission providers and their energy affiliates that were adopted by FERC in late 2003. The revised rules are applicable to the relationship between the electric and gas services of PSE&G, as well as the relationship between PSE&G and certain subsidiaries of Power and Energy Holdings. PSE&G, Power and Energy Holdings are evaluating the impact that these revised rules may have, including: (i) additional training and reporting obligations; (ii) restrictions on an employee's ability to perform services for both a transmission provider and its energy affiliates; and (iii) restrictions on the availability of information to both the transmission provider and
its energy affiliates. On April 14, 2004, FERC issued a final order revising its generation market power screen, which it uses to determine if power sellers should be entitled to sell at market-based rates. FERC's revised screen will be an indicative, rather than decisive tool, and will include two separate analyses: (a) an uncommitted pivotal supplier analysis and (b) a market share analysis that is to be prepared on a seasonal basis. FERC eliminated an exemption that previously existed for generators in RTOs and Independent System Operators (ISOs) such as PJM and NYISO and will require all entities that wish to sell at market-based rates to submit to this market power screen. PSE&G and Power are scheduled for their
next triennial market power review in 2006. Lawrenceburg and Waterford are subject to their triennial market power review in August 2004. Also on April 14, 2004, FERC issued a notice that it will commence a pre-rulemaking to analyze the adequacy of its overall process used to consider whether an applicant is entitled to market-based rate authority. On July 8, 2004, FERC issued an order on rehearing of its April 14, 2004 order that upheld the elimination of the exemption for generators within RTOs and ISOs, but also clarified that generators need not include load-following or provider of last resort contracts, such as obligations to supply BGS in New Jersey, within the screens. On June 17, 2004, FERC issued two orders to allow the operating affiliates of American Electric Power Service Corporation's (AEP) to transfer transmission facilities in Virginia to PJM's control and allowing AEP's Kentucky operating company to join PJM. These orders are expected to facilitate AEP's efforts to join PJM on October 1, 2004. PSE&G, Power and Energy Holdings cannot predict the impact, if any, that these proceedings will have on their respective businesses. NRC Power 2003 Form 10-K, Page 18 and March 31, 2004 Form 10-Q, Page 71. In 2002, the NRC issued a bulletin requiring that all operators of pressurized water reactor (PWR) nuclear units submit certain information related to potential degradation of reactor vessel heads. In 2003, the NRC issued an order to all operators of PWR units concerning reactor vessel head inspections. The order confirms the previous bulletin's requirements and adds more intrusive and frequent future inspections, which apply to Salem 1 and 2. In September 2002, Nuclear provided the requested information for Salem to the NRC, and performed inspections in accordance with the NRC order for Salem 1 and 2 during 2004 and 2003, respectively. The reactor heads were determined to be satisfactory for continued safe operation.
Nuclear plans to replace Salem 1 and 2 reactor heads in 2005 as a preventive maintenance measure. Also in 2003, the NRC issued a bulletin requiring that all operators of PWR nuclear units also perform inspections of the reactor vessel lower head, due to leakage observed at another nuclear unit not owned by Power. Bare metal visual examinations were completed during Salem 2's October 2003 80
outage and Salem 1's April 2004 outage, and no degradation was observed. Nuclear's Hope Creak nuclear unit and Peach Bottom 2 and 3 are unaffected by either of these bulletins as they are boiling water reactor nuclear units. Power cannot predict what other actions the NRC may take on this issue. On January 28, 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter on February 28, 2004 and had independent assessments of the work environment at both facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified issues that needed to be addressed. At an NRC public meeting on June 16, 2004, PSEG outlined its action plan to address these issues, which focuses on a safety conscious work environment, the corrective action program and work management. A letter documenting these plans and commitments was sent to the
NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to PSEG indicating that it had completed its review. The letter indicates that the NRC has not identified any safety violations and that it appears that the PSEG action plan will address the key findings of both the NRC and PSEG assessments. The NRC further indicated that it will continue to closely monitor PSEG's performance and its efforts to improve the work environment at Salem and Hope Creek. Remediation Adjustment Clause (RAC) Filing PSE&G 2003 Form 10-K, Page 21 and March 31, 2004 Form 10-Q, Page 72. On April 22, 2004, PSE&G filed its RAC-11 with the BPU to recover $35 million of remediation program expenditures for the period from August 1, 2002 through July 31, 2003. In July 2004, responses were provided to discovery requests received from the New Jersey Ratepayer Advocate (RPA). Public hearings were held in July 2004. BGSS Filing PSE&G 2003 Form 10-K, Page 21 and March 31, 2004 Form 10-Q, Page 72. On April 9, 2004, PSE&G received the Administrative Law Judge's (ALJ's) Initial Decision in the 2003/2004 BGSS Commodity Charge Proceeding, filed on May 30, 2003. Under the ALJ's Initial Decision, the Partial Settlement executed and submitted by the parties was approved. Moreover, under the Initial Decision, the RPA's proposal to return pipeline refunds from September and November 2002 and the deferred cost balance as of May 1, 2002 to Commercial and Industrial (C&I) customers was rejected. The initial decision was sent to the BPU for a final order. The parties have filed exceptions and replies to those exceptions. The BPU normally has 45 days from the date of ALJ's Initial Decision
