UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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Commission |
Registrants, State of Incorporation, |
I.R.S. Employer |
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001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
22-2625848 |
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000-49614 |
PSEG POWER LLC |
22-3663480 |
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001-00973 |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY |
22-1212800 |
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 S No £
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
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Public Service Enterprise Group Incorporated |
Large accelerated filer S |
Accelerated filer £ |
Non-accelerated filer £ |
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PSEG Power LLC |
Large accelerated filer £ |
Accelerated filer £ |
Non-accelerated filer S |
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Public Service Electric and Gas Company |
Large accelerated filer £ |
Accelerated filer £ |
Non-accelerated filer S |
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No S
As of April 30, 2008, Public Service Enterprise Group Incorporated had outstanding 508,505,013 shares of its sole class of Common Stock, without par value.
PSEG Power LLC is a wholly owned subsidiary of Public Service Enterprise Group Incorporated and meets the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
As of April 30, 2008, 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.
TABLE OF CONTENTS
Page
ii
Item 1.
1
5
8
12
13
16
17
17
27
30
30
31
32
33
34
35
38
40
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
42
43
44
47
53
56
57
Item 3.
57
Item 4.
62
Item 1.
63
Item 1A.
63
Item 4.
64
Item 5.
65
Item 6.
70
71 i
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 “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of
such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves.
Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 5.
Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United
States Securities and Exchange Commission (SEC). These factors include, but are not limited to:
•
Adverse changes in energy industry, policies and regulation, including market rules that may adversely affect our operating results. • Any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and/or regulatory approvals from federal and/or state regulators. • Changes in federal and/or state environmental regulations that could increase our costs or limit operations of our generating units. • Changes in nuclear regulation and/or developments in the nuclear power industry generally, that could limit operations of our nuclear generating units. • Actions or activities at one of our nuclear units that might adversely affect our ability to continue to operate that unit or other units at the same site. • Any inability to balance our energy obligations, available supply and trading risks. • Any deterioration in our credit quality. • Any inability to realize anticipated tax benefits or retain tax credits. • Increases in the cost of or interruption in the supply of fuel and other commodities necessary to the operation of our generating units. • Delays or cost escalations in our construction and development activities. • Adverse capital market performance of our decommissioning and defined benefit plan trust funds. • Changes in technology and/or increased customer conservation. All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be
realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance
on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. Except as may be required by the federal
securities laws, we expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or
are anticipated to occur or arise after the date hereof. 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. ii
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For The Quarters
Ended
2008
2007
(Millions) OPERATING REVENUES
$
3,803
$
3,508 OPERATING EXPENSES Energy Costs
2,124
1,977 Operation and Maintenance
631
595 Depreciation and Amortization
194
192 Taxes Other Than Income Taxes
43
43 Total Operating Expenses
2,992
2,807 Income from Equity Method Investments
12
27 OPERATING INCOME
823
728 Other Income
93
72 Other Deductions
(94
)
(36
) Interest Expense
(153
)
(182
) Preferred Stock Dividends
(1
)
(1
) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
668
581 Income Tax Expense
(234
)
(260
) INCOME FROM CONTINUING OPERATIONS
434
321 Income from Discontinued Operations, net of tax (expense) benefit of ($6) and $1
14
8 NET INCOME
$
448
$
329 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC
508,490
505,784 DILUTED
510,107
506,711 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS
$
0.85
$
0.63 NET INCOME
$
0.88
$
0.65 DILUTED INCOME FROM CONTINUING OPERATIONS
$
0.85
$
0.63 NET INCOME
$
0.88
$
0.65 DIVIDENDS PAID PER SHARE OF COMMON STOCK
$
0.3225
$
0.2925 See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
March 31,
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
251
$
381 Accounts Receivable, net of allowances of $52 and $46 in 2008 and 2007, respectively
1,709
1,552 Unbilled Revenues
307
353 Fuel
390
793 Materials and Supplies
296
296 Prepayments
54
91 Restricted Funds
95
114 Derivative Contracts
189
65 Assets of Discontinued Operations
1,394
1,162 Other
36
29 Total Current Assets
4,721
4,836 PROPERTY, PLANT AND EQUIPMENT
19,571
19,310 Less: Accumulated Depreciation and Amortization
(6,121
)
(6,035
) Net Property, Plant and Equipment
13,450
13,275 NONCURRENT ASSETS Regulatory Assets
4,919
5,165 Long-Term Investments
3,205
3,246 Nuclear Decommissioning Trust (NDT) Funds
1,209
1,276 Other Special Funds
143
164 Goodwill and Other Intangibles
59
64 Derivative Contracts
56
52 Other
206
221 Total Noncurrent Assets
9,797
10,188 TOTAL ASSETS
$
27,968
$
28,299 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31,
(Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
607
$
1,123 Commercial Paper and Loans
128
65 Accounts Payable
993
1,093 Derivative Contracts
450
324 Accrued Interest
154
113 Accrued Taxes
318
204 Deferred Income Taxes
141
106 Clean Energy Program
121
135 Liabilities of Discontinued Operations
648
520 Other
605
537 Total Current Liabilities
4,165
4,220 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
4,234
4,454 Regulatory Liabilities
453
419 Asset Retirement Obligations
551
542 Other Postretirement Benefit (OPEB) Costs
1,007
1,003 Accrued Pension Costs
213
203 Clean Energy Program
—
14 Environmental Costs
646
649 Derivative Contracts
305
198 Long-Term Accrued Taxes
431
423 Other
123
133 Total Noncurrent Liabilities
7,963
8,038 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
6,588
6,783 Securitization Debt
1,487
1,530 Project Level, Non-Recourse Debt
339
349 Total Long-Term Debt
8,414
8,662 SUBSIDIARIES’ PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares
80
80 COMMON STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued; 2008—533,556,660 shares; 2007—533,556,660 shares
4,742
4,732 Treasury Stock, at cost; 2008—25,034,528 shares; 2007—25,033,656 shares
(483
)
(478
) Retained Earnings
3,523
3,261 Accumulated Other Comprehensive Loss
(436
)
(216
) Total Common Stockholders’ Equity
7,346
7,299 Total Capitalization
15,840
16,041 TOTAL LIABILITIES AND CAPITALIZATION
$
27,968
$
28,299 See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For The Three Months
2008
2007
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
448
$
329 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
193
196 Amortization of Nuclear Fuel
24
25 Provision for Deferred Income Taxes (Other than Leases) and ITC
2
(13
) Non-Cash Employee Benefit Plan Costs
42
46 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
(26
)
(15
) Gain on Sale of Investments
—
(16
) Undistributed Earnings from Affiliates
(21
)
32 Foreign Currency Transaction Loss
—
1 Unrealized (Gains) Losses on Energy Contracts and Other Derivatives
(20
)
34 Under Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
(38
)
(47
) Over (Under) Recovery of Societal Benefits Charge (SBC)
31
(1
) Cost of Removal
(9
)
(8
) Net Realized Gains (Losses) and Income (Expense) from NDT Funds
8
(19
) Net Change in Certain Current Assets and Liabilities
400
440 Employee Benefit Plan Funding and Related Payments
(24
)
(21
) Investment Income and Dividend Distributions from Partnerships
—
11 Other
33
(26
) Net Cash Provided By Operating Activities
1,043
948 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(323
)
(275
) Proceeds
from the Sale of Investments and Capital Leases
40
7 Proceeds from NDT Funds Sales
623
501 Investment in NDT Funds
(631
)
(511
) Restricted Funds
21
34 NDT Funds Interest and Dividends
11
12 Other
(3
)
(1
) Net Cash Used In Investing Activities
(262
)
(233
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans
63
(104
) Issuance of Long-Term Debt
300
— Issuance of Common Stock
—
33 Redemptions of Long-Term Debt
(1,013
)
(113
) Repayment of Non-Recourse Debt
(13
)
(16
) Redemption of Securitization Debt
(40
)
(38
) Premium Paid on Early Extinguishment of Debt
(48
)
— Cash Dividends Paid on Common Stock
(164
)
(148
) Other
4
5 Net Cash Used In Financing Activities
(911
)
(381
) Net (Decrease) Increase in Cash and Cash Equivalents
(130
)
334 Cash and Cash Equivalents at Beginning of Period
381
106 Cash and Cash Equivalents at End of Period
$
251
$
440 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
133
$
85 Interest Paid, Net of Amounts Capitalized
$
91
$
126 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
March 31,
(Unaudited)
PSEG POWER LLC
For The Quarters Ended
2008
2007
(Millions) OPERATING REVENUES
$
2,375
$
2,149 OPERATING EXPENSES Energy Costs
1,589
1,488 Operation and Maintenance
239
238 Depreciation and Amortization
38
34 Total Operating Expenses
1,866
1,760 OPERATING INCOME
509
389 Other Income
86
51 Other Deductions
(91
)
(29
) Interest Expense
(42
)
(37
) INCOME FROM CONTINUING OPERATIONS
462
374 Income Tax Expense
(187
)
(155
) INCOME FROM CONTINUING OPERATIONS
275
219 Loss from Discontinued Operations, net of tax benefit of $4
—
(6
) EARNINGS AVAILABLE TO PUBLIC SERVICE
$
275
$
213 See disclosures regarding PSEG Power LLC included in the 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
March 31,
(Unaudited)
BEFORE INCOME TAXES
ENTERPRISE GROUP INCORPORATED
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
9
$
11 Accounts Receivable
469
533 Accounts Receivable—Affiliated Companies, net
47
441 Short-Term Loan to Affiliate
407
— Fuel
387
791 Materials and Supplies
219
220 Energy Contracts
165
46 Restricted Funds
43
50 Prepayments
31
26 Other
33
31 Total Current Assets
1,810
2,149 PROPERTY, PLANT AND EQUIPMENT
6,667
6,565 Less: Accumulated Depreciation and Amortization
(1,830
)
(1,814
) Net Property, Plant and Equipment
4,837
4,751 NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC)
2
— Nuclear Decommissioning Trust (NDT) Funds
1,209
1,276 Goodwill
16
16 Other Intangibles
36
35 Other Special Funds
28
45 Energy Contracts
9
7 Other
57
57 Total Noncurrent Assets
1,357
1,436 TOTAL ASSETS
$
8,004
$
8,336 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Accounts Payable
$
615
$
648 Short-Term Loan from Affiliate
—
238 Energy Contracts
384
300 Accrued Interest
81
34 Other
124
118 Total Current Liabilities
1,204
1,338 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
—
176 Asset Retirement Obligations
315
309 Other Postretirement Benefit (OPEB) Costs
132
129 Energy Contracts
246
158 Accrued Pension Costs
71
70 Environmental Costs
55
55 Long-Term Accrued Taxes
28
26 Other
12
12 Total Noncurrent Liabilities
859
935 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt
2,902
2,902 MEMBER’S EQUITY Contributed Capital
2,000
2,000 Basis Adjustment
(986
)
(986
) Retained Earnings
2,588
2,438 Accumulated Other Comprehensive Loss
(563
)
(291
) Total Member’s Equity
3,039
3,161 TOTAL LIABILITIES AND MEMBER’S EQUITY
$
8,004
$
8,336 See disclosures regarding PSEG Power LLC included in the 6
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
For The Three Months
2008
2007
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
275
$
213 Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization
38
34 Amortization of Nuclear Fuel
24
25 Interest Accretion on Asset Retirement Obligations
6
6 Provision for Deferred Income Taxes and ITC
19
26 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives
(23
)
4 Non-Cash Employee Benefit Plan Costs
6
7 Net Realized Losses (Gains) and Income from NDT Funds
8
(19
) Net Change in Working Capital: Fuel, Materials and Supplies
405
490 Accounts Receivable
(58
)
(105
) Accounts Payable
(12
)
57 Accounts Receivable/Payable-Affiliated Companies, net
189
72 Accrued Interest Payable
47
46 Other Current Assets and Liabilities
(3
)
4 Employee Benefit Plan Funding and Related Payments
—
(1
) Other
17
(35
) Net Cash Provided By Operating Activities
938
824 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(174
)
(126
) Short-Term Loan—Affiliated Company, net
(407
)
(525
) Proceeds from NDT Funds Sales
623
501 NDT Funds Interest and Dividends
11
12 Investment in NDT Funds
(631
)
(511
) Restricted Funds
7
— Other
(6
)
(2
) Net Cash Used In Investing Activities
(577
)
(651
) CASH FLOWS FROM FINANCING ACTIVITIES Cash Dividend Paid
(125
)
(125
) Short-Term Loan—Affiliated Company, net
(238
)
(54
) Net Cash Used In Financing Activities
(363
)
(179
) Net Decrease in Cash and Cash Equivalents
(2
)
(6
) Cash and Cash Equivalents at Beginning of Period
11
13 Cash and Cash Equivalents at End of Period
$
9
$
7 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
19
$
24 Interest Paid, Net of Amounts Capitalized
$
3
$
3 See disclosures regarding PSEG Power LLC included in the 7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
March 31,
(Unaudited)
Operating Activities:
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For The Quarters
2008
2007
(Millions) OPERATING REVENUES
$
2,618
$
2,486 OPERATING EXPENSES Energy Costs
1,793
1,665 Operation and Maintenance
360
325 Depreciation and Amortization
143
145 Taxes Other Than Income Taxes
43
43 Total Operating Expenses
2,339
2,178 OPERATING INCOME
279
308 Other Income
5
5 Other Deductions
(1
)
(1
) Interest Expense
(81
)
(81
) INCOME BEFORE INCOME TAXES
202
231 Income Tax Expense
(65
)
(99
) NET INCOME
137
132 Preferred Stock Dividends
(1
)
(1
) EARNINGS AVAILABLE TO PUBLIC
$
136
$
131 See disclosures regarding PSEG Power LLC included in the 8
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
March 31,
(Unaudited)
SERVICE ENTERPRISE GROUP INCORPORATED
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
68
$
32 Accounts Receivable, net of allowances of $52 in 2008 and $45 in 2007
1,171
995 Unbilled Revenues
307
353 Materials and Supplies
59
53 Prepayments
7
57 Restricted Funds
10
7 Derivative Contracts
1
1 Deferred Income Taxes
47
44 Total Current Assets
1,670
1,542 PROPERTY, PLANT AND EQUIPMENT
11,678
11,531 Less: Accumulated Depreciation and Amortization
(3,980
)
(3,920
) Net Property, Plant and Equipment
7,698
7,611 NONCURRENT ASSETS Regulatory Assets
4,919
5,165 Long-Term Investments
154
153 Other Special Funds
48
57 Other
100
109 Total Noncurrent Assets
5,221
5,484 TOTAL ASSETS
$
14,589
$
14,637 See disclosures regarding Public Service Electric and Gas Company included in the 9
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31,
(Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
524
$
429 Commercial Paper and Loans
128
65 Accounts Payable
287
325 Accounts Payable—Affiliated Companies, net
297
559 Accrued Interest
53
56 Accrued Taxes
67
29 Clean Energy Program
121
135 Derivative Contracts
25
20 Other
422
318 Total Current Liabilities
1,924
1,936 NONCURRENT LIABILITIES Deferred Income Taxes and ITC
2,442
2,440 Other Postretirement Benefit (OPEB) Costs
820
821 Accrued Pension Costs
64
63 Regulatory Liabilities
453
419 Clean Energy Program
—
14 Environmental Costs
591
594 Asset Retirement Obligations
234
231 Derivative Contracts
53
36 Long-Term Accrued Taxes
100
75 Other
9
9 Total Noncurrent Liabilities
4,766
4,702 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
2,909
3,102 Securitization Debt
1,487
1,530 Total Long-Term Debt
4,396
4,632 PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares
80
80 COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding
892
892 Contributed Capital
170
170 Basis Adjustment
986
986 Retained Earnings
1,373
1,237 Accumulated Other Comprehensive Income
2
2 Total Common Stockholder’s Equity
3,423
3,287 Total Capitalization
7,899
7,999 TOTAL LIABILITIES AND CAPITALIZATION
$
14,589
$
14,637 See disclosures regarding Public Service Electric and Gas Company included in 10
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For The Three Months
Ended
2008
2007
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
137
$
132 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
143
145 Provision for Deferred Income Taxes and ITC
(13
)
(24
) Non-Cash Employee Benefit Plan Costs
33
35 Non-Cash Interest Expense
1
1 Cost of Removal
(9
)
(8
) Employee Benefit Plan Funding and Related Payments
(19
)
(16
) Over Recovery of Electric Energy Costs (BGS and NTC)
15
4 Under Recovery of Gas Costs
(53
)
(51
) Over (Under) Recovery of SBC
31
(1
) Other Non-Cash Charges
(1
)
(1
) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues
(130
)
(269
) Materials and Supplies
(6
)
(7
) Prepayments
50
(4
) Accrued Taxes
37
41 Accrued Interest
(3
)
(11
) Accounts Payable