to either accept, reject or modify that decision. On June 23, 2004, the BPU extended the deadline an additional 45 days. The outcome of this proceeding cannot be determined at this time. On May 28, 2004, PSE&G filed its 2004/2005 BGSS commodity charge filing, requesting an increase in its BGSS commodity charge to its residential gas customers of approximately $46.5 million in annual revenues effective October 1, 2004 or approximately 3% for the class average residential heating customer. The case was transmitted to the Office of Administrative Law (OAL) for hearings, which are scheduled for August 2004. Universal Service Fund (USF) PSE&G 2003 Form 10-K, Page 21. On June 23, 2004, the BPU orally approved an increase in the statewide electric and gas USF rates to recover approximately $113 million beginning on July 1, 2004. PSE&G's share is approximately $68 million. In addition, the BPU orally approved a settlement on the 2001 Interim USF Pilot Program, to implement a $6.6 million increase on July 1, 2004 based on costs incurred in 2001. 81
Water Pollution Control PSEG, Power and Energy Holdings 2003 Form 10-K, Page 25. The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of pollutants to waters of the U.S. from point sources, except pursuant to a National Pollutant Discharge Elimination System (NPDES) permit issued by the EPA or by a state under a federally authorized state program. Section 316(b) of the FWPCA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing the “adverse environmental impact.” The EPA, on July 9, 2004, published regulations implementing Section 316(b) of the FWPCA for large existing power plants. The regulations provide the following five alternative methods by which a facility can demonstrate that
it complies with the requirement for BTA for minimizing adverse environmental impacts associated with cooling water intake structures: (1) reduce flow commensurate with a closed-cycle system or reduce intake velocity; (2) meet applicable performance standards for reduction of entrainment and impingement through the use of the existing design, construction, operational or restoration measures; (3) meet applicable performance standards through a combination of existing and proposed design, construction, operational or restoration measures; (4) installation of a design and construction technology specified by the regulation or pre-approved by the agency; and (5) a site-specific determination that the cost to the facility to meet the performance standards is “significantly greater” than either (a) the
costs that the EPA estimated for that type of facility or (b) the environmental benefits of complying with the performance standards. The new regulations become effective September 7, 2004. The Attorneys General of six northeastern states, including New Jersey, have filed a joint petition for review of the new regulations and a request that the effective date of the regulations be stayed pending resolution of their petition for review. Similarly, a coalition of environmental interest groups have also filed a petition for review of the new regulations. Although the regulations apply to all of Power's electric generating units that use surface waters for once-through cooling purposes, the impact of the regulations to Power and the regulations' ability to withstand these legal challenges cannot be determined at this time. If
application of the Section 316(b) regulations require the retrofitting of cooling water intake structures at Power's existing facilities, the retrofit, including capital costs of the construction and costs associated with unit outages for the construction, would result in material costs of compliance. Permit Renewals Power 2003 Form 10-K, Page 27. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. An application for renewal of that permit, including a demonstration of compliance with the requirements of the recently published FWPCA Section 316(b) regulations, must be submitted to NJDEP by February 2, 2006 unless the agency grants additional time to collect information to comply with the new regulations. NJDEP advised Power in a letter dated July 12, 2004 that it strongly recommends reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. If application of the Section 316(b) regulations requires the retrofitting
of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, the retrofit would result in material costs of compliance, including capital costs of constructing cooling towers and an outage to complete the construction. Power has not determined which of the options available under the Section 316(b) regulations it will use to demonstrate compliance with the new regulations. Energy Holdings Texas 2003 Form 10-K, Page 41. On July 7, 2003, Texas Commercial Energy LLC (TCE) filed suit against power generators, qualified scheduling entities and affiliated retail electric providers, as well as the Electric Reliability Council of Texas (ERCOT) in its function as the independent system operator 82
for the Texas energy market. The action filed in the U.S. District Court for the Southern District of Texas alleges price-fixing, predatory pricing and certain common law claims. APX Inc., a named defendant, acted as agent and submitted bids on behalf of TIE as well as several other generators in the ERCOT balancing energy market. APX Inc. has submitted a demand for indemnification from TIE. On February 3, 2004, TCE amended its complaint and named TIE and others as additional defendants. TIE believes it has valid defenses to these claims and will vigorously assert them. In June 2004, the District Court granted defendants' motion to dismiss. In July 2004, TCE
filed a Notice of Appeal. India PPN Power Generating Company Limited (PPN) 2003
Form 10-K, Page 52 and March 31, 2004 Form 10-Q, Page 49. Global's
investment in India, PPN, sells its output under a long-term Power Purchase
Agreement (PPA) with the Tamil Nadu Electricity Board (TNEB). TNEB has not made
full payment to PPN for the purchase of energy under the PPA and the total receivable
as of June 30, 2004 was approximately $104 million. The project ran on
a limited basis during the second quarter of 2004, primarily due to the high
cost of Naptha fuel. The past due receivable as of June 30, 2004 was approximately
$98 million, of which Global's share is approximately $7 million, net of
a $13 million reserve. If TNEB continues to fail to make required payments under
the PPA, PPN may have further liquidity problems. On March 26, 2004, PSEG
and one of its partners in PPN, El Paso Energy Company, filed a notice of arbitration
on behalf of PPN against TNEB under the arbitration clause of the PPA, which
allows the minority shareholders to protect the rights of PPN where PPN has
failed to exercise those rights itself. Global expects
the resolution of certain of these matters later
in 2004, including a settlement with TNEB and other
authorities regarding the capital cost of the project, the equity invested and
other matters affecting the tariff that PPN charges TNEB. The cost of PPN's
output is also expected to decrease due to an anticipated switch from Naptha
fuel to natural gas at the facility. An adverse outcome to the continuing negotiations
or arbitration with TNEB could potentially result in an impairment of this investment,
which could be material to PSEG's and Energy Holdings' respective results
of operations. As of June 30, 2004, Global's total investment in PPN
was approximately $39 million. Poland ELCHO 2003 Form 10-K, Page 53. Global has a 90% ownership interest in ELCHO, which owns a combined power generation and thermal energy plant in Poland. ELCHO has a contract with a local distribution company for the delivery of steam to the town of Chorzow, Poland, which represents approximately 20% of ELCHO's business. ELCHO recently received notification that the local distribution company has filed a petition for bankruptcy protection and that the District Court
has appointed a temporary court supervisor to secure its property as it reviews the petition. The bankruptcy of this significant customer could lead to a default under ELCHO's bank agreements. If that occurs, Energy Holdings believes that a waiver would be successfully obtained. Failure to obtain a waiver could result in the acceleration of payment of approximately $285 million of non-recourse project debt at ELCHO. ELCHO's net receivable from the local distribution company as of June 30, 2004 is approximately $5 million. Although Energy Holdings believes that the receivable will be recoverable and that there will not be a material adverse impact on its financial position, results or cash flows as a result of this matter, no assurances can be given. Global's total capital at risk at ELCHO was approximately $70 million as of June 30, 2004. 83
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (A) A listing of exhibits being filed with this document is as follows: a. PSEG: b. PSE&G: c. Power:
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,
2004
2003
(Millions)
(Unaudited)
$
161
$
656
Operating Activities:
—
(370
)
55
47
41
46
13
12
110
78
(22
)
(5
)
19
26
(75
)
(28
)
52
(11
)
48
144
(113
)
8
118
(8
)
(8
)
(37
)
(26
)
22
373
580
(335
)
(330
)
77
—
(4
)
(16
)
(262
)
(346
)
488
—
(800
)
—
191
—
—
(235
)
(121
)
(235
)
(10
)
(1
)
27
26
$
17
$
25
$
36
$
94
$
118
$
108
included in the Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Quarters Ended
June 30,
For the Six Months Ended
June 30,
As Restated,
see Note 2
As Restated,
see Note 2
2004
2003
2004
2003
(Millions)
(Unaudited)
$
118
$
102
$
244
$
193
49
54
101
110
10
15
45
58
177
171
390
361
48
41
94
76
50
41
99
76
12
10
25
18
110
92
218
170
33
31
61
51
100
110
233
242
2
3
3
7
(9
)
(1
)
(9
)
(4
)
(67
)
(53
)
(130
)
(101
)
26
59
97
144
(5
)
(17
)
(26
)
(36
)
—
(2
)
(2
)
(7
)
21
40
69
101
—
(5
)
2
(9
)
5
—
3
(9
)
26
35
74
83
(5
)
(6
)
(10
)
(12
)
$
21
$
29
$
64
$
71
included in the Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
212
$
104
91
103
20
19
—
173
169
300
6
2
24
26
5
7
34
16
—
298
3
3
564
1,051
1,364
1,348
(184
)
(170
)
1,180
1,178
2,820
2,981
994
1,040
473
531
28
31
472
496
127
152
4,914
5,231
$
6,658
$
7,460
included in the Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED BALANCE SHEETS
June 30,
2004
December 31,
2003
(Millions)
(Unaudited)
$
38
$
303
47
53
37
4
30
37
58
55
—
2
—
242
53
69
263
765
1,496
1,487
62
73
64
58
1,622
1,618
36
35
918
938
1,755
1,800
2,673
2,738
1,888
1,888
359
509
167
178
(350
)
(271
)
2,064
2,304
$
6,658
$
7,460
included in the Notes to Condensed Consolidated Financial Statements.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended
June 30,
As Restated,
see Note 2
2004
2003
(Millions)
(Unaudited)
$
74
$
83
(3
)
9
29
23
4
—
(113
)
35
18
5
(2
)
4
17
(5
)
(46
)
(45
)
6
(6
)
5
7
181
(23
)
1
4
20
(97
)
17
28
93
47
(3
)
12
298
81
(49
)
(112
)
(14
)
(18
)
63
2
229
—
131
(69
)
18
—
5
(23
)
383
(220
)
—
45
(311
)
—
8
690
(25
)
(576
)
(150
)
—
(75
)
—
—
(4
)
(10
)
(12
)
(9
)
(15
)
—
(10
)
(572
)
118
(1
)
—
108
(21
)
104
88
$
212
$
67
$
(128
)
$
(25
)
$
94
$
52
included in the Notes to Condensed Consolidated Financial Statements.
(UNAUDITED)
(UNAUDITED)
Pension Benefits
Other Benefits
Pension Benefits
Other Benefits
Quarters Ended
June 30,
Quarters Ended
June 30,
Six Months Ended
June 30,
Six Months Ended
June 30,
2004
2003
2004
2003
2004
2003
2004
2003
(Millions)
$
21
$
19
$
6
$
5
$
41
$
38
$
12
$
10
49
49
14
13
98
98
28
26
(58
)
(48
)
(2
)
(1
)
(116
)
(96
)
(4
)
(2
)
—
1
7
7
—
2
14
14
4
4
—
—
8
8
—
—
9
12
—
(1
)
19
24
—
(2
)
25
37
25
23
50
74
50
46
—
—
5
5
—
—
10
10
$
25
$
37
$
30
$
28
$
50
$
74
$
60
$
56
(UNAUDITED)
Pension Benefits
Other Benefits
Pension Benefits
Other Benefits
Quarters Ended
June 30,
Quarters Ended
June 30,
Six Months Ended
June 30,
Six Months Ended
June 30,
2004
2003
2004
2003
2004
2003
2004
2003
(Millions)
$
13
$
20
$
27
$
25
$
26
$
40
$
54
$
50
8
12
2
2
15
24
4
4
1
1
—
—
1
2
—
—
3
4
1
1
8
8
2
2
$
25
$
37
$
30
$
28
$
50
$
74
$
60
$
56
(UNAUDITED)
Quarters
Ended
June 30,
Six Months
Ended
June 30,
2004
2003
2004
2003
(Millions, except for share data)
$
124
$
133
$
395
$
814
—
—
—
—
(1
)
(2
)
(2
)
(4
)
$
123
$
131
$
393
$
810
$
0.52
$
0.59
$
1.67
$
3.61
$
0.52
$
0.58
$
1.66
$
3.59
$
0.52
$
0.59
$
1.66
$
3.60
$
0.51
$
0.57
$
1.65
$
3.58
(UNAUDITED)
As of
June 30,
2004
December 31,
2003
(Millions)
$
328
$
352
133
133
6
6
467
491
16
16
483
507
69
73
156
163
63
63
25
25
313
324
$
796
$
831
(A)
Changes relate to changes in foreign exchange rates.
PSE&G
Power
Energy Holdings
Other(A)
Consolidated
Total
(Millions)
$
2
$
3
$
4
$
5
$
14
—
45
—
—
45
—
40
—
—
40
—
23
—
—
23
—
—
1
—
1
$
2
$
111
$
5
$
5
$
123
$
2
$
3
$
4
$
5
$
14
—
49
—
—
49
—
40
—
—
40
—
14
—
—
14
—
—
1
—
1
$
2
$
106
$
5
$
5
$
118
(A)
Other primarily consists of activity at Services.
(B)
Not subject to amortization.
(C)
Expensed as used or sold.
(D)
Amortized on a straight-line basis.