(38
)
7 Accounts Receivable/Payable-Affiliated Companies, net
(20
)
59 Other Current Assets and Liabilities
98
27 Other
8
2 Net Cash Provided By Operating Activities
261
61 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(145
)
(130
) Net Cash Used In Investing Activities
(145
)
(130
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt
63
238 Issuance of Long-Term Debt
300
— Redemption of Long-Term Debt
(401
)
(113
) Redemption of Securitization Debt
(40
)
(38
) Deferred Issuance Costs
(1
)
— Preferred Stock Dividends
(1
)
(1
) Net Cash (Used In) Provided By Financing Activities
(80
)
86 Net Increase In Cash and Cash Equivalents
36
17 Cash and Cash Equivalents at Beginning of Period
32
28 Cash and Cash Equivalents at End of Period
$
68
$
45 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
—
$
49 Interest Paid, Net of Amounts Capitalized
$
81
$
88 See disclosures regarding Public Service Electric and Gas Company 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
March 31,
(Unaudited)
included in the Notes to Condensed Consolidated Financial Statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information
contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G 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: Power, PSE&G, PSEG Energy Holdings L.L.C. (Energy Holdings) and PSEG Services Corporation (Services). Power Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and
marketing and risk management function through 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 Power’s portfolio. Fossil, Nuclear and ER&T are subject to
regulation by the Federal Energy Regulatory Commission (FERC) and Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC). PSE&G PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to
regulation by the New Jersey Board of Public Utilities (BPU) and the FERC. PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain
transition properties from PSE&G and issued transition bonds secured by such properties. The transition properties consist principally of the statutory rights to receive electricity consumption-based per
kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation,
as approved by the BPU. Energy Holdings Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which primarily owns and operates domestic and international projects engaged in the generation of
energy and PSEG Resources L.L.C. (Resources), which has invested primarily in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a
commercial real estate property management business. Global has reduced its international risk by monetizing the majority of its international investments. In December 2007, Global announced that it intends to sell its largest remaining international
investment in the SAESA Group. For additional information, see Note 3. Discontinued Operations. Global is also continuing to explore options for its other remaining international investments in Italy,
Venezuela and India, which had a total book asset value of approximately $123 million as of March 31, 2008. 12
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Services Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, financial risk management, law, tax, planning, information
technology, investor relations and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to an intercompany service agreement. Basis of Presentation PSEG, Power and PSE&G 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 accounting principles generally accepted in the United States (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, Power’s and PSE&G’s respective Annual Reports on Form 10-K for the year ended December 31, 2007. 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 year ended December 31, 2007. Reclassifications PSEG and Power Certain reclassifications have been made to the prior period financial statements to conform to the 2008 presentation. In accordance with a new policy established in the first quarter of 2008, Power has
adjusted its Condensed Consolidated Balance Sheet as of December 31, 2007 to net the fair value of cash collateral receivables and payables with the corresponding net derivative balances. See Note 2.
Recent Accounting Standards for additional information. In addition, operating results for the SAESA Group and Electroandes S.A. (Electroandes) were reclassified to Income from Discontinued
Operations on the Condensed Consolidated Statement of Operations of PSEG for the first quarter of 2007. See Note 3. Discontinued Operations. Note 2. Recent Accounting Standards The following accounting standards were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG, Power and PSE&G. Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007), “Business Combinations” (SFAS 141(R)) PSEG, Power and PSE&G In December 2007, the FASB issued SFAS 141(R) which replaces SFAS No. 141 “Business Combinations.” SFAS 141(R) will change financial accounting and reporting of business combination
transactions. It is based on the principle that all the assets acquired and the liabilities assumed in a business combination should be measured at their acquisition date fair values, with limited exceptions. This
standard applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree. The standard also expands the definition of a business. A transaction formerly
recorded as an asset acquisition may qualify as a business combination under SFAS 141(R). It also requires that acquisition-related costs and certain restructuring costs be recognized separately from the
business combination. 13
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS SFAS 141(R) is effective for all business combinations with an acquisition date on or after the beginning of fiscal years commencing on or after December 15, 2008. Earlier adoption is prohibited. SFAS
141(R) is required to be adopted concurrently with SFAS 160. PSEG, Power and PSE&G will adopt SFAS 141(R) effective January 1, 2009. Accordingly, all business combinations for which the acquisition
date is on or after January 1, 2009 will be accounted for under this new guidance. PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements upon adoption. SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS 160) PSEG, Power and PSE&G In December 2007, the FASB issued SFAS 160 which significantly changes the financial reporting relationship between a parent and non-controlling interests (i.e. minority interests). SFAS 160 requires
all entities to report minority interests in subsidiaries as a separate component of equity in the consolidated financial statements. Accordingly, the amount of net income attributable to the noncontrolling
interest is required to be included in consolidated net income on the face of the income statement. Further, SFAS 160 requires that the transactions between a parent and noncontrolling interests should be
treated as equity. However, if a subsidiary is deconsolidated, a parent is required to recognize a gain or loss. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. SFAS 160 will be applied prospectively, except for presentation and disclosure
requirements which are required to be applied retrospectively. PSEG, Power and PSE&G will adopt SFAS 160 effective January 1, 2009. PSEG, Power and PSE&G do not anticipate a material impact to their
respective financial statements upon adoption. SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (SFAS 161) PSEG, Power and PSE&G In March 2008, the FASB issued SFAS 161 which expands derivative disclosures by requiring an entity to disclose: i) an understanding of how and why an entity uses derivatives, ii) an understanding of
how derivatives and related hedged items are accounted for and iii) transparency into the overall impact of derivatives on an entity’s financial statements. SFAS 161 is effective for fiscal years beginning on or after November 15, 2008. Earlier adoption is encouraged. PSEG, Power and PSE&G are currently analyzing the requirements of SFAS 161 and will
adopt the standard on January 1, 2009. As SFAS 161 provides only disclosure requirements, PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements. The following new accounting standards were adopted by PSEG, Power and PSE&G during 2008. SFAS No. 157, “Fair Value Measurements” (SFAS 157) PSEG, Power and PSE&G In September 2006, the FASB issued SFAS 157 which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.
Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific
measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own
assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets. SFAS 157 also nullifies the guidance in footnote 3 of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved 14
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS in Energy Trading and Risk Management Activities” (EITF 02-3). The guidance in footnote 3 applied to derivative (and other) instruments measured at fair value at initial recognition under SFAS 133.
That guidance precluded immediate recognition in earnings of an unrealized gain or loss, measured as the difference between the transaction price and the fair value of the instrument at initial recognition,
if the fair value of the instrument was determined using significant unobservable inputs. Under this guidance, an entity could not recognize an unrealized gain or loss at inception of a derivative instrument
unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions or based on
a valuation technique incorporating observable market data. SFAS 157 requires that the principles of fair value measurement should be applied for derivatives and other financial instruments at initial
recognition and in all subsequent periods. At December 31, 2007, PSEG had a deferred inception loss of $34 million (pre-tax) related to Global’s Texas generation facilities. In accordance with the provisions
of SFAS 157, PSEG recorded a cumulative effect adjustment of $22 million (after-tax) to January 1, 2008 Retained Earnings associated with the implementation of SFAS 157. PSEG, Power and PSE&G adopted SFAS 157 (except for non-financial assets and liabilities as described in FASB Staff Position (FSP) FAS 157-2) effective January 1, 2008. In February 2008, the FASB
issued FSP FAS 157-2 to partially defer the effective date of SFAS 157 for certain nonfinancial assets and nonfinancial liabilities. In February 2008, the FASB also issued FSP FAS 157-1 to exclude leasing
transactions from SFAS 157’s scope. For additional information, see Note 13. Fair Value Measurements. SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) PSEG, Power and PSE&G In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair
value. An entity would report unrealized gains and losses in earnings at each subsequent reporting date on items for which the fair value option has been elected. The objective is to improve financial
reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting
provisions. The decision whether to elect the fair value option is applied instrument by instrument, with a few exceptions. The decision is irrevocable and it is required to be applied only to entire
instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities; and (b) between assets and liabilities in
the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS 159 is effective for financial statements issued for fiscal years beginning after
November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. PSEG, Power and PSE&G adopted SFAS 159 effective January 1, 2008; however, to date, PSEG, Power and PSE&G have not elected to measure any of their respective assets or liabilities at fair value
under this standard. FSP FIN 39-1, “An amendment of FASB Interpretation No. 39” (FSP FIN 39-1) PSEG and Power In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, “Offsetting of Amounts Related to Certain Contracts” to permit an entity to offset cash collateral paid or received against fair
value amounts recognized for derivative instruments held with the same counterparty under the same master netting arrangement. PSEG and Power adopted the FSP effective January 1, 2008. In accordance with the provisions of FIN 39-1, PSEG and Power established a policy of netting fair value cash collateral receivables and
payables with the corresponding net derivative balances. The adoption of FSP FIN 39-1 resulted in PSEG and Power 15
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS offsetting cash collateral receivables of $209 million against net derivative positions as of March 31, 2008. Amounts in prior period statements have been retroactively adjusted, as required under the FSP. Note 3. Discontinued Operations Power On May 16, 2007, Power completed the sale of Lawrenceburg, a 1,096-megawatt (MW), gas-fired combined cycle electric generating plant located in Lawrenceburg, Indiana, to AEP Generating
Company, a subsidiary of American Electric Power Company, Inc. (AEP) for a sale price of $325 million. Lawrenceburg’s operating results for the quarter ended March 31, 2007, which are included in Discontinued Operations, are summarized below:
Quarter Ended
(Millions) Operating Revenues
$
— Loss Before Income Taxes
$
(10
) Net Loss
$
(6
) Energy Holdings SAESA Group On December 18, 2007, Global announced that it intends to sell its investment in the SAESA Group. The SAESA Group consists of four distribution companies, one transmission company and a
generation facility located in Chile. SAESA Group’s operating results for the quarters ended March 31, 2008 and 2007, which are included in Discontinued Operations, are summarized below:
Quarters Ended
2008
2007
(Millions) Operating Revenues
$
186
$
94 Income Before Income Taxes
$
20
$
16 Net Income
$
14
$
14 The carrying amounts of SAESA Group’s assets as of March 31, 2008 and December 31, 2007 are summarized in the following table:
As of
As of
(Millions) Current Assets
$
264
$
191 Noncurrent Assets
1,130
971 Total Assets of Discontinued Operations
$
1,394
$
1,162 Current Liabilities
$
206
$
130 Noncurrent Liabilities
442
390 Total Liabilities of Discontinued Operations
$
648
$
520 Electroandes On September 19, 2007, Global entered into an agreement for the sale of Electroandes, a hydro-electric generation and transmission company in Peru that owns and operates four hydro-generation
plants with total capacity of 180 MW and 437 miles of electric transmission lines. 16
(UNAUDITED)
March 31,
2007
March 31,
March 31,
2008
December 31,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The sale was completed on October 17, 2007 for a total purchase price of $390 million, including the assumption of approximately $108 million of debt. Electroandes’ operating results for the quarter ended March 31, 2007, which are included in Discontinued Operations, are summarized below:
Quarter Ended
(Millions) Operating Revenues
$
11 Income Before Income Taxes
$
1 Net Income
$
— Note 4. Earnings Per Share (EPS) PSEG Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or
vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock
options, restricted stock awards, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
Quarters Ended March 31,
2008
2007
Basic
Diluted
Basic
Diluted EPS Numerator: Earnings (Millions) Continuing Operations
$
434
$
434
$
321
$
321 Discontinued Operations
14
14
8
8 Net Income
$
448
$
448
$
329
$
329 EPS Denominator (Thousands): Weighted Average Common Shares Outstanding
508,490
508,490
505,784
505,784 Effect of Stock Options
—
539
—
780 Effect of Stock Performance Units
—
965
—
147 Effect of Restricted Stock
—
19
—
— Effect of Restricted Stock Units
—
94
—
— Total Shares
508,490
510,107
505,784
506,711 EPS: Continuing Operations
$
0.85
$
0.85
$
0.63
$
0.63 Discontinued Operations
0.03
0.03
0.02
0.02 Net Income
$
0.88
$
0.88
$
0.65
$
0.65 Dividend payments on common stock for the quarter ended March 31, 2008 were $0.3225 per share and totaled $164 million. Dividend payments on common stock for the quarter ended March 31, 2007
were $0.2925 per share and totaled $148 million. Note 5. Commitments and Contingent Liabilities Guaranteed Obligations Power Power contracts for electricity, natural gas, oil, coal, pipeline capacity, transportation and emission allowances and engages in risk management activities through ER&T. These activities primarily involve
the 17
(UNAUDITED)
March 31,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are executed with numerous counterparties
and brokers. Counterparties and brokers may require guarantees, cash or cash-related instruments to be deposited on these transactions as described below. Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions to support current exposure, interest
and other costs on sums due and payable in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit. Under these agreements, guarantees 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 March 31, 2008 and
December 31, 2007 was $1.5 billion. In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to them by every counterparty to whom
Power has provided a guarantee and all of ER&T’s and Power New York’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
The probability of all contracts at ER&T and Power New York being simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. 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 if ER&T and/or Power New York were to default. This 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 $530 million and $521 million as of March 31,
2008 and December 31, 2007, respectively. Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements.
Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts. As of March 31, 2008 and December 31, 2007,
Power had the following margin posted and received to satisfy collateral obligations, which were primarily in the form of letters of credit:
As of
As of
(Millions) Margin Posted
$
582
$
188 Margin Received
$
29
$
44 Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. Generally, such futures contracts require a deposit of cash margin, the amount of
which is subject to change based on market movement and in accordance with exchange rules. As of March 31, 2008 and December 31, 2007, Power had deposited margin of $234 million and $168 million,
respectively. In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the
counterparty to demand that ER&T provide further performance assurance. Transactions that are margined and monitored separately from physical trading activity may not be subject to change in the event
of a downgrade to Power’s rating. As of March 31, 2008, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to
demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to $957 million. Power believes that it has the ability to post such collateral, if
necessary. In addition to amounts discussed above, Power had posted $37 million in letters of credit as of March 31, 2008 and December 31, 2007 to support various other contractual and environmental
obligations. 18
(UNAUDITED)
March 31,
2008
December 31,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Environmental Matters PSEG, Power and PSE&G Passaic River 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 electric generating station (Essex Site),
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 Clause (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 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 Power and 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 had been 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 estimated that its study would require five to eight years to complete and would cost $20 million, of which
it would seek to recover $10 million from the PRPs, including Power and PSE&G. In 2006, the EPA notified the PRPs that the cost of its study will greatly exceed the $20 million initially estimated and after discussion, 70 (now 73) PRPs, including Power and PSE&G, have agreed to
assume responsibility for the study pursuant to an Administrative Order on Consent and to divide the associated costs among themselves according to a mutually agreed-upon formula. The PRP group is
presently executing the study. The percentage allocable to Power and PSE&G varies depending on the number of PRPs who have agreed to divide the costs but it currently approximates 6%, approximately
80% of which is attributable to PSE&G’s former MGPs and approximately 20% to Power’s generating station. Power has provided notice to insurers concerning this potential claim. In June 2007, the EPA announced a draft Focused Feasibility Study (FFS) that proposes six options with estimated costs ranging from $900 million to $2.3 billion to address contamination cleanup in
the lower eight miles of the Passaic River in addition to a “No Action” alternative. The work contemplated by the FFS is not subject to the Administrative Order on Consent or the cost sharing agreement.
The EPA is reviewing comments received on the draft FFS. CERCLA and the New Jersey Spill Compensation and Control Act (Spill Act) authorize federal and state trustees for natural resources to assess damages against persons who have discharged a
hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the New Jersey Department of Environmental Protection (NJDEP) requires persons conducting remediation to
characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP has regulations in effect 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. 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 Spill 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. On August 2, 2007, the National Oceanic
and Atmospheric Administration of the United States Department of Commerce sent a letter to PSE&G and other companies identified as PRPs notifying them that it intended to perform an 19
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS assessment of injuries to natural resources and inviting the PRPs to participate. The PRPs have not agreed to participate in either of these natural resource damage initiatives. PSEG cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River. However, such costs could be material. Newark Bay Study Area The EPA sent PSEG and 11 other entities notices that the EPA considered each of the entities to be a PRP with respect to contamination in the Newark Bay Study Area, which it defined as Newark
Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. The notice letter requested that the PRPs participate and fund the EPA-approved study in the Newark Bay Study Area
and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study (RI/FS) that OCC is conducting in the Newark Bay
Study Area. The EPA considers the Newark Bay Study Area, along with the Passaic River Study Area, to be part of the Diamond Alkali Superfund Site. The notice states the EPA’s belief that hazardous
substances were released from sites owned by PSEG and located on the Hackensack River. The sites included two operating electric generating stations (Hudson and Kearny sites), and one former MGP.
PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. The Hudson and Kearny sites were 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 Hudson and Kearny sites. Power has provided notice to insurers concerning this potential claim.
PSEG cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Newark Bay Study Area. However, such costs could be material. Other On June 29, 2007, the State of New Jersey filed multiple lawsuits against parties, including PSE&G, who were alleged to be responsible for injuries to natural resources in New Jersey. Included in these
lawsuits was a claim against PSE&G and others arising out of PSE&G’s former Camden Coke facility, and a claim against PSE&G and others arising out of the Global Landfill matter. PSE&G has responded to
the complaint in the natural resource damages case arising out of the former Camden Coke site and is in the process of remediating that site under its MGP program, discussed below. The time for PSE&G to
answer the complaint in the natural resource damages case arising out of the Global Landfill matter has been delayed until June 2008 to allow the parties to negotiate an order that would resolve the natural
resource damages claim. In March 2008, Power executed an Amended Consent Decree, which obligates the settling parties (including PSE&G) to implement remediation of the Global Landfill site and
resolves the natural resource damages claim. PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River,
Newark Bay or other natural resource damages claims; 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 remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have
been identified as sites requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying
surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant sites
for cleanup. One of the sites identified is PSE&G’s former Camden Coke facility located in Camden. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based
on regulatory requirements, experience with the program and available remediation technologies. During the fourth quarter of 2007, PSE&G refined the detailed site estimates. Based on that review, the remaining cost of remediating all sites to completion, as well as the anticipated costs to address
MGP-related material discovered in three rivers adjacent to two former MGP sites, could range between $639 million and 20
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS $812 million through 2021. Since no amount within the range was considered to be most likely, PSE&G increased its accrual to $639 million as the low end of the range as of December 31, 2007. As of March
31, 2008, PSE&G’s remaining accrual was $636 million, which represents the low end of the range less $3 million of costs incurred in 2008. Of this amount, $45 million was recorded in Other Current
Liabilities and $591 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G
ratepayers. As such, PSE&G has a Regulatory Asset recorded which is equivalent to the accrued liability. Power Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act, 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 may order companies that are not in compliance with the PSD/NSR regulations to
install the best available control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation. On November 30, 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets consistent with an earlier consent decree that resolved allegations of non-
compliance with PSD/NSR programs at Power’s Mercer, Hudson and Bergen generating stations. Under this agreement and the consent decree, Power is required to undertake a number of technology
projects, plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide, nitrogen oxide (NOx), particulate matter and
mercury. Pursuant to this program, Power has installed selective catalytic reductions at Mercer at a cost of $122 million. The cost of implementing the balance of the agreement is estimated at $475 million to
$525 million for Mercer, to be completed by May 2010, and $700 million to $750 million for Hudson, to be completed by the end of 2010. Fossil also purchased and retired emissions allowances by July 31,
2007, paid a $6 million civil penalty and has agreed to contribute $3 million for programs to reduce particulate emissions from diesel engines in New Jersey. In March 2007, Fossil entered into an
engineering, procurement and construction contract with a third party contractor to complete all back-end technology requirements for the Mercer station, as referenced above. Fossil signed a contract for
construction management related to the Hudson back-end technology construction in July 2007. Mercury Regulation In March 2005, the EPA established a New Source Performance Standard limit for nickel emissions from oil-fired electric generating units, and a cap-and-trade program for mercury emissions from
coal-fired electric generating units, with a first phase cap of 38 tons per year (tpy) in 2010 and a second phase cap of 15 tpy in 2018 (the ‘Clean Air Mercury Rule’). The United States Court of Appeals for
the District of Columbia Circuit issued a decision on February 8, 2008 rejecting the EPA’s mercury emissions program. As a result of this decision, the EPA is required to develop emissions standards for
mercury and nickel emissions that do not rely on a cap-and-trade program. The full impact, if any, of this development is uncertain until the EPA issues the new emissions standards. Compliance with the
new mercury standards, however, is not expected to have a material impact on Power’s operations in New Jersey and Connecticut given the stringent mercury control requirements applicable in those states,
as described below. New Jersey and Connecticut had adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The regulations in New Jersey required the units to meet certain
emissions limits or reduce emissions by 90% by December 15, 2007, unless a one-year extension was granted by NJDEP. Under the New Jersey regulations, companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity
until December 15, 2012. With respect to Power’s New Jersey facilities, half of the reductions that were required 21
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS by December 15, 2007 are expected to be achieved through the installation of carbon injection technology at both Mercer Units, which was completed in January 2007. Because there is some uncertainty as
to whether the system can consistently achieve the required reductions, Power has applied for and received from NJDEP approval of a one-year extension through a facility-specific control plan that
includes the installation of baghouses at the Mercer Units in 2008. Installation is scheduled to be completed by the end of 2008. At its Hudson plant, Power anticipates compliance consisting of the
installation of a baghouse by the end of 2010. The mercury control technologies are also part of Power’s multi-pollutant reduction agreement, which resulted from earlier agreements that resolved issues arising out of the PSD/NSR air pollution
control programs discussed above. Mercury emissions control standards effective in July 2008 in Connecticut require coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency
through technology installed to control mercury emissions. Power anticipates compliance at its Bridgeport Harbor Station resulting from the installation of a baghouse which was placed in operation in
January 2008. In February 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal-fired electric generating units. The Keystone and Conemaugh generating stations will
be positioned by 2010 to meet Phase I of the Pennsylvania mercury rule by benefiting from reductions realized from the installation of controls for compliance with SO2 and NOx reductions. Phase 2 of the
mercury rule will be addressed after a full evaluation of Phase 1 reductions. Some uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute. However, the estimated costs of
technology believed to be capable of meeting these emissions limits at Power’s coal-fired units in Connecticut, New Jersey and Pennsylvania have been incurred or are included in Power’s capital
expenditure forecast. Total estimated costs for each project are between $150 million and $200 million. The costs for Mercer and Hudson are included in the cost estimates referred to in the PSD/NSR
discussion above. Emission Fees Section
185 of the Clean Air Act requires states (or in the absence of state action,
the EPA) in severe and extreme non-attainment areas to adopt a penalty fee
for major stationary sources if the area fails to attain the one-hour ozone
National Ambient Air Quality Standard (NAAQS) set by the EPA. In June 2007,
the U.S. Court of Appeals for the District of Columbia Circuit ruled against
the EPA, which had sought to vacate imposition of fees for NOx emissions
as part of the one-hour standard for ozone attainment implementation. Power
operates electric generation stations, major stationary sources, in the New
Jersey-Connecticut severe non-attainment area that failed to meet the required
NAAQS. Neither EPA nor the states in the non-attainment areas in which Power
operates have completed the process for imposing fees in compliance with
the court ruling; however, preliminary analysis suggests that penalty fees
will be approximately $6 million annually. This analysis could change if
the EPA or the states issue additional guidance addressing the imposition
of fees, or if Power is able to reduce its emissions of NOx in
the future below the statutory threshold through the installation of control
technologies at one or more of Power’s generation stations. New Jersey Industrial Site Recovery Act (ISRA) Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s
generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability as of each of March 31, 2008 and December 31,
2007 related to these obligations, which is included in Environmental Costs on Power’s and PSEG’s Condensed Consolidated Balance Sheets. Permit Renewals In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with
its 22
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS existing cooling water intake system. A renewal application prepared in accordance with the Federal Water Pollution Control Act (FWPCA) Section 316(b) and the Phase II 316(b) rule was filed in January
2006 with the NJDEP, which allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power’s application to renew Salem’s NJPDES permit demonstrates that
the station satisfies FWPCA Section 316(b) and meets the Phase II 316(b) rule’s performance standards for reduction of impingement and entrainment through the station’s existing cooling water intake
technology and operations plus implemented restoration measures. The application further demonstrates that even without the benefits of restoration, the station meets the Phase II 316(b) rule’s site-specific
determination standards, both on a comparison of the costs and benefits of new intake technology as well as a comparison of the costs to implement the technology at the facility to the cost estimates
prepared by the EPA. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its decision in litigation of the Phase II 316(b) regulations brought by several environmental groups, the Attorneys General
of six Northeastern states, including New Jersey, the Utility Water Act Group and several of its members, including Power. The court remanded major portions of the regulations and determined that
Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. The court instructed the EPA to reconsider the definition of “best technology available” without
comparing the costs of the best performing technology to its benefits. Prior to this decision, Power had used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits
at its once-through cooled plants, including Salem, Hudson and Mercer. In May 2007, Power and other industry petitioners filed with the Second Circuit Court a request for a rehearing, which was denied. The parties, including Power, requested U.S. Supreme Court review
of the matter. On April 14, 2008, the U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the FWPCA allows EPA to
compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake structures. Oral argument will occur in the Court’s 2008-
2009 term, which begins in October 2008. It is anticipated that the Court will render a decision during that term. Although the rule applies to all of Power’s electric generating units that use surface waters for once-through cooling purposes, the impact of the rule and the decision of the Second Circuit Court cannot
be determined at this time for all of Power’s facilities. Depending on the final decision of the U.S. Supreme Court, and subsequent actions by the EPA to promulgate a revised rule, the Second Circuit’s
decision could have a material impact on Power’s ability to renew its New Jersey and Connecticut permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and,
possibly, Sewaren and New Haven, without making significant upgrades to their existing intake structures and cooling systems. If the NJDEP and the Connecticut Department of Environmental Protection
were to require installation of closed-cycle cooling or its equivalent at these once-through cooled facilities, the related costs and impacts would be material to Power and would require economic review to
determine whether to continue operations. For example, Power’s application to renew its Salem permit, filed in February 2006 with the NJDEP, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of
which Power’s share would be approximately $575 million. Potential costs associated with any closed-cycle cooling requirements are not included in Power’s currently forecasted capital expenditures. New Generation and Development Power Power plans to modestly increase its generating capacity at Hope Creek and Salem Unit 2 in 2008. Phase I of the Hope Creek turbine replacement project increased the capacity of the unit by 10 MW
in 2005, and Phase II, which is expected to add approximately 125 MW of capacity, is expected to be completed and in operation in the second quarter of 2008. Phase I of the Salem Unit 2 turbine upgrade
increased Power’s share of the capacity by 14 MW in 2003. Phase II is currently scheduled to be completed and in operation in the second quarter of 2008, concurrent with steam generator replacement and
is anticipated to increase Power’s share of the capacity by an additional 15 MW. As of March 31, 2008, Power’s expenditures for these projects 23
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS were $203 million (including IDC of $24 million) with an aggregate estimated share of total costs for these projects of $216 million (including IDC of $28 million). Completion of the projects discussed above 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. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) Power and PSE&G PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for customers who do not purchase electric supply from third-party suppliers. PSE&G enters into the Supplier
Master Agreement (SMA) with the winners of these BGS auctions within three business days following the BPU’s approval. PSE&G has entered into contracts with Power, as well as with other winning BGS
suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Interconnection L.L.C. (PJM) Load Serving
Entity including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any customer migration risk and must satisfy New Jersey’s renewable
portfolio standards. Power seeks to mitigate volatility in its results by contracting in advance for its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts
to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In
addition to the BGS-related contracts, Power enters into firm supply contracts with EDCs, as well as other firm sales and commitments. PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows:
Auction Year
2005
2006
2007
2008 36 Month Terms Ending
May 2008
May 2009
May 2010
May 2011(a
) Load (MW)
2,840
2,882
2,758
2,840 $ per kWh
$
0.06541
$
0.10251
$
0.09888
$
0.1115
(a)
Prices set in the February 2008 BGS Auction are effective on June 1, 2008 when the 2005 Auction Year agreements expire.