(UNAUDITED)
(UNAUDITED)
Quarter Ended June 30, 2003
Six Months Ended
June 30, 2003
As Previously
Reported
As Restated
As Previously
Reported
As Restated
(Millions, except for Share Data)
$
2,419
$
2,401
$
5,725
$
5,689
$
1,412
$
1,400
$
3,376
$
3,353
$
487
$
488
$
1,007
$
1,007
$
103
$
98
$
203
$
197
$
31
$
31
$
48
$
51
$
30
$
30
$
88
$
89
$
(21
)
$
(9
)
$
(64
)
$
(52
)
$
(190
)
$
(210
)
$
(377
)
$
(408
)
$
(71
)
$
(72
)
$
(255
)
$
(258
)
$
150
$
156
$
471
$
480
$
(2
)
$
(5
)
$
(17
)
$
(18
)
$
130
$
133
$
806
$
814
$
0.67
$
0.69
$
2.09
$
2.13
$
0.58
$
0.59
$
3.57
$
3.61
$
0.66
$
0.69
$
2.09
$
2.12
$
0.57
$
0.59
$
3.57
$
3.60
Quarter Ended June 30, 2003
Six Months Ended June 30, 2003
As Previously
Reported
As Restated
As Previously
Reported
As Restated
(Millions)
$
122
$
102
$
235
$
193
$
12
$
15
$
52
$
58
$
52
$
41
$
99
$
76
$
14
$
10
$
24
$
18
$
31
$
31
$
48
$
51
$
—
$
3
$
1
$
7
$
(8
)
$
(1
)
$
(12
)
$
(4
)
$
(54
)
$
(53
)
$
(104
)
$
(101
)
$
(16
)
$
(17
)
$
(33
)
$
(36
)
$
(1
)
$
(2
)
$
(6
)
$
(7
)
$
33
$
40
$
92
$
101
$
(2
)
$
(5
)
$
(8
)
$
(9
)
$
31
$
35
$
75
$
83
(UNAUDITED)
(UNAUDITED)
As of
June 30,
2004
December 31,
2003
(Millions)
$
225
$
225
150
150
150
150
180
180
460
460
$
1,165
$
1,165
(UNAUDITED)
(UNAUDITED)
Quarters Ended
June 30,
Six Months
Ended
June 30,
2004
2003
2004
2003
(Millions)
$
12
$
20
$
38
$
42
$
—
$
(3
)
$
2
$
(1
)
$
—
$
(3
)
$
2
$
(1
)
As of
December 31, 2003
(Millions)
$
45
253
$
298
$
161
81
$
242
(UNAUDITED)
Quarter Ended
June 30, 2003
Six Months Ended
June 30, 2003
(Millions)
$
12
$
61
$
(4
)
$
(13
)
$
(2
)
$
(8
)
(UNAUDITED)
Quarters Ended June 30,
Six Months Ended June 30,
2004
2003
2004
2003
Basic
Diluted
Basic
Diluted
Basic
Diluted
Basic
Diluted
$
119
$
119
$
156
$
156
$
390
$
390
$
480
$
480
5
5
(5
)
(5
)
5
5
(18
)
(18
)
—
—
(18
)
(18
)
—
—
(18
)
(18
)
—
—
—
—
—
—
370
370
$
124
$
124
$
133
$
133
$
395
$
395
$
814
$
814
236,705
236,705
225,910
225,910
236,449
236,449
225,627
225,627
—
707
—
672
—
909
—
481
—
589
—
—
—
963
—
—
236,705
238,001
225,910
226,582
236,449
238,321
225,627
226,108
$
0.50
$
0.50
$
0.69
$
0.69
$
1.65
$
1.64
$
2.13
$
2.12
0.02
0.02
(0.02
)
(0.02
)
0.02
0.02
(0.08
)
(0.08
)
—
—
(0.08
)
(0.08
)
—
—
(0.08
)
(0.08
)
—
—
—
—
—
—
1.64
1.64
$
0.52
$
0.52
$
0.59
$
0.59
$
1.67
$
1.66
$
3.61
$
3.60
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
(UNAUDITED)
PSE&G
Power (A)
Energy
Holdings (B)
Other (C)
Consolidated
Total
(Millions)
$
63
$
52
$
26
$
(17
)
$
124
(1
)
(58
)
(30
)
4
(85
)
$
62
$
(6
)
$
(4
)
$
(13
)
$
39
$
4
$
109
$
35
$
(15
)
$
133
1
21
50
2
74
$
5
$
130
$
85
$
(13
)
$
207
$
188
$
161
$
74
$
(28
)
$
395
(1
)
(185
)
(79
)
(2
)
(267
)
$
187
$
(24
)
$
(5
)
$
(30
)
$
128
$
105
$
656
$
83
$
(30
)
$
814
—
60
18
2
80
$
105
$
716
$
101
$
(28
)
$
894
(A)
Changes at Power primarily relate to SFAS 133 unrealized losses on derivative contracts that qualify for hedge accounting and unrealized gains and losses on the NDT Funds.
(B)
Changes at Energy Holdings primarily relate to foreign currency translation adjustments and unrealized gains and losses on various derivative transactions.
(C)
Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations.
(UNAUDITED)
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
3
$
1
$
—
$
1
$
5
—
68
—
—
68
—
8
—
—
8
—
—
1
—
1
—
—
1
—
1
$
3
$
77
$
2
$
1
$
83
$
2
$
—
$
—
$
(1
)
$
1
—
17
—
—
17
—
7
—
—
7
—
—
2
—
2
1
1
1
—
3
$
3
$
25
$
3
$
(1
)
$
30
$
9
$
2
$
—
$
(1
)
$
10
(3
)
—
—
—
(3
)
—
96
—
—
96
—
14
—
—
14
—
—
2
—
2
—
—
1
(2
)
(1
)
$
6
$
112
$
3
$
(3
)
$
118
$
4
$
—
$
—
$
—
$
4
8
—
—
—
8
—
54
—
—
54
—
13
—
—
13
—
—
6
—
6
1
2
1
—
4
$
13
$
69
$
7
$
—
$
89
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
—
$
21
$
—
$
—
$
21
—
—
6
—
6
—
—
3
—
3
—
1
—
—
1
$
—
$
22
$
9
$
—
$
31
$
—
$
10
$
—
$
—
$
10
—
—
—
2
2
—
—
1
—
1
—
—
—
(4
)
(4
)
$
—
$
10
$
1
$
(2
)
$
9
$
1
$
—
$
—
$
—
$
1
—
34
—
—
34
—
—
6
—
6
—
—
3
—
3
—
—
—
2
2
—
8
—
—
8
$
1
$
42
$
9
$
2
$
54
$
1
$
—
$
—
$
—
$
1
—
40
—
—
40
—
—
—
7
7
—
—
4
—
4
$
1
$
40
$
4
$
7
$
52
(A)
Other consists of reclassifications for minority interests in PSEG's consolidated results of operations and intercompany eliminations at PSEG (as parent company).