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has
entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of
PSE&G’s residential gas supply annually through the BGSS tariff. For additional information, see Note 14. Related-Party Transactions. The BPU is currently conducting an audit of the gas procurement practices of all four New Jersey gas utilities, including PSE&G. The outcome of this proceeding cannot be predicted. Minimum Fuel Purchase Requirements Power Coal Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. As of March 31, 2008, the total minimum purchase requirements included in these
commitments amount to approximately $1.1 billion through 2012. 24
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Uranium Power has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations. Power has inventory and commitments to purchase sufficient
quantities of uranium concentrates to meet 100% of its total estimated requirements through 2011 and approximately 60% of its estimated requirements for 2012. Additionally, Power has commitments for
uranium hexafluoride to meet 100% of its estimated requirements for 2011 and 92% for 2012. These commitments, based on current market prices, which have increased substantially over the past two to
three years, total $422 million ($285 million Power’s estimated share). Power’s policy is to maintain certain levels of concentrates and uranium hexafluoride in inventory and to make periodic purchases to
support such levels. As such, the commitments referred to above include estimated quantities to be purchased that are in excess of contractual minimum quantities. Power also has commitments that provide 100% of its uranium enrichment requirements through 2011 and 35% for 2012, totaling $285 million ($191 million Power’s estimated share). Power has commitments that provide 100% of the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek that total $121 million ($88 million
Power’s estimated share). Exelon Generation has informed Power that the Peach Bottom plant has inventory and commitments to purchase sufficient quantities of uranium (concentrates and uranium
hexafluoride) to meet 100% of its total estimated requirements through 2010. Additionally, Exelon Generation has commitments covering approximately 100% of its estimated requirements for 2011 and
47% for 2012. Natural Gas 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 to PSE&G.
As of March 31, 2008, the total minimum requirements under these contracts were approximately $1 billion through 2012. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Global’s Texas generation facilities have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of March 31,
2008, the plants had fuel purchase commitments totaling $83 million to support all of their contracted energy sales. Regulatory Proceedings PSEG and PSE&G Electric Discount and Energy Competition Act (Competition Act) On April 23, 2007, PSE&G and Transition Funding were served with a copy of a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of
certain provisions of New Jersey’s Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond charge (TBC) of Transition Funding, as well
as recovery of TBC amounts previously collected. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is
presumed constitutional. On July 9, 2007, the same plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously
collected. On July 30, 2007, PSE&G filed a motion to dismiss the amended Complaint, or, in the alternative, for summary judgment. On October 10, 2007, PSE&G’s and Transition Funding’s motion to dismiss
the Amended Complaint was granted. On November 21, 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. Briefing of the appeal has been completed. On July 9, 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same charges. On September 30, 2007, PSE&G filed a motion with the
BPU to dismiss the petition. PSE&G’s motion to dismiss the BPU petition is pending. 25
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Investment Tax Credits (ITC) The Internal Revenue Service (IRS) has issued several private letter rulings (PLRs) 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 for PSE&G, was terminated upon New Jersey’s electric industry deregulation in 1999. Based on this fact, in 1999, PSE&G reversed the deferred tax and ITC
liability relating to the generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge due to such restructuring of the industry in New Jersey. In May
2006, the IRS issued a PLR to PSE&G, which concluded that none of the generation ITC could be passed to utility customers without violating its normalization rules. On March 19, 2008, the Treasury issued
final regulations that confirmed that none of the generation-related ITC could be passed to utility customers without violating the normalization rules. PSE&G has advised the BPU of these regulations and
awaits the BPU’s determination on this matter. While the issuance of the regulations is a favorable development for PSE&G, no assurance can be given as to final outcome of this issue. BPU Deferral Audit The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit—Phase II report relating to the 12-month period ended July 31, 2003
was released by the consultant to the BPU in April 2005. The draft report addresses the SBC, Market Transition Charge (MTC) and Non-Utility Generation deferred balances. The BPU released the report
on May 13, 2005. While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had
raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition
period. The amount in dispute is $114 million, which if required to be refunded to customers with interest through March 2008, would be $128 million. At PSE&G’s request, the matter was transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request on February 7,
2007. On May 25, 2007, PSE&G filed a motion for Summary Judgment requesting dismissal of the matter. On September 28, 2007, the Administrative Law Judge issued an initial decision denying PSE&G’s
motion to dismiss the matter and ordering the filing of testimony and evidentiary hearings. Hearing dates have been established for July 2008. The BPU Staff and New Jersey Division of Rate Counsel have
both asserted in briefs that the disputed amount be refunded to customers. While PSE&G believes the MTC methodology it used was fully litigated and resolved by the prior BPU Orders in its previous electric base rate case, deferral audit and deferral proceedings, PSE&G
cannot predict the outcome of this proceeding. New Jersey Clean Energy Program The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G’s electric
and gas funding requirement was $28 million and $37 million for the three months ended March 31, 2008 and 2007, respectively. The remaining liability has been recorded with an offsetting Regulatory
Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC. The liability for the funding requirement as of March 31, 2008 and December 31,
2007 was $121 million and $149 million, respectively. Energy Holdings Leveraged Lease Investments On November 16, 2006, the IRS issued its Revenue Agent’s Report for tax years 1997 through 2000, which disallowed all deductions associated with certain lease transactions that are similar to a type
that the 26
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS IRS publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest of these findings with
the Office of Appeals of the IRS. On April 9, 2008, the IRS issued its Revenue Agent’s Report for tax years 2001 through 2003, which disallowed all deductions associated with lease transactions similar to those disallowed in its 1997
through 2000 Report. As in its prior report, the IRS imposed a 20% penalty. PSEG is presently preparing a protest to this report which will be filed with the Office of Appeals of the IRS. As of March 31, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1.5 billion. PSEG has been in discussions with the Office of Appeals of the IRS concerning the deductions that have been disallowed. The outcome of such discussions cannot be predicted. There
are several tax cases involving other taxpayers with similar leverage lease
investments that are pending. To date, two of these cases have been decided
at the trial court level, both in favor of the government. An appeal of
one of these decisions was recently affirmed. The other cases are in earlier
stages. Based on these developments and its ongoing discussions with the
IRS, PSEG anticipates that, absent reaching an agreement with the IRS to
resolve this issue, a decision to proceed to litigation may occur in 2008.
It is also reasonably possible that a re-measurement of unrecognized tax
benefits related to these lease transactions will occur during the next 12
months. Such re-measurement could result in a material charge to earnings
and a corresponding material impact to the Condensed Consolidated Balance
Sheet; however, such impacts cannot be estimated at this time. If all deductions associated with these lease transactions are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s Condensed Consolidated Financial Statements and
could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law. If the IRS’ disallowance of tax benefits associated with all of these lease transactions were sustained, $904 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease
accounting through March 31, 2008 would become currently payable. In addition, as of March 31, 2008 interest of $195 million, after-tax, and penalties of $173 million may become payable, with potential
additional interest and penalties of $15 million continuing to accrue quarterly. PSEG’s management has assessed the probability of various outcomes to this matter and recorded the tax effect to be realized
in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48). In December 2007, PSEG deposited $100 million with the IRS to defray
potential interest costs associated with this disputed tax liability. In the event PSEG is successful in its defense of its position, the deposit is fully refundable with interest. Note 6. Financial Risk Management Activities The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results
of operations and financial conditions. PSEG, Power and PSE&G 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, Power and PSE&G 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 gains or losses on the assets, liabilities or anticipated
transactions exposed to such market risks. Each of PSEG, Power and PSE&G uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices. 27
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivative Instruments and Hedging Activities Energy Contracts Power Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil 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 positions to optimize the value of its portfolio and reduce earnings volatility 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. There have been significant increases in commodity prices over the last year. The
resultant changes in market values for energy and related contracts that qualify for hedge accounting have resulted in significant increases to Accumulated Other Comprehensive Loss. For additional
information, see Note 5. Commitments and Contingent Liabilities. For contracts not qualifying for hedge accounting, Power marks its derivative energy contracts to market in accordance with SFAS 133,
with changes in fair value charged to the Consolidated Statements 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. 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 and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of
March 31, 2008, the fair value of these hedges was $(811) million. These hedges resulted in a $(493) million after-tax impact on Accumulated Other Comprehensive Loss. As of December 31, 2007, the fair
value of these hedges was $(427) million. These hedges, along with realized losses on hedges of $(4) million retained in Accumulated Other Comprehensive Loss, resulted in a $(250) million after-tax impact
on Accumulated Other Comprehensive Loss. During the 12 months ending March 31, 2009, $(295) million of after-tax unrealized losses on these commodity derivatives is expected to be reclassified to
earnings with another $(143) million of after-tax unrealized losses to be reclassified to earnings for the 12 months ending March 31, 2010. Ineffectiveness associated with these hedges, as defined in SFAS
133, was a gain of $4 million at March 31, 2008. The expiration date of the longest dated cash flow hedge is in 2011. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for cash flow hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation
requirements and for electricity purchases for contractual sales obligations and a portion is used in Power’s Nuclear Decommissioning Trust Funds (NDT). Therefore, the changes in fair market value of
these derivative contracts are recorded in Energy Costs, Operating Revenues, Other Income or Other Deductions, as appropriate, on the Consolidated Statements of Operations. The net fair value of these
instruments was $(4) million and $(10) million as of March 31, 2008 and December 31, 2007, respectively. 28
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Holdings Other Derivatives PSEG Texas enters into electricity forward and capacity sales contracts to sell a portion of its 2,000 MW capacity with the balance sold into the daily spot market. PSEG Texas also enters into gas
purchase contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and
thereby provide financial stability to PSEG Texas, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and
normal sales exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value through the Consolidated Statements of Operations. The net fair
value of the open positions was $32 million and $63 million as of March 31, 2008 and December 31, 2007, respectively. In March 2008, in connection with the sale of SAESA, Energy Holdings purchased two options to sell Chilean Pesos and receive U.S. Dollars at strike prices of 475 and 480 Chilean Pesos to the U.S.
Dollar for a combined notional amount of $100 million. These are four month options which will protect the expected sales proceeds of SAESA from a devaluation of the Chilean Peso prior to the
anticipated sale. The fair value of the option contracts was $1 million at March 31, 2008. Subsequent to March 31, 2008, Energy Holdings entered into four additional options at strike prices between 470 and
480 Chilean Pesos to the U.S. Dollar for an additional notional amount of $200 million. Interest Rates PSEG, Power and PSE&G PSEG, Power and PSE&G 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 April 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 March 31, 2008 and December 31, 2007,
the fair value of the hedge was less than $1 million and $(3) million, respectively. Cash Flow Hedges PSEG and PSE&G PSEG and PSE&G 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. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in Accumulated Other
Comprehensive Loss. As of March 31, 2008, the fair value of these cash flow hedges was $(5) million and $(13) million at PSE&G and Energy Holdings, respectively. As of December 31, 2007, the fair value of
these cash flow hedges was $(4) million and $(7) million at PSE&G and Energy Holdings, respectively. The $(5) million and $(4) million at PSE&G as of March 31, 2008 and December 31, 2007, is not included
in Accumulated Other Comprehensive Loss, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the next 12 months, $(6) million of unrealized losses (net
of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified at PSEG. As of March 31, 2008, there was no hedge ineffectiveness associated with these
hedges. 29
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7. Comprehensive Income, Net of Tax
Power (A)
PSE&G
Other (B)
Consolidated
(Millions) For the Quarter Ended March 31, 2008: Net Income
$
275
$
137
$
36
$
448 Other Comprehensive (Loss) Income
(272
)
—
52
(220
) Comprehensive Income
$
3
$
137
$
88
$
228 For the Quarter Ended March 31, 2007: Net Income (Loss)
$
213
$
132
$
(16
)
$
329 Other Comprehensive Loss
(155
)
—
(9
)
(164
) Comprehensive Income (Loss)
$
58
$
132
$
(25
)
$
165
(A)
Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2008 and 2007, as detailed below. (B) Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. Changes for 2008 and 2007 primarily relate to foreign currency translation
adjustments at Global, as detailed below. Accumulated Other Comprehensive Income (Loss)
Balance as of
Power
PSE&G
Other
Balance as of
(Millions) For the Quarter Ended March 31, 2008: Derivative
Contracts
$
(259
)
$
(242
)
$
—
$
(4
)
$
(505
) Pension
and OPEB Plans
(167
)
—
—
—
(167
) Currency Translation Adjustment
107
—
—
56
163 NDT Funds
97
(30
)
—
—
67 Other
6
—
—
—
6
$
(216
)
$
(272
)
$
—
$
52
$
(436
)
Balance as of
Power
PSE&G
Other
Balance as of
(Millions) For the Quarter Ended March 31, 2007: Derivative
Contracts
$
(114
)
$
(158
)
$
—
$
—
$
(272
) Pension
and OPEB Plans
(214
)
2
—
—
(212
) Currency Translation Adjustment
110
—
—
(9
)
101 NDT Funds
108
1
—
—
109 Other
2
—
—
—
2
$
(108
)
$
(155
)
$
—
$
(9
)
$
(272
) Note 8. Changes in Capitalization Power In March 2008, Power paid a cash dividend to PSEG of $125 million. 30
(UNAUDITED)
Total
December 31,
2007
March 31,
2008
December 31,
2006
March 31,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSE&G In May 2008, PSE&G redeemed its outstanding $157 million of 6.375% First and Refunding Mortgage Bonds Remarketable Series YY Due 2023 Mandatorily Tendered 2008. PSE&G paid approximately
$32 million in cash to settle the remarketing option held by the remarketing dealer. In April 2008, PSE&G issued $400 million of 5.30% Medium-Term Notes, Series E due May 1, 2018. In March 2008, PSE&G issued $300 million of Floating Rate (3-month Libor + 0.875%) Bonds due 2010. As of December 31, 2007, PSE&G had $494 million of variable rate pollution control bonds outstanding which serviced and secured a like amount of insured tax-exempt variable rate bonds of the
Pollution Control Authority of Salem County (Salem County Authority). Through April 2008, PSE&G purchased $494 million of the Salem County Authority bonds which were either being held by the
broker/dealer or tendered by bondholders upon conversion of the bonds to a weekly interest rate mode. These purchases were recorded as a reduction to PSE&G’s Long-Term Debt included on its
Condensed Consolidated Balance Sheets. PSE&G intends to hold these bonds until they can be remarketed or refinanced. For the quarter ended March 31, 2008, Transition Funding repaid $40 million of its transition bonds. Energy Holdings In March 2008, Energy Holdings repurchased $5 million of the $530 million then outstanding 8.50% Senior Notes due 2011. In February 2008, Energy Holdings repaid at maturity $207 million of its 8.625% Senior Notes. In January 2008, Energy Holdings redeemed its outstanding $400 million of 10% Senior Notes due 2009. During the first three months of 2008, Energy Holdings’ subsidiaries repaid $13 million of non-recourse debt, primarily related to Global’s Texas generation facilities. Note 9. Other Income and Deductions
Power
PSE&G
Other (A)
Consolidated
(Millions) Other Income: For the Quarter Ended March 31, 2008: Interest and Dividend Income
$
2
$
2
$
9
$
13 NDT Fund Realized Gains
75
—
—
75 NDT Interest and Dividend Income
8
—
—
8 Other
1
3
(7
)
(3
) Total Other Income
$
86
$
5
$
2
$
93 For the Quarter Ended March 31, 2007: Interest and Dividend Income
$
5
$
3
$
3
$
11 NDT Fund Realized Gains
34
—
—
34 NDT Interest and Dividend Income
12
—
—
12 Change in Derivative Fair Value
—
—
1
1 Arbitration Award (Konya-Ilgin)
—
—
9
9 Other
—
2
3
5 Total Other Income
$
51
$
5
$
16
$
72 31
(UNAUDITED)
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Power
PSE&G
Other (A)
Consolidated
(Millions) Other Deductions: For the Quarter Ended March 31, 2008: Donations
$
—
$
1
$
—
$
1 NDT Fund Realized Losses and Expenses
53
—
—
53 Loss on Early Extinguishment of Debt
—
—
2
2 Other-Than-Temporary Impairment of Investments
38
—
—
38 Total Other Deductions
$
91
$
1
$
2
$
94 For the Quarter Ended March 31, 2007: Donations
$
—
$
1
$
5
$
6 NDT Fund Realized Losses and Expenses
17
—
—
17 Foreign Currency Losses
—
—
1
1 Loss on Disposition of Assets
1
—
—
1 Other-Than-Temporary Impairment of Investments
10
—
—
10 Other
1
—
—
1 Total Other Deductions
$
29
$
1
$
6
$
36
(A)
Other primarily consists of activity at PSEG (parent company), Energy Holdings, Services and intercompany eliminations.
Note 10. Pension and Other Postretirement Benefits (OPEB) PSEG PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s 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 and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal
subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003.
Pension Benefits
OPEB
Quarters Ended
Quarters Ended
2008
2007
2008
2007
(Millions) Components of Net Periodic Benefit Costs: Service Cost
$
19
$
21
$
4
$
4 Interest Cost
57
54
18
18 Expected Return on Plan Assets
(72
)
(72
)
(4
)
(4
) Amortization of Net Transition Obligation
—
—
7
7 Prior Service Cost
2
3
3
3 Loss
3
5
—
2 Net Periodic Benefit Cost
9
11
28
30 Effect of Regulatory Asset
—
—
5
5 Total Benefit Costs
$
9
$
11
$
33
$
35 32
(UNAUDITED)
Total
March 31,
March 31,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG, Power and PSE&G Pension costs and OPEB costs for PSEG, Power and PSE&G are detailed as follows:
Pension Benefits
OPEB
Quarters Ended
Quarters Ended
2008
2007
2008
2007
(Millions) Power
$
3
$
3
$
3
$
4 PSE&G
4
5
29
30 Other
2
3
1
1 Total PSEG Consolidated Benefit Costs
$
9
$
11
$
33
$
35 An analysis of the tax provision expense is as follows:
Power
PSE&G
Other (A)
Consolidated
(Millions) For the Quarter Ended March 31, 2008: Income Before Income Taxes
$
462
$
202
$
4
$
668 Tax Computed at the Statutory Rate
$
162
$
70
$
2
$
234 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit
29
15
(2
)
42 Uncertain Tax Positions
1
(20
)
(17
)
(36
) Other
(5
)
—
(1
)
(6
) Total Income Tax Expense (Benefit)
$
187
$
65
$
(18
)
$
234 Effective Income Tax Rate
40.5
%
32.2
%
N/A
35.0
% For the Quarter Ended March 31, 2007: Income (Loss) Before Income Taxes
$
374
$
231
$
(24
)
$
581 Tax Computed at the Statutory Rate
$
131
$
81
$
(8
)
$
204 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit
23
16
(3
)
36 Foreign Operations
—
—
12
12 Uncertain Tax Positions
1
—
5
6 Other
—
2
—
2 Total Income Tax Expense
$
155
$
99
$
6
$
260 Effective Income Tax Rate
41.4
%
42.9
%
N/A
44.8
%
(A)
PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs and amounts applicable to Energy
Holdings (as parent company) that reflect interim period distortion due to asset sales and other one-time adjustments.
Each of PSEG, Power and PSE&G provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing
assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through
item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting regulatory asset was established. As of March 31, 2008, PSE&G had a regulatory asset of $421
million representing the tax costs expected to be recovered through rates based upon established regulatory practices, which permit recovery of current taxes payable. This amount was determined using the
enacted federal income tax rate of 35% and state income tax rate of 9%. 33
(UNAUDITED)
March 31,
March 31,
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG and its subsidiaries adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain
tax positions that it has taken or expects to take on a tax return. On December 17, 2007, PSEG made a tax deposit with the IRS in the amount of $100 million to defray interest costs associated with disputed tax assessments associated with certain lease investments
(see Note 5. Commitments and Contingent Liabilities). The $100 million deposit is fully refundable and is recorded as a reduction to the Unrecognized Tax Benefit liability on PSEG’s Consolidated Balance
Sheet. Based on decisions in two court cases involving lease investments by other taxpayers as described in Note 5. Commitments and Contingent Liabilities, it is reasonably possible that a re-measurement of
unrecognized tax benefits will occur during the next 12 months. Such re-measurement could result in a material charge to earnings and a corresponding material impact to PSEG’s Consolidated Balance
Sheet; however, such impacts cannot be estimated at this time. It
is reasonably possible that approximately $(67) million of unrecognized
tax benefits at PSEG associated with a change in accounting method for federal
income tax purposes, including $(38) million at PSE&G, will be settled within
12 months due to agreement with the IRS’ position with respect to these
items. The change in method related to the adoption of the Simplified Service
cost method of capitalizing indirect costs. Note 12. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below:
Power
PSE&G
Resources
Global
Other (A)
Consolidated
(Millions) For the Quarter Ended March 31, 2008: Total Operating Revenues
$
2,375
$
2,618
$
31
$
108
$
(1,329
)
$
3,803 Income (Loss) From Continuing Operations
275
137
14
14
(6
)
434 Income from Discontinued Operations, net of tax
—
—
—
14
—
14 Net Income (Loss)
275
137
14
28
(6
)
448 Preferred Securities Dividends
—
(1
)
—
—
1
— Segment Earnings (Loss)
275
136
14
28
(5
)
448 Gross Additions to Long-Lived Assets
174
145
—
2
2
323 As of March 31, 2008: Total Assets
$
8,004
$
14,589
$
2,959
$
2,521
$
(105
)
$
27,968 Investments in Equity Method Subsidiaries
$
17
$
—
$
—
$
214
$
—
$
231 For the Quarter Ended March 31, 2007: Total Operating Revenues
$
2,149
$
2,486
$
44
$
102
$
(1,273
)
$
3,508 Income (Loss) From Continuing Operations
219
132
17
(27
)
(20
)
321 (Loss) Income from Discontinued Operations, net of tax
(6
)
—
—
14
—
8 Net Income (Loss)
213
132
17
(13
)
(20
)
329 Preferred Securities Dividends
—
(1
)
—
—
1
— Segment Earnings (Loss)
213
131
17
(13
)
(19
)
329 Gross Additions to Long-Lived Assets
126
130
—
16
3
275 As of December 31, 2007: Total Assets
$
8,336
$
14,637
$
2,992
$
2,334
$
—
$
28,299 Investments in Equity Method Subsidiaries
$
14
$
—
$
—
$
208
$
—
$
222 34
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(A)
PSEG’s other activities include amounts applicable to PSEG (as parent corporation) and Energy Holdings (as parent company) and EGDC 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 between Power and PSE&G, see Note 14. Related-Party
Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation.
Note 13. Fair Value Measurements PSEG, Power and PSE&G Effective
January 1, 2008, PSEG, Power and PSE&G adopted SFAS 157 except for non-financial
assets and liabilities as described in FSP FAS 157-2 and discussed in Note
2. Recent Accounting Standards. SFAS 157 defines fair value, establishes
a framework for measuring fair value and expands disclosures about fair value
measurements. Fair value is the price that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. SFAS 157 emphasizes that fair value
is a market-based measurement, not an entity-specific measurement, and establishes
a fair value hierarchy that distinguishes between assumptions based on market
data obtained from independent sources and those based on an entity’s
own assumptions. The hierarchy prioritizes the inputs to fair value measurement
into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity
securities, exchange traded derivatives and certain U.S. government treasury securities. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other
observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options
and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, are based on the best information available and might include an entity’s own data. In some valuations, the inputs used may fall
into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These
consist mainly of various FTRs, other longer term capacity and transportation contracts and certain commingled securities. In addition to establishing a measurement framework, SFAS 157 nullifies the guidance of EITF 02-3, which did not allow an entity to recognize an unrealized gain or loss at the inception of a derivative
instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions
or based on a valuation technique incorporating observable market data. Under EITF 02-3, PSEG Texas had a deferred inception loss of $34 million, pre-tax, at December 31, 2007 related to a five-year
capacity contract at its generation facilities, which was being amortized at $11 million per year through 2010. In accordance with the provisions of SFAS 157, PSEG Texas recorded a cumulative effect
adjustment of $22 million after-tax to January 1, 2008 Retained Earnings associated with the implementation of SFAS 157. 35
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table presents information about PSEG’s, Power’s, and PSE&G’s respective assets and liabilities measured at fair value on a recurring basis at March 31, 2008, including the fair value
measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.