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
94
$
74
$
26
$
(23
)
$
171
33
26
9
(8
)
60
7
4
12
(1
)
22
—
—
(2
)
—
(2
)
(1
)
—
—
—
(1
)
—
—
(12
)
—
(12
)
(8
)
(8
)
(2
)
3
(15
)
$
31
$
22
$
5
$
(6
)
$
52
33.0
%
29.7
%
19.2
%
26.1
%
30.4
%
$
14
$
183
$
59
$
(28
)
$
228
5
64
21
(10
)
80
3
10
—
(1
)
12
—
—
(3
)
—
(3
)
(14
)
—
—
—
(14
)
(2
)
—
(1
)
—
(3
)
$
(8
)
$
74
$
17
$
(11
)
$
72
(57.1
)%
40.4
%
28.8
%
39.3
%
31.6
%
$
313
$
259
$
97
$
(47
)
$
622
110
91
34
(17
)
218
22
15
12
(3
)
46
—
—
(9
)
—
(9
)
(2
)
—
—
—
(2
)
—
—
(10
)
—
(10
)
(5
)
(8
)
(1
)
3
(11
)
$
125
$
98
$
26
$
(17
)
$
232
39.9
%
37.8
%
26.8
%
36.2
%
37.3
%
$
171
$
483
$
144
$
(60
)
$
738
60
169
50
(21
)
258
14
28
—
(3
)
39
—
—
(14
)
—
(14
)
(26
)
—
—
—
(26
)
—
—
—
1
1
$
48
$
197
$
36
$
(23
)
$
258
28.1
%
40.8
%
25.0
%
38.3
%
35.0
%
(A)
PSEG's other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs.
(UNAUDITED)
Energy Holdings
PSE&G
Power
Resources
Global
Other (A)
Other (B)
Consolidated
Total
(Millions)
$
1,418
$
993
$
57
$
117
$
3
$
(298
)
$
2,290
63
52
14
9
(2
)
(17
)
119
—
—
—
5
—
—
5
63
52
14
14
(2
)
(17
)
124
(1
)
—
(1
)
(4
)
—
6
—
62
52
13
10
(2
)
(11
)
124
112
188
10
39
(1
)
6
354
$
1,342
$
1,235
$
67
$
103
$
1
$
(347
)
$
2,401
22
109
24
16
—
(15
)
156
—
—
—
(2
)
(3
)
—
(5
)
(18
)
—
—
—
—
—
(18
)
4
109
24
14
(3
)
(15
)
133
(1
)
—
(2
)
(4
)
—
7
—
3
109
22
10
(3
)
(8
)
133
124
177
—
42
—
3
346
$
3,600
$
2,685
$
95
$
290
$
5
$
(1,164
)
$
5,511
188
161
15
58
(4
)
(28
)
390
—
—
—
5
—
—
5
188
161
15
63
(4
)
(28
)
395
(2
)
—
(2
)
(8
)
—
12
—
186
161
13
55
(4
)
(16
)
395
187
335
11
52
—
7
592
$
3,490
$
3,065
$
118
$
238
$
5
$
(1,227
)
$
5,689
123
286
37
66
(2
)
(30
)
480
—
—
—
(1
)
(17
)
—
(18
)
(18
)
—
—
—
—
—
(18
)
—
370
—
—
—
—
370
105
656
37
65
(19
)
(30
)
814
(2
)
—
(3
)
(9
)
—
14
—
103
656
34
56
(19
)
(16
)
814
215
330
—
129
1
4
679
$
12,979
$
7,887
$
2,995
$
3,455
$
208
$
(117
)
$
27,407
$
—
$
—
$
59
$
1,407
$
—
$
—
$
1,466
$
13,162
$
7,731
$
3,277
$
3,814
$
369
$
(292
)
$
28,061
$
—
$
—
$
94
$
1,472
$
4
$
—
$
1,570
(UNAUDITED)
(A)
Energy Holdings' other activities include amounts applicable to Energy Holdings (as parent company), the HVAC/operating companies formerly owned by Energy Holdings subsidiaries, which are classified in discontinued operations, and EGDC. The net losses primarily relate to financing and certain administrative and general costs of Energy Holdings. For a discussion of the charges relating to Discontinued Operations at Energy Technologies, see Note 4. Discontinued Operations and Dispositions.
(B)
PSEG's other activities include amounts applicable to PSEG (as parent company), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions, see Note 14. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation.
Billings
Quarters Ended June 30,
Six Months Ended June 30,
Power Receivable
from PSE&G as of
2004
2003
2004
2003
June 30, 2004
December 31, 2003
(Millions)
$
63
$
—
$
82
$
—
$
49
$
9
$
236
$
294
$
1,083
$
1,126
$
52
$
268
(UNAUDITED)
(UNAUDITED)
Services Billings for the
Quarters
Ended
June 30,
Six Months
Ended
June 30,
Payable to Services as of
2004
2003
2004
2003
June 30, 2004
December 31, 2003
(Millions)
$
53
$
54
$
100
$
100
$
16
$
21
$
40
$
27
$
74
$
54
$
12
$
14
$
5
$
4
$
8
$
8
$
2
$
2
(Payable to) Receivable from PSEG
As of
June 30, 2004
As of
December 31, 2003
(Millions)
$
(98
)
$
(105
)
$
50
$
(17
)
$
23
$
173
(UNAUDITED)
Power
Guarantor
Subsidiaries
Other
Subsidiaries
Consolidating
Adjustments
Consolidated
Total
(Millions)
For the Quarter Ended June 30, 2004:
$
—
$
1,204
$
25
$
(236
)
$
993
—
1,152
30
(236
)
946
—
52
(5
)
—
47
24
77
—
(24
)
77
—
(22
)
—
—
(22
)
52
(13
)
—
(39
)
—
(28
)
(8
)
(16
)
24
(28
)
4
(35
)
8
1
(22
)
$
52
$
51
$
(13
)
$
(38
)
$
52
For the Quarter Ended June 30, 2003:
$
—
$
1,487
$
74
$
(326
)
$
1,235
—
1,313
52
(326
)
1,039
—
174
22
—
196
8
63
—
(46
)
25
—
(43
)
—
33
(10
)
98
32
—
(130
)
—
(51
)
(21
)
32
12
(28
)
54
(108
)
(19
)
(1
)
(74
)
$
109
$
97
$
35
$
(132
)
$
109
For the Six Months Ended June 30, 2004:
$
—
$
3,106
$
47
$
(468
)
$
2,685
—
2,839
56
(468
)
2,427
—
267
(9
)
—
258
38
112
—
(38
)
112
—
(35
)
(7
)
—
(42
)
172
(27
)
—
(145
)
—
(61
)
(17
)
(30
)
39
(69
)
12
(128
)
18
—
(98
)
$
161
$
172
$
(28
)
$
(144
)
$
161
For the Six Months Ended June 30, 2003:
$
—
$
3,546
$
144
$
(625
)
$
3,065
—
3,070
110
(625
)
2,555
—
476
34
—
510
8
75
—
(14
)
69
—
(40
)
—
—
(40
)
669
31
—
(700
)
—
(92
)
(39
)
63
12
(56
)
71
(232
)
(36
)
—
(197
)
—
366
4
—
370
$
656
$
637
$
65
$
(702
)
$
656
(UNAUDITED)
Power
Guarantor
Subsidiaries
Other
Subsidiaries
Consolidating
Adjustments
Consolidated
Total
(Millions)
For the Six Months Ended June 30, 2004
$
(70
)
$
207
$
(97
)
$
333
$
373
$
77
$
(99
)
$
(98
)
$
(142
)
$
(262
)
$
(7
)
$
(156
)
$
195
$
(153
)
$
(121
)
For the Six Months Ended June 30, 2003
$
261
$
736
$
8
$
(425
)
$
580
$
(403
)
$
(478
)
$
(11
)
$
546
$
(346
)
$
142
$
(270
)
$
12
$
(119
)
$
(235
)
As of June 30, 2004:
$
1,965
$
2,731
$
167
$
(3,160
)
$
1,703
41
2,856
1,897
1
4,795
3,247
762
—
(4,009
)
—
1,274
1,273
56
(1,214
)
1,389
$
6,527
$
7,622
$
2,120
$
(8,382
)
$
7,887
$
582
$
3,722
$
299
$
(3,249
)
$
1,354
48
673
30
(115
)
636
—
—
1,100
(1,100
)
—
3,316
—
—
—
3,316
2,581
3,227
691
(3,918
)
2,581
$
6,527
$
7,622
$
2,120
$
(8,382
)
$
7,887
As of December 31, 2003:
$
1,992
$
1,967
$
102
$
(2,282
)
$
1,779
28
2,724
1,812
17
4,581
3,330
733
—
(4,063
)
—
468
1,209
91
(397
)
1,371
$
5,818
$
6,633
$
2,005
$
(6,725
)
$
7,731
$
352
$
2,876
$
192
$
(2,355
)
$
1,065
44
485
11
(95
)
445
—
—
300
(300
)
—
2,816
—
800
—
3,616
2,606
3,272
702
(3,975
)
2,605
$
5,818
$
6,633
$
2,005
$
(6,725
)
$
7,731
(UNAUDITED)
CONDITION AND RESULTS OF OPERATIONS (MD&A)
Earnings (Losses)
Quarters Ended June 30,
Six Months Ended June 30,
2004
2003
2004
2003
(Millions)
$
63
$
22
$
188
$
123
52
109
161
286
14
24
15
37
9
16
58
66
(2
)
—
(4
)
(2
)
(17
)
(15
)
(28
)
(30
)
119
156
390
480
5
(5
)
5
(18
)
—
(18
)
—
(18
)
Principle (E)
—
—
—
370
$
124
$
133
$
395
$
814
Contribution to PSEG Earnings Per Share (Diluted)
Quarters Ended June 30,
Six Months Ended June 30,
2004
2003
2004
2003
$
0.26
$
0.10
$
0.79
$
0.54
0.22
0.48
0.68
1.27
0.06
0.10
0.06
0.16
0.04
0.07
0.24
0.28
(0.01
)
—
(0.01
)
(0.01
)
(0.07
)
(0.06
)
(0.12
)
(0.12
)
0.50
0.69
1.64
2.12
0.02
(0.02
)
0.02
(0.08
)
—
(0.08
)
—
(0.08
)
Principle (E)
—
—
—
1.64
$
0.52
$
0.59
$
1.66
$
3.60
(A)
Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings.
(B)
Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends requirements for PSE&G and Energy Holdings, interest on certain financing transactions and certain other administrative and general expenses at PSEG (as parent company).
(C)
Includes Discontinued Operations at Energy Holdings. See Note 4. Discontinued Operations and Dispositions of the Notes.
(D)
Relates to charge recorded in the second quarter of 2003 at PSE&G resulting from the decision issued by the BPU in PSE&G's Electric Base Rate Case. See Note 5. Extraordinary Item of the Notes.
(E)
Relates to the adoption of Statement of Financial Accounting Standard (SFAS) No. 143, “Asset Retirement Obligations” (SFAS 143) in 2003 at Power. See Note 3. Recent Accounting Standards of the Notes.