Recurring Fair Value Measurements as of March 31, 2008
Description
Total at
Cash
Quoted Market Prices
Significant Other
Significant
(Millions) PSEG Assets: Derivative Contracts: Energy Trading Contracts (A)
$
173
$
—
$
—
$
160
$
13 Commodity Hedges (A)
$
1
$
—
$
—
$
—
$
1 Other Commodity Contracts (B)
$
69
$
—
$
—
$
6
$
63 Foreign Currency Contract (C)
$
1
$
—
$
—
$
1
$
— NDT Funds (D)
$
1,281
$
—
$
684
$
570
$
27 Rabbi Trusts (D)
$
138
$
—
$
14
$
110
$
14 Other Long-Term Investments (E)
$
3
$
—
$
4
$
(1
)
$
— Liabilities: Derivative Contracts: Energy Trading Contracts (A)
$
25
$
(2
)
$
—
$
23
$
4 Commodity Hedges (A)
$
605
$
(207
)
$
—
$
812
$
— Other Commodity Contracts (B)
$
108
$
—
$
—
$
35
$
73 Interest Rate Swaps (C)
$
17
$
—
$
—
$
17
$
— Power Assets: Derivative Contracts: Energy Trading Contracts (A)
$
173
$
—
$
—
$
160
$
13 Commodity Hedges (A)
$
1
$
—
$
—
$
—
$
1 NDT Funds (D)
$
1,281
$
—
$
684
$
570
$
27 Rabbi Trusts (D)
$
28
$
—
$
3
$
22
$
3 Liabilities: Derivative Contracts: Energy Trading Contracts (A)
$
25
$
(2
)
$
—
$
23
$
4 Commodity Hedges (A)
$
605
$
(207
)
$
—
$
812
$
— PSE&G Assets: Derivative Contracts: Other Commodity Contracts (B)
$
2
$
—
$
—
$
—
$
2 Rabbi Trusts (D)
$
48
$
—
$
5
$
38
$
5 Liabilities: Other Commodity Contracts (B)
$
73
$
—
$
—
$
—
$
73 Interest Rate Swap (C)
$
5
$
—
$
—
$
5
$
—
(A)
Whenever possible, fair values for energy trading and commodity hedge contracts are obtained from quoted market sources in active markets. When this pricing is unavailable, contracts are valued
using broker or dealer quotes or auction prices. For contracts where no observable market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves
and forward prices, as applicable, to interpolate certain prices. (B) Other commodity contracts primarily include more complex agreements for which limited pricing information is available. These contracts are valued using modeling techniques and assumptions
reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. 36
(UNAUDITED)
March 31,
2008
Collateral
Netting (F)
for Identical Assets
(Level 1)
Observable Inputs
(Level 2)
Unobservable Inputs
(Level 3)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (C) Interest rate swaps and foreign currency contracts are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a
market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (D) The NDT Funds and the Rabbi Trusts maintain investments in various equity and fixed income securities classified as “available for sale” under SFAS No. 115, “Accounting for Certain Investments in
Debt and Equity Securities.” These securities are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. All fair
value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask
price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued
based upon internal matrices using observable market prices or market parameters such as time-to- maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash
equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The NDT Funds exclude net receivables/payables of
$72 million related to pending security sales/purchases. (E) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices. (F) Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under FIN 39-1. For further discussion, see Note 2. Recent Accounting Standards. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis Description
Balance at
Total Gains or (Losses)
Purchases and
Balance at
Included in
Included in
(Millions) PSEG Derivative Assets
$
44
$
23
$
(1
)
$
11
$
77 PSEG Derivative Liabilities
$
(49
)
$
(7
)
$
(21
)
$
—
$
(77
) PSEG NDT Funds
$
27
$
(1
)
$
—
$
1
$
27 PSEG Rabbi Trust Funds
$
16
$
—
$
—
$
(2
)
$
14 Power Derivative Assets
$
13
$
(10
)
$
—
$
11
$
14 Power Derivative Liabilities
$
3
$
(7
)
$
—
$
—
$
(4
) Power NDT Funds
$
27
$
(1
)
$
—
$
1
$
27 Power Rabbi Trust Funds
$
3
$
—
$
—
$
—
$
3 PSE&G Derivative Assets
$
3
$
—
$
(1
)
—
$
2 PSE&G Derivative Liabilities
$
(52
)
$
—
$
(21
)
$
—
$
(73
) PSE&G Rabbi Trust Funds
$
6
$
—
$
—
$
(1
)
$
5
(A)
PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $23 million is included in Operating Revenues and ($7) million is included in Other
Comprehensive Income. Of the $23 million in Operating Revenues, $33 million (unrealized) is at PSEG Texas and $(10) million (($5) unrealized) is at Power. The ($7) million included in Other
Comprehensive Income is at Power. (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a regulatory asset and are expected to be
recovered from PSE&G’s customers. 37
(UNAUDITED)
January 1,
2008
Realized/Unrealized
(Sales)
March 31,
2008
Income (A)
Regulatory Assets
/Liabilities (B)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of March 31, 2008, PSEG carried approximately $1 billion of net assets that are measured at fair value on a recurring basis, of which approximately $40 million are measured using unobservable
inputs and classified as level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers in or out of Level 3 during the
quarter ended March 31, 2008. The overall impact of gains and losses associated with Level 3 assets and liabilities was immaterial to PSEG’s Condensed Consolidated Financial Statements for the quarter. Note 14. Related-Party Transactions The majority of the following discussion relates to intercompany transactions. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated
during the consolidation process in accordance with GAAP when preparing PSEG’s Condensed Consolidated Financial Statements. BGS and BGSS Contracts Power and PSE&G PSE&G has 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 through March 2012
and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
Power’s Billings for
2008
2007
(Millions) BGS
$
272
$
218 BGSS
$
1,050
$
1,049 As of March 31, 2008 and December 31, 2007, Power had net receivables from PSE&G of $398 million and $451 million, respectively, primarily related to the BGS and BGSS contracts. In addition, as of March 31, 2008, PSE&G had a receivable from Power of $150 million and as of December 31, 2007, PSE&G had a payable to Power of $55 million related to gas supply hedges Power
entered into for BGSS. Services Power and PSE&G Services provides and bills administrative services to Power and PSE&G. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as
pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below:
Services’ Billings for
the
Payable to Services as of
March 31,
December 31,
2008
2007
(Millions) Power
$
41
$
33
$
21
$
18 PSE&G
$
65
$
49
$
39
$
32 38
(UNAUDITED)
the Quarters Ended
March 31,
Quarters Ended
March 31,
2008
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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,
Power and PSE&G believe that the costs of services provided by Services approximate market value for such services. Tax Sharing Agreements PSEG, Power and PSE&G Power and PSE&G had payables to PSEG related to taxes as follows:
Payable to PSEG as of
March 31,
December 31,
(Millions) Power
$
189
$
43 PSE&G
$
67
$
5 In addition to these tax payable amounts, as of March 31, 2008 and December 31, 2007, Power had a $9 million and an $8 million current receivable, respectively, from PSEG related to unrecognized
tax positions. As of March 31, 2008, PSE&G had a $53 million current receivable from PSEG and as of December 31, 2007 PSE&G had a $3 million current tax payable to PSEG for unrecognized tax positions.
PSEG and its subsidiaries adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax
positions that it has taken or expects to take on a tax return. Affiliate Loans and Advances PSEG and Power As of March 31, 2008, Power had a demand note receivable of $407 million due from PSEG. As of December 31, 2007, Power had a demand note payable to PSEG of $238 million for short-term
funding needs. PSE&G and Services As of each of March 31, 2008 and December 31, 2007, PSE&G had advanced working capital to Services of $33 million. This amount is included in Other Noncurrent Assets on PSE&G’s Condensed
Consolidated Balance Sheets. Power and Services As of each of March 31, 2008 and December 31, 2007, Power had advanced working capital to Services of $17 million. This amount is included in Other Noncurrent Assets on Power’s Condensed
Consolidated Balance Sheets. Other PSEG and Power As of December 31, 2007, Power had net receivables from PSEG of $5 million related to amounts that PSEG had collected on Power’s behalf. PSEG and PSE&G As of March 31, 2008 and December 31, 2007, PSE&G had net receivables from PSEG of $5 million and $11 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf. 39
(UNAUDITED)
2008
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power and Global Effective January 1, 2008, Fossil assumed control of the management of Global’s operations located in Texas. Power’s receivable for management fees from Global was immaterial as of March 31, 2008. Power Each series of Power’s Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed
financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.
Power
Guarantor
Other
Consolidating
Consolidated
(Millions) For the Quarter Ended March 31, 2008: Operating Revenues
$
—
$
2,627
$
27
$
(279
)
$
2,375 Operating Expenses
2
2,117
27
(280
)
1,866 Operating Income
(2
)
510
—
1
509 Equity Earnings (Losses) of Subsidiaries
281
(10
)
—
(271
)
— Other Income
39
101
—
(54
)
86 Other Deductions
—
(91
)
—
—
(91
) Interest Expense
(53
)
(28
)
(15
)
54
(42
) Income Taxes
10
(201
)
5
(1
)
(187
) Net Income (Loss)
$
275
$
281
$
(10
)
$
(271
)
$
275 For the Quarter Ended March 31, 2008: Net Cash (Used In) Provided By Operating Activities
$
(848
)
$
856
$
(26
)
$
956
$
938 Net Cash Provided By (Used In) Investing Activities
$
973
$
(806
)
$
(2
)
$
(742
)
$
(577
) Net Cash (Used In) Provided By Financing Activities
$
(125
)
$
(52
)
$
28
$
(214
)
$
(363
) For the Quarter Ended March 31, 2007: Operating Revenues
$
—
$
2,401
$
27
$
(279
)
$
2,149 Operating Expenses
—
2,014
24
(278
)
1,760 Operating Income
—
387
3
(1
)
389 Equity Earnings (Losses) of Subsidiaries
217
(12
)
—
(205
)
— Other Income
49
66
—
(64
)
51 Other Deductions
—
(29
)
—
—
(29
) Interest Expense
(54
)
(35
)
(11
)
63
(37
) Income Taxes
1
(160
)
3
1
(155
) Loss from Discontinued Operations, net of tax
—
—
(6
)
—
(6
) Net Income (Loss)
$
213
$
217
$
(11
)
$
(206
)
$
213 For the Quarter Ended March 31, 2007: Net Cash Provided By (Used In) Operating Activities
$
61
$
801
$
(17
)
$
(21
)
$
824 Net Cash Provided By (Used In) Investing Activities
$
64
$
114
$
(14
)
$
(815
)
$
(651
) Net Cash (Used In) Provided By Financing Activities
$
(125
)
$
(921
)
$
31
$
836
$
(179
) 40
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Power
Guarantor
Other
Consolidating
Consolidated
(Millions) As of March 31, 2008: Current Assets
$
2,630
$
3,974
$
366
$
(5,160
)
$
1,810 Property, Plant and Equipment, net
149
3,760
927
1
4,837 Investment in Subsidiaries
3,397
159
—
(3,556
)
— Noncurrent Assets
138
1,604
30
(415
)
1,357 Total Assets
$
6,314
$
9,497
$
1,323
$
(9,130
)
$
8,004 Current Liabilities
$
134
$
5,166
$
1,064
$
(5,160
)
$
1,204 Noncurrent Liabilities
239
935
100
(415
)
859 Long-Term Debt
2,902
—
—
—
2,902 Member’s Equity
3,039
3,396
159
(3,555
)
3,039 Total Liabilities and Member’s Equity
$
6,314
$
9,497
$
1,323
$
(9,130
)
$
8,004 As of December 31, 2007: Current Assets
$
2,553
$
3,541
$
360
$
(4,305
)
$
2,149 Property, Plant and Equipment, net
149
3,669
934
(1
)
4,751 Investment in Subsidiaries
3,538
168
—
(3,706
)
— Noncurrent Assets
156
1,505
30
(255
)
1,436 Total Assets
$
6,396
$
8,883
$
1,324
$
(8,267
)
$
8,336 Current Liabilities
$
99
$
4,487
$
1,057
$
(4,305
)
$
1,338 Noncurrent Liabilities
234
858
98
(255
)
935 Long-Term Debt
2,902
—
—
—
2,902 Member’s Equity
3,161
3,538
169
(3,707
)
3,161 Total Liabilities and Member’s Equity
$
6,396
$
8,883
$
1,324
$
(8,267
)
$
8,336 41
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) PSEG, Power and PSE&G This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information
contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to
any other company. The following discussion relates to the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that
have occurred during the first quarter of 2008 and the future outlook for Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings), as well as the key factors that will drive the future
performance of these businesses. This discussion includes significant changes in or additions to information reported in the 2007 Annual Report on Form 10-K and refers to the Condensed Consolidated
Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2007
Annual Report on Form 10-K (Form 10-K). PSEG’s business consists of four reportable segments, which are Power, PSE&G and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C.
(Resources). Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market in the Northeast and Mid Atlantic U.S. Through its subsidiaries, Power
seeks to produce low-cost energy through efficient operations of its nuclear, coal and gas-fired generation facilities. Power seeks to balance this generation production with its fuel requirements and supply
obligations through energy portfolio management. In addition to the electric generation business, Power’s revenues include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a
series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the availability of Power’s diverse fleet of generation
units to produce these products, as well as the prices of commodities such as electricity, gas, nuclear fuel, coal and emissions, can have a material effect on Power’s profitability. In recent years, the prices at
which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM Interconnection L.L.C. (PJM) West, have escalated
considerably over historical prices. Broad market price increases such as these have had a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced over 50%
and 25% of Power’s production, respectively. With the vast majority of its power sourced from these lower-cost units, the rise in electric prices has yielded higher margins for Power. Over a longer-term
horizon, if these higher prices are sustained at levels reflective of what the current forward markets indicate, Power would have an attractive environment in which to contract for the sale of its anticipated
output, allowing for potentially sustained higher profitability than recognized in prior years. However, its prices also increase the cost of replacement power, thereby placing risk on Power to operate the
generating units to produce these products. Further, changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other assumptions could
materially affect its ability to meet earnings targets and/or liquidity requirements. Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output, capacity and fuel needs. Power believes this contracting strategy
increases stability of earnings and cash flow. Power seeks to sell a portion of its anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of two to four years. Power also contracts for the
future delivery of nuclear fuel and coal to support its contracted sales. Power’s estimated fuel needs are subject to change based upon the level of its operations as well as upon market demands for and the
price of coal, both of which have increased recently. Power has recently negotiated through some disruptions in the delivery of certain contracted coal. Power believes it can continue to manage its fuel
sourcing needs in this dynamic 42
market but cannot predict the impact that rising prices and potential increasing demand may have on its operations in the future. By contrast, Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched
only when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear
units or coal units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments. In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. For example, in a rising price environment, this hedging
strategy will tend to create margins which are below those implied by the current market. Alternatively, in a falling price environment, this hedging strategy will tend to create margins in excess of those
implied by the then current market. In the electricity markets where Power participates, the pricing of electricity can vary by location. For example, prices may be higher in congested areas due to transmission constraints during peak
demand periods, reflecting the bid prices of the higher-cost units that are dispatched to meet demand. This typically occurs in the eastern portion of PJM, where many of Power’s plants are located. At
various times, depending upon its production and its obligations, these price differentials can serve to increase or decrease Power’s profitability. 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. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those
agencies. Global Domestically, Global has investments in power producers that own and operate electric generation in Texas, California and Hawaii, with smaller investments in New Hampshire and Pennsylvania.
Global has reduced its international risk by monetizing the majority of its international investments. Resources Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. PSEG, Power and PSE&G Overview Financial Results PSEG had Income from Continuing Operations of $434 million, or $0.85 per share for the quarter ended March 31, 2008, as compared to $321 million, or $0.63 per share for the same quarter in 2007.
PSEG’s Net Income for the quarter ended March 31, 2008 was $448 million, or $0.88 per share, as compared to Net Income of $329 million, or $0.65 per share for the first quarter of 2007. The quarter-over-
quarter changes in PSEG’s Income from Continuing Operations are primarily due to improved earnings at Power and Energy Holdings. The primary reasons for the increase at Power were higher prices and sales volumes in PJM and higher prices realized from recontracted Basic Generation Service (BGS) contracts. The increase was
somewhat offset by higher generation costs, largely due to increased prices for natural gas and coal purchases and by the recognition in 2008 of $17 million of additional other-than-temporary impairments
on certain securities in the Nuclear Decommissioning Trust Funds. The increase at Energy Holdings was primarily due to increased earnings at Global from its Texas generation facilities, mostly due to mark-to-market (MTM) activity, combined with increased earnings
at 43
Bioenergie S.p.A (Bioenergie) which did not operate its San Marco facility during the first quarter of 2007. The increases were partially offset by the absence of income from Chilquinta Energia S.A.
(Chilquinta) and Luz del Sur S.A.A. (LDS), which were sold in December 2007, and the absence of a gain on the sale of the Tracy project and an arbitration award received during the first quarter of 2007. Also contributing to the increase were lower taxes at PSE&G and Energy Holdings related to an IRS approved refund claim at PSEG for earlier tax years. During the quarter ended March 31, 2008, commodity prices increased significantly, resulting in a material increase in Power’s Accumulated Other Comprehensive Loss related to the derivative
transactions entered into to hedge forecasted energy sales from its generation stations, related load obligations and the price of fuel to meet its fuel purchase requirements. Power’s required margin postings
for sales contracts entered into in the normal course of business also significantly increased due to the increased commodity prices. Should commodity prices rise further, additional margin calls may be
necessary relative to existing power sales contracts. Business Developments In January 2008, PSEG’s Board of Directors approved a two-for-one stock split of PSEG’s outstanding shares of common stock. Also in January 2008 and April 2008, PSEG’s Board of Directors
approved a $0.3225 per share dividend for each of the first two quarters of 2008, reflecting an indicated annual dividend rate of $1.29 per share. In February 2008, the BPU approved the results of New Jersey’s annual BGS-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price auctions and PSE&G successfully secured contracts to
provide the anticipated electricity requirements for its customers. As a result of the February 2008 auction, new BGS-FP rates will increase the average residential customer’s bill by approximately 12%
effective June 2008. In April 2008, the U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the Federal Water Pollution Control Act allows
the U.S. Environmental Protection Agency ( EPA) to compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake
structures. This matter could have a material impact on Power’s ability to renew Clean Water Act permits at a number of its larger plants without making significant equipment upgrades involving material
expenditures. See Note 5. Commitments and Contingent Liabilities for additional information. PSEG and its subsidiaries also received updates on various regulatory proceedings during 2008, including:
•
FERC approval of the classification of new 69 kV facilities as transmission rather than distribution which PSE&G expects to result in improvements in reliability and more expeditious rate treatment
for these facilities. • U.S. Department of Treasury issuance of final regulations regarding Investment Tax Credit (ITC) normalization. See Note 5. Commitments and Contingent Liabilities for additional information. • BPU approval of a settlement agreement allowing PSE&G to invest approximately $105 million in a solar energy pilot program. A Written Order was received on April 16, 2008. • FERC approval of incentive rate treatment for PSE&G’s Susquehanna-Roseland transmission line project. • issuance of a draft of the New Jersey Energy Master Plan (EMP) with a final report to be available later in 2008. For additional information relating to these regulatory matters, see Item 5. Other Information. Future Outlook PSEG’s future success will depend on the ability of Power, PSE&G and Energy Holdings to achieve their respective objectives and earnings expectations, as well as the successful completion of their
respective growth initiatives, discussed below. A key factor for success is Power’s ability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Power’s
ability to achieve its objectives will also depend on the continuation of reasonable capacity markets. In addition, Power 44
must be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements, including legislation,
regulation and voluntary restrictions to address:
•
the control of carbon dioxide emissions to reduce the effects of global climate change and greenhouse gas; • other emissions such as nitrogen oxide, sulfur dioxide and mercury; and • the potential need for significant upgrades to existing intake structures and cooling systems at its larger once-through cooled plants, including Salem, Hudson, Mercer, Sewaren, New Haven and
Bridgeport. Power has two large environmental back-end technology projects underway at its Mercer and Hudson coal plants scheduled to be completed by the end of 2010. Power is focused on completing these
projects on schedule and within the established budgets, but faces many risks typically involved in managing large construction projects. In addition, with an increase in competition and market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While
recent higher forward prices may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages,
and could also further increase liquidity requirements as a result of contract obligations. For additional information on liquidity requirements, see Liquidity and Capital Resources. Power could also be impacted by a number of events, including regulatory or legislative actions favoring non-competitive markets, energy efficiency initiatives and regulatory policies favoring the
construction of rate-based transmission that may result in increased imports of generation, which may be subject to less stringent environmental regulation, into areas served by Power’s generation assets.
Further, some of the market-based mechanisms in which Power participates, including BGS auctions and the Reliability Pricing Model (RPM) capacity payments, are at times the subject of review or
discussion by some of the participants in the New Jersey and federal regulatory and political arenas, including the FERC and the BPU, and the PJM market monitor. Power can provide no assurance that
these mechanisms will continue to exist in their current form. For additional information, see Item 5. Other Information—Regulatory Issues. PSE&G’s results primarily depend on the treatment of the various rate and other issues by the BPU and the FERC, as well as other state and federal regulatory agencies. This includes its ability to attain
a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels, continue recovery of the regulatory assets it has deferred and attain an adequate return on the
investments it plans to make in its electric and gas transmission and distribution system and the level of recovery of distribution revenues in light of customer demand and conservation efforts. Under the
terms of the settlement of PSE&G’s most recent electric and gas base rate cases, it is required to file jointly for any gas and electric petition for future base rate increases and no base rate changes may
become effective before November 15, 2009. Energy Holdings’ earnings are primarily comprised of the results of operations at Global and Resources. As a merchant generation business with a load-following asset profile, Global’s largest domestic
investment is in two generating facilities in Texas, and, as such, its success will be driven by the efficient operation of those plants and by changes in market conditions, particularly projected market heat
rates and weather. Resources maintains a portfolio of investments which is designed to provide a fixed rate of return. However, its future performance is subject to tax risks, such as the impacts of changes
to uncertain tax positions as determined by changes in substantive tax law and tax audit results, including resolution of significant tax audit claims associated with its leveraged lease transactions. See Note 5.
Commitments and Contingent Liabilities for further discussion. PSEG expects that continued strong cash from operations will be sufficient to fund dividends and support expected capital expenditures as projected in its Form 10-K. As noted, this strong cash from
operations is expected to come primarily from Power, with modest contributions from the operations of PSE&G and Energy Holdings. When combined with funds from planned asset sales and potential
financing activities, PSEG expects that it could have up to $3 billion of cash available through the end of 2011 to pursue disciplined growth of its businesses through acquisition, construction or other
development projects or to repurchase common stock. 45
There are several factors that could impact the amount of cash that at any point in time may actually be available for these purposes, including:
•
the continued liquidity and strength of energy and capacity markets; • the net proceeds actually realized from sales of international assets at Energy Holdings; • the cash required to resolve the significant income tax claims discussed in Note 5. Commitments and Contingent Liabilities, the timing of which cannot be predicted and the amount of which
may exceed our previous expectations; and • the ability to successfully deploy discretionary capital for growth. In general, PSEG believes it has growth opportunities in the following three key areas:
•
responding to climate change and continuing to improve environmental performance through investments in energy efficiency, renewables and clean central station power; • upgrading critical energy infrastructure; and • providing new energy supplies. Power has initiated planning activities with respect to the construction of 300 MW to 400 MW of new gas-fired peaking capacity that is expected to be available to bid into PJM’s RPM base residual
auctions in 2008. Power estimates that the cost of this new construction could range from $250 million to $350 million. Power has requested that PJM perform studies to determine the system impact of
adding incremental capacity at some of its existing generating stations located in the Eastern Mid Atlantic Area Council reliability region. Power is also participating in a regulatory process in Connecticut
seeking new peaking capacity. Power’s final decision whether or not to proceed with construction of any of these units will depend on estimated capital and interconnection costs,
expected capacity payments, available siting and
Power’s ability to meet environmental permitting requirements. The estimated costs related to these units are included in Power’s forecasted capital expenditures. Power
is also currently exploring a number of other initiatives for potential growth
or development, including the potential to build new nuclear generation.
In addition, Power may seek from time to time to acquire assets from others.