For the Quarters
Ended June 30,
For the
Six Months
Ended June 30,
2004
2003
Increase
(Decrease)
%
2004
2003
Increase
(Decrease)
%
(Millions)
(Millions)
$
2,290
$
2,401
$
(111
)
(5
)
$
5,511
$
5,689
$
(178
)
(3
)
$
1,254
$
1,400
$
(146
)
(10
)
$
3,077
$
3,353
$
(276
)
(8
)
Maintenance
$
537
$
488
$
49
10
$
1,083
$
1,007
$
76
8
Amortization
$
170
$
98
$
72
73
$
342
$
197
$
145
74
$
33
$
31
$
2
6
$
61
$
51
$
10
20
$
83
$
30
$
53
177
$
118
$
89
$
29
33
$
(31
)
$
(9
)
$
22
244
$
(54
)
$
(52
)
$
2
4
$
(214
)
$
(210
)
$
4
2
$
(437
)
$
(408
)
$
29
7
$
(52
)
$
(72
)
$
(20
)
(28
)
$
(232
)
$
(258
)
$
(26
)
(10
)
For the Quarters
Ended June 30,
For the
Six Months
Ended June 30,
2004
2003
Increase
(Decrease)
%
2004
2003
Increase
(Decrease)
%
(Millions)
(Millions)
$
1,418
$
1,342
$
76
6
$
3,600
$
3,490
$
110
3
$
824
$
919
$
(95
)
(10
)
$
2,243
$
2,426
$
(183
)
(8
)
$
258
$
224
$
34
15
$
536
$
510
$
26
5
$
126
$
63
$
63
100
$
253
$
129
$
124
96
$
3
$
3
$
—
—
$
6
$
13
$
(7
)
(54
)
$
—
$
—
$
—
—
$
(1
)
$
(1
)
$
—
—
$
(91
)
$
(97
)
$
(6
)
(6
)
$
(187
)
$
(194
)
$
(7
)
(4
)
$
(31
)
$
8
$
39
488
$
(125
)
$
(48
)
$
77
160
For the Quarters
Ended June 30,
For the
Six Months
Ended June 30,
2004
2003
Increase
(Decrease)
%
2004
2003
Increase
(Decrease)
%
(Millions)
(Millions)
$
993
$
1,235
$
(242
)
(20
)
$
2,685
$
3,065
$
(380
)
(12
)
$
681
$
787
$
(106
)
(13
)
$
1,905
$
2,078
$
(173
)
(8
)
$
237
$
228
$
9
4
$
467
$
430
$
37
9
$
28
$
24
$
4
17
$
55
$
47
$
8
17
$
77
$
25
$
52
208
$
112
$
69
$
43
62
$
(22
)
$
(10
)
$
12
120
$
(42
)
$
(40
)
$
2
5
$
(28
)
$
(28
)
$
—
—
$
(69
)
$
(56
)
$
13
23
$
(22
)
$
(74
)
$
(52
)
(70
)
$
(98
)
$
(197
)
$
(99
)
(50
)
For the
Quarters Ended
June 30,
For the
Six Months
Ended June 30,
2004
2003
Increase
(Decrease)
%
2004
2003
Increase
(Decrease)
%
(Millions)
(Millions)
$
177
$
171
$
6
4
$
390
$
361
$
29
8
$
48
$
41
$
7
17
$
94
$
76
$
18
24
$
50
$
41
$
9
22
$
99
$
76
$
23
30
$
12
$
10
$
2
20
$
25
$
18
$
7
39
$
33
$
31
$
2
6
$
61
$
51
$
10
20
$
2
$
3
$
(1
)
(33
)
$
3
$
7
$
(4
)
(57
)
$
(9
)
$
(1
)
$
8
800
$
(9
)
$
(4
)
$
5
125
$
(67
)
$
(53
)
$
14
26
$
(130
)
$
(101
)
$
29
29
$
(5
)
$
(17
)
$
(12
)
(71
)
$
(26
)
$
(36
)
$
(10
)
(28
)
Total Capital at Risk (A)
For the Quarters Ended June 30,
For the Six Months Ended June 30,
As of
EBIT (B)
Non-Recourse
Interest (C)
EBIT (B)
Non-Recourse
Interest (C)
June 30,
2004
December 31,
2003
2004
2003
2004
2003
2004
2003
2004
2003
(Millions)
$
402
$
424
$
9
$
21
$
—
$
—
$
64
$
76
$
—
$
—
1,573
1,575
35
34
4
5
70
66
10
8
191
180
3
2
—
—
8
5
—
—
237
309
7
—
8
—
20
10
16
—
94
91
3
2
4
—
10
2
8
—
—
—
(8
)
(7
)
—
—
(16
)
(15
)
—
—
$
2,497
$
2,579
$
49
$
52
$
16
$
5
$
156
$
144
$
34
$
8
$
49
$
52
$
156
$
144
(38
)
(28
)
(77
)
(54
)
(2
)
(6
)
(19
)
(17
)
—
(2
)
(2
)
(7
)
$
9
$
16
$
58
$
66
(A)
Total Capital at Risk includes Global's gross investments, net of equity adjustments, non-recourse debt at the project level and including equity commitment guarantees.
(B)
Includes Global's share of net earnings, including Interest Expense and Income Taxes, for investments accounted for under the equity method of accounting.
(C)
Non-recourse interest is Interest Expense on debt that is non-recourse to Global.
Moody's (A)
S&P (B)
Fitch (C)
Baa3(N)
BB+
BBB(NW)
P2(N)
A3
Not Rated
A3
A–
A(N)
Baa3
BB+
BBB+(N)
P2
A3
F1
Baa1
BBB(N)
BBB+(NW)
Ba3(N)
BB–
BB(N)
(A)
Moody's ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities.
(B)
S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (highest) to D (lowest) for short-term securities.
(C)
Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F-1 (highest) to D (lowest) for short-term securities.
(D)
Rating for PSE&G Cumulative Preferred Stock without Mandatory Redemption.
Company
Expiration Date
Total
Facility
Primary
Purpose
Usage as of
6/30/2004
Available
Liquidity as of
6/30/2004
(Millions)
April 2008
$
450
CP Support/
Funding/Letters
of Credit
$
402
$
48
March 2005
$
280
CP Support
$
—
$
280
December 2005
$
350
CP Support/
Funding/
Letters of Credit
$
—
$
350
N/A
N/A
Funding
$
50
N/A
April 2005
$
75
Funding
$
75
$
—
April 2005
$
25
Funding
$
25
$
—
June 2009
$
600
CP Support/
Funding/Letters
of Credit
$
142
$
458
N/A
N/A
Funding
$
80
N/A
April 2007
$
600
CP Support/
Funding/Letters
of Credit
$
44
(B)
$
556
August 2005
$
25
Funding/Letters
of Credit
$
12
(B)
$
13
October 2006
$
200
Funding/
Letters of
Credit
$
39
(B)
$
161
(A)
PSEG/Power co-borrower facility.
(B)
These amounts relate to letters of credit outstanding.