There is no guarantee that such initiatives will be achieved since many issues
need to be considered, such as system reliability concerns, regulatory approvals
and construction or development costs. For additional information, see Item
5. Other Information. PSEG is also exploring growth opportunities through Global, with potential development of wind, biomass and solar projects, primarily in PSEG’s core markets. In March 2008, PSEG Renewable Generation, a subsidiary of Global, together with Winergy Power Holdings, a New York-based unaffiliated private developer, submitted a proposal to the New Jersey
Office of Clean Energy (OCE) to build a 350 MW wind farm approximately 16 miles off the shore of southern New Jersey. If the proposal is accepted by the OCE, subject to required permits, feasibility
and environmental studies, financing and other conditions, the wind farm could be fully operational in 2013. PSE&G has also proposed various initiatives to meet energy goals under the EMP. As discussed above, PSE&G has received BPU approval allowing PSE&G to invest approximately $105 million over two
years to help finance the installation of solar energy systems throughout its service area. PSE&G will be allowed to earn a fair return on and of its investment and partially recover its administrative costs to
implement the Solar Energy Program through regulated rates. The program will support 30 MW of solar power in the next two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard
requirements of 60 MW in PSE&G’s service area for energy years 2009 and 2010. In June 2007, PSE&G had also endorsed the construction of three new 500 kV transmission lines intended to significantly improve the reliability of the electrical grid serving New Jersey customers. PSE&G
has since endorsed another new 500 kV line for reliability purposes. PJM’s Board of Managers approved 46
construction of one of
the proposed lines (Susquehanna-Roseland) and assigned construction responsibility
to PSE&G and Pennsylvania Power and Light Company for their respective
service territories. The estimated cost of PSE&G’s portion of this
construction project is between $600 million and $650 million. Based on a
decision by FERC, PSE&G’s costs will go into transmission rate base
with incentive rate treatment, subject to regulatory approval, and can be
expected to have a positive impact on revenues and earnings for PSE&G. The three other lines which PSE&G has endorsed have not yet been submitted to PJM for approval, as required, but PSE&G believes that construction of these lines, which would follow existing
transmission rights-of-way, are needed to enhance the reliability of the transmission system. PSE&G will also be responsible for constructing a portion of the Mid-Atlantic Pathway Project (MAPP), a 500kV transmission line that will terminate at Power’s Hope Creek station in southern New
Jersey. Construction is anticipated to be completed by 2015. The results for PSEG and its subsidiaries for the quarters ended March 31, 2008 and 2007 are presented below:
Earnings
(Losses)
Quarters
Ended
2008
2007
(Millions) Power
$
275
$
219 PSE&G
137
132 Global
14
(27
) Resources
14
17 Other (A)
(6
)
(20
) PSEG Income from Continuing Operations
434
321 Income from Discontinued Operations (B)
14
8 PSEG Net Income
$
448
$
329
Earnings Per
Share (Diluted)
Quarters Ended
March 31,
2008
2007 PSEG Income from Continuing Operations
$
0.85
$
0.63 Income from Discontinued Operations
0.03
0.02 PSEG Net Income
$
0.88
$
0.65
(A)
Other activities include non-segment amounts of PSEG (as parent company) and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and
certain administrative and general expenses at PSEG and Energy Holdings (as parent companies). (B) Includes Discontinued Operations of the SAESA Group in 2008 and 2007 and of Electroandes and Lawrenceburg in 2007. See Note 3. Discontinued Operations. As shown in the table above, PSEG had Income from Continuing Operations of $434 million, or $0.85 per share for the quarter ended March 31, 2008, as compared to $321 million, or $0.63 per share
for the same quarter in 2007. PSEG’s Net Income for the quarter ended March 31, 2008 was $448 million, or $0.88 per share, as compared to Net Income of $329 million, or $0.65 per share for the first
quarter of 2007. The quarter-over-quarter changes in PSEG’s Income from Continuing Operations and Net Income primarily relate to changes in Net Income for Power, PSE&G and Energy Holdings,
discussed below. 47
March 31,
PSEG
For the
Increase
%
2008
2007
(Millions)
(Millions) Operating Revenues
$
3,803
$
3,508
$
295
8 Energy Costs
$
2,124
$
1,977
$
147
7 Operation and Maintenance
$
631
$
595
$
36
6 Depreciation and Amortization
$
194
$
192
$
2
1 Income from Equity Method Investments
$
12
$
27
$
(15
)
(56
) Other Income and (Deductions)
$
(1
)
$
36
$
(37
)
N/A Interest Expense
$
(153
)
$
(182
)
$
(29
)
(16
) Income Tax Expense
$
(234
)
$
(260
)
$
(26
)
(10
) Income from Discontinued Operations
$
14
$
8
$
6
75 PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, Power, PSE&G and Energy Holdings, excluding changes related to intercompany
transactions, which are eliminated in consolidation, and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 14. Related-Party Transactions. For
a discussion of the causes for the variances at PSEG in the table above, see the discussions for Power, PSE&G and Energy Holdings that follow. Power For the quarter ended March 31, 2008, Power had Net Income of $275 million, an increase of $62 million as compared to the same period in the prior year. The primary reasons for the increase were
higher prices and sales volumes in PJM and higher prices realized from recontracted BGS contracts. The increase was somewhat offset by higher generation costs, largely due to higher prices for natural gas
and coal fuel and by the recognition in 2008 of other-than-temporary impairments (OTTI) on certain securities in the Nuclear Decommissioning Trust (NDT) Funds in excess of those recognized in the
same period in 2007. Net Income for the three month periods included the effects of MTM gains of $3 million, after-tax,
in 2008 as compared to less than $1 million, after-tax, of losses in 2007. The quarter-over-quarter detail for the variances is discussed below:
For the
Increase
%
2008
2007
(Millions)
(Millions) Operating Revenues
$
2,375
$
2,149
$
226
11 Energy Costs
$
1,589
$
1,488
$
101
7 Operation and Maintenance
$
239
$
238
$
1
N/A Depreciation and Amortization
$
38
$
34
$
4
12 Other Income and (Deductions)
$
(5
)
$
22
$
(27
)
N/A Interest Expense
$
(42
)
$
(37
)
$
5
14 Income Tax Expense
$
(187
)
$
(155
)
$
32
21 Loss from Discontinued Operations
$
—
$
(6
)
$
6
N/A Operating Revenues The $226 million increase for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to increases of $227 million in generation revenues and $4 million in trading revenues
partially offset by a decrease of $5 million in gas revenues. Generation Generation revenues increased $227 million for the quarter ended March 31, 2008, as compared to the same period in 2007, due to an increase of $127 million resulting from a higher volume of
generation being sold at higher prices into PJM and an increase of $78 million mainly from higher prices on BGS-FP contracts and BGS Commercial and Industrial Energy hourly contracts that started in
June 2007. Also contributing to 48
Quarters Ended
March 31,
(Decrease)
Quarters Ended
March 31,
(Decrease)
the increase was $54 million from higher capacity prices resulting from the changes in the capacity markets in PJM and Connecticut. These increases were offset by a $7 million reduction of Reliability-Must-
Run (RMR) revenues in those markets. The increases were partially offset by a decrease of $16 million in sales to the New England and New York power pools, principally due to curtailment of gas by
certain suppliers and a decrease of $6 million due to the expiration of certain wholesale contracts. Gas Supply Gas supply revenues decreased $5 million for the quarter ended March 31, 2008, as compared to the same period in 2007, principally due to lower sales volumes of $36 million under the BGSS contract,
resulting from milder average temperatures in the 2008 winter heating season and customer conservation. The decrease was also due to a reduction of $33 million in gains recognized on financial hedging
transactions in 2008 as compared to the same period in 2007. These decreases were partly offset by an increase of $40 million due to higher prices under the BGSS contract and an increase of $25 million
from higher pricing and volumes of sales to third party customers. Trading Revenues Trading revenues increased $4 million for the quarter ended March 31, 2008, as compared to the same period in 2007, due primarily to gains on electric trading contracts. Operating Expenses Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as energy purchased in the market, and gas purchases to meet Power’s obligation under its BGSS
contract with PSE&G. Energy Costs increased $101 million for the quarter ended March 31, 2008, as compared to the same period in 2007, due to an increase of $94 million in generation costs and an increase
of $7 million in gas costs. Generation costs increased $94 million, reflecting an increase of $130 million mainly due to higher prices and higher volumes of natural gas and coal used for fuel, as certain units ran more frequently in
2008. The increase was somewhat offset by a reduction of $27 million due to a lower volume of oil used for fuel and by gains of $12 million on asset-backed transactions. Gas costs increased $7 million, reflecting an increase of $29 million due to higher volumes of gas sold to third party customers at higher inventory costs. This increase was partly reduced by a net
decrease of $8 million due to a reduced volume of gas sold to satisfy Power’s BGSS obligations offset by higher inventory costs and a reduction of $14 million in losses recognized on financial hedging
transactions in 2008 as compared to the same period in 2007. Operation and Maintenance Operation and Maintenance expense increased $1 million for the quarter ended March 31, 2008, as compared to the same period in 2007, due to an increase at Nuclear of $7 million, primarily related to
preparations for a planned outage at the Salem station in 2008 nearly offset by a decrease of $6 million due to the absence of maintenance costs incurred in 2007 for planned outages at certain fossil stations. Depreciation and Amortization The $4 million increase for the quarter ended March 31, 2008, as compared to the same period in 2007, was primarily due to a larger depreciable nuclear and fossil asset base in 2008. Of the increase,
$2 million was attributable to depreciation of pollution-control equipment being placed into service on January 1, 2008 at Power’s coal-fired Bridgeport, Connecticut generating facility. Other Income and Deductions Other Income and Deductions decreased $27 million for the quarter ended March 31, 2008, as compared to the same period in 2007. OTTI recognized on certain securities in the NDT Funds securities
increased $28 million from $10 million in the first quarter of 2007 to $38 million in the first quarter of 2008, reflecting 49
difficult market conditions in 2008. This decrease was partially offset by an increase of $1 million from realized gains, interest and dividend income net of realized losses and expenses related to the NDT
Funds. Interest Expense Interest Expense increased $5 million for the quarter ended March 31, 2008, as compared to the same period in 2007, due primarily to the reclassification in 2007 of Interest Expense to Discontinued
Operations of the Lawrenceburg facility, which was sold in May 2007, partially offset by higher capitalized interest costs of $4 million in 2008 related to various fossil and nuclear capital projects in process. Income Taxes Income Taxes increased $32 million for the quarter ended March 31, 2008, as compared to the same period in 2007, primarily due to higher pre-tax income. Loss from Discontinued Operations, net of tax On May 16, 2007, Power completed the sale of its Lawrenceburg generation facility. The sale price for the facility and inventory was $325 million. The transaction resulted in an after-tax charge to
Power’s earnings of $208 million and was reflected as a charge to Discontinued Operations in the fourth quarter of 2006. The Loss from Discontinued Operations of Lawrenceburg was $6 million in the first
quarter of 2007. PSE&G For the quarter ended March 31, 2008, PSE&G had Net Income of $137 million, an increase of $5 million as compared to the quarter ended March 31, 2007. The quarter-over-quarter detail for the variances is discussed below:
For the
Increase
%
2008
2007
(Millions)
(Millions) Operating Revenues
$
2,618
$
2,486
$
132
5 Energy Costs
$
1,793
$
1,665
$
128
8 Operation and Maintenance
$
360
$
325
$
35
11 Depreciation and Amortization
$
143
$
145
$
(2
)
(1
) Other Income and Other Deductions
$
4
$
4
$
—
— Interest Expense
$
(81
)
$
(81
)
$
—
— Income Tax Expense
$
(65
)
$
(99
)
$
(34
)
(34
) 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. PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and
the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial (C&I)
customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any
time, if warranted, between annual BGSS proceedings. PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply
prices are set based on the results of these auctions for residential and smaller C&I customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger C&I customers is provided at a
rate principally based on the hourly PJM real-time energy price. Customers may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric
suppliers, and the majority 50
Quarters Ended
March 31,
(Decrease)
of the customers subject to hourly pricing are currently receiving electric supply from third-party suppliers. Any differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the
amounts of electric commodity revenue collected from customers is deferred and collected or returned to customers in subsequent months. The $132 million increase in operating revenues for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to increases of $129 million in commodity revenues and $3
million in delivery revenues, described below. Commodity The
$129 million increase in commodity-related revenues for the quarter ended
March 31, 2008, as compared to 2007, was due to increases of $99 million
and $30 million in electric and gas revenues, respectively. The electric
increase was due to $100 million in higher BGS revenues (higher auction prices
of $111 million offset by decreased volumes of $11 million) and $15 million
in higher non-utility generation (NUG) prices, offset by $16 million in lower
non-utility generation clause prices. The gas increase was primarily due
to $71 million in price variances for C&I customers offset by $41 million
in lower volumes due to weather. Prices charged to C&I customers are
market-based. Delivery The $3 million increase in delivery revenues for the quarter ended March 31, 2008, as compared to 2007, was due to a $20 million increase in electric revenues offset by $17 million in lower gas
revenues. The electric increase was due primarily to $23 million for increased Societal Benefits Clause (SBC) rates offset by $3 million in lower other operating revenues. The gas decrease was due to $14
million in lower volumes primarily due to weather and $3 million in lower SBC rates. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below. Operating Expenses Energy Costs The $128 million increase for the quarter ended March 31, 2008, as compared to the same period in 2007, was comprised of increases of $100 million and $28 million in electric and gas costs,
respectively. The electric increase was due to $126 million or 15% in higher prices for BGS and NUG purchases offset by $26 million or 2% in lower volumes due to weather. The gas increase was caused by
$41 million or 2% in higher prices offset by $12 million in lower volumes, primarily due to weather. Operation and Maintenance The
$35 million increase for the quarter ended March 31, 2008, as compared to
the same period in 2007, was due to $23 million in increased amortization
of deferred expenses, resulting primarily from an SBC rate increase in March
2007. Labor costs increased $7 million due to added headcount, pay increases
and overtime related to storm work. Injuries and damages reserves increased
$2 million, regulatory commission expenses increased $1 million and various
other expenses increased by $2 million. Depreciation and Amortization The $2 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was due primarily to a $2 million reduction in software amortization, a $1 million decrease in
regulatory asset amortization and a $1 million decrease in the amortization of U.S. Department of Energy (DOE) enrichment facility decommissioning costs. These decreases were offset by a $2 million
increase due to increased plant in service. Income Taxes The $34 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was primarily due to decreased taxes of $20 million resulting from an IRS approved refund claim at PSEG for earlier tax years, $12 million on lower pre-tax income and $2 million in various tax adjustments. 51
Energy Holdings For the quarter ended March 31, 2008, Energy Holdings had Net Income of $42 million, an increase of $39 million as compared to the same period in 2007, including $14 million of Income from
Discontinued Operations in both periods. The increase was primarily due to increased earnings from the Texas generation facilities primarily due to the recognition of MTM gains of $3 million ($2 million,
after-tax) in 2008 as compared to MTM losses of $29 million ($17 million, after-tax) in 2007 combined with increased earnings at Bioenergie, which was prohibited from conducting operations during the
first quarter of 2007 at the San Marco Facility as a result of legal proceedings regarding alleged violations of the facility’s air permit. Also contributing to the increase was an income tax benefit recorded
during the first quarter of 2008 resulting from an IRS approved refund claim at PSEG for earlier tax years. The increases were partially offset by
the absence of income from Chilquinta and LDS, which were sold in December 2007, and the absence of a gain on the sale of the Tracy project and an arbitration award received during the first quarter of
2007. The quarter-over-quarter detail for the variances is discussed below:
For the
Increase
%
2008
2007
(Millions)
(Millions) Operating Revenues
$
142
$
148
$
(6
)
(4
) Energy Costs
$
73
$
96
$
(23
)
(24
) Operation and Maintenance
$
38
$
38
$
—
N/A Depreciation and Amortization
$
9
$
10
$
(1
)
(10
) Income from Equity Method Investments
$
12
$
27
$
(15
)
(56
) Other Income and Deductions
$
3
$
14
$
(11
)
(79
) Interest Expense
$
(24
)
$
(39
)
$
(15
)
(38
) Income Tax Benefit (Expense)
$
15
$
(17
)
$
(32
)
N/A Income from Discontinued Operations
$
14
$
14
$
—
N/A Operating Revenues The $6 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was primarily due to lower lease revenues at Resources of $13 million combined with the
absence of a gain on settlement of its investment in a collateralized bond fund in the first quarter of 2007. The decrease at Resources was partially offset by a $6 million increase in revenues at Global, which
primarily related to the San Marco facility at Bionergie being operational during 2008, which was partially offset by the absence of a gain on the sale of Global’s 34.5% interest in Tracy Biomass in January
2007. Operating Expenses Energy Costs The $23 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to a $28 million decrease at the Texas generation facilities primarily due to MTM
activity related to gas contracts, offset by a $5 million increase at Bioenergie with the San Marco facility being operational during 2008. Depreciation and Amortization The $1 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to lower depreciation at the Texas generation facilities. Income from Equity Method Investments The $15 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to the absence of earnings from Chilquinta and LDS which were sold in December
2007. 52
Quarters
Ended
March 31,
(Decrease)
Other Income and Deductions