ABOUT MARKET RISK
Trading VaR (A)
Non-Trading
MTM VaR (A)
(Millions)
$
1
$
13
$
1
$
12
$
2
$
19
$
1
$
11
$
2
$
20
$
2
$
18
$
3
$
29
$
1
$
17
$
1
$
13
$
2
$
8
$
3
$
19
$
1
$
1
$
2
$
20
$
3
$
13
$
4
$
29
$
1
$
2
(A)
The VaR models are augmented to account for the fact that the natural log of energy-related commodity prices, especially emissions and are not normally distributed. Energy commodity price distributions have a higher frequency of extreme events than would be predicted by a normal distribution.
For the Quarter Ended June 30, 2004
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
$
24
$
(11
)
$
13
—
—
—
—
—
—
(11
)
4
(7
)
13
(7
)
6
11
(4
)
7
—
(1
)
(1
)
24
(12
)
12
981
—
981
$
1,005
$
(12
)
$
993
For the Six Months Ended June 30, 2004
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
$
25
$
(6
)
$
19
—
—
—
—
—
—
(10
)
13
3
15
7
22
10
(13
)
(3
)
—
(3
)
(3
)
25
(9
)
16
2,669
—
2,669
$
2,694
$
(9
)
$
2,685
(A)
Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions and hedging activities, but excludes owned and contracted generation assets.
As of June 30, 2004
Normal
Operations
and
Hedging
Trading
Total
(Millions)
$
22
$
150
$
172
12
36
48
$
34
$
186
$
220
$
(141
)
$
(138
)
$
(279
)
(156
)
(38
)
(194
)
$
(297
)
$
(176
)
$
(473
)
$
(263
)
$
10
$
(253
)
As of June 30, 2004
Maturities within
2004
2005
2006
2007-2008
Total
(Millions)
$
(1
)
$
15
$
(3
)
$
(1
)
$
10
(46
)
(135
)
(25
)
(57
)
(263
)
$
(47
)
$
(120
)
$
(28
)
$
(58
)
$
(253
)
As of June 30, 2004
Accumulated
OCI
Portion Expected
to be Reclassified
in next 12 months
(Millions)
$
(169
)
$
(78
)
(77
)
(27
)
—
—
$
(246
)
$
(105
)
As of June 30, 2004
Rating
Current
Exposure
Securities
Held as
Collateral
Net
Exposure
Number of
Counterparties
>10%
Net
Exposure of
Counterparties
>10%
(Millions)
(Millions)
$
260
$
69
$
216
2
$
96
30
12
22
—
—
9
—
9
—
—
66
2
63
1
50
$
365
$
83
$
310
3
$
146
Page 29.
(Power) Motions by
Old Dominion Electric Cooperative (ODEC) to reopen
proceedings against Power, Docket Nos. EL98-6-001
and EL03-45-000 and lawsuit filed on November 26, 2003 by Power against
ODEC, Docket No. 03-5678.
Page 31. (PSE&G and Power) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. Docket No. EX93060255.
Page 31. (PSE&G) PSE&G's MGP Remediation Program instituted by NJDEP's Coal Gasification Facility Sites letter dated March 25, 1988.
Page 34.
(PSE&G and Power) Filing of Complaint by Nuclear against the DOE on
September 26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-551C
seeking damages caused by the DOE's failure to take possession of spent
nuclear fuel.
Page 36. (PSE&G) Purported class action lawsuit against PSE&G demanding the utility move or shield gas meters located in allegedly dangerous locations, Docket No. GO03080640.
Page 36. (Energy Holdings) Peru's Internal Revenue Agency's (SUNAT) claim for past due taxes at Luz de Sur (LDS), Resolution No. 0150150000030, dated July 10, 2003.
Page 79. (PSE&G and Power) FERC proceeding regarding elimination of regional through and out rates. Midwest Independent System Operator et al., Docket No. EL02-111-000.
Page 80. (PSE&G and Power) FERC proceeding regarding affiliate relationships, standards of conduct for transmission providers. Docket No. RM01-10-000.
Page 80. (PSE&G and Power) FERC proceeding regarding revised generation market power screen, AEP Power Marketing, Inc. et al., Docket Nos. ER96-2495-016 et al., Market Based Rates for public utilities, Docket No. RM04-7-000.
Page 81. (PSE&G) PSE&G's Remediation Adjustment Clause filing with the BPU on April 22, 2004, Docket No. GR04040291.
Page 81. (PSE&G) PSE&G's Basic Gas Supply Service (BGSS) Commodity filing with the BPU on May 30, 2003, Docket No. EO03050394.
Page 81. (PSE&G) PSE&G's BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390.
Page 81. (PSE&G) BPU approval of increased USF rates on June 23, 2004, Docket No. EX00020091.
Page 82. (Energy Holdings) Action filed in the U.S. District Court for the Southern District of Texas alleging price-fixing, predatory pricing and certain common law claims, Docket No. CA No. C-03-249.
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
Exhibit 31: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 31.1: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 32: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32.1: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 4: Supplemental Indenture between PSE&G and Wachovia Bank, National Association, trustee, dated June 1, 2004 supplemental to Indenture dated August 1, 1924.
Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.2: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 31.3: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 32.2: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32.3: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.4: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
| Exhibit 31.5: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 |
| Exhibit 32.4: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| Exhibit 32.5: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
d. Energy Holdings:
| Exhibit 12.4: Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31.6: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 |
| Exhibit 31.7: Certification by Thomas M. O'Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 |
| Exhibit 32.6: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| Exhibit 32.7: Certification by Thomas M. O'Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
84
(B) Reports on Form 8-K: a. PSEG: b. PSE&G: c. Power: d. Energy Holdings: 85
Items Reported
Date of Report
Items 5 and 12
April 30, 2004
Items 5 and 12
July 30, 2004
Items Reported
Date of Report
Item 5
April 30, 2004
Item 5
July 30, 2004
Items Reported
Date of Report
Item 5
April 30, 2004
Item 5
July 30, 2004
Items Reported
Date of Report
Item 5
April 30, 2004
Item 5
July 30, 2004
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. Date: August 2, 2004 86
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant)
By: /s/ PATRICIA A. RADO
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. Date: August 2, 2004 87
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant)
By: /s/ PATRICIA A. RADO
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. Date: August 2, 2004 88
PSEG POWER LLC
(Registrant)
By: /s/ PATRICIA A. RADO
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. Date: August 2, 2004 89
PSEG ENERGY HOLDINGS LLC
(Registrant)
By: /s/ PATRICIA A. RADO
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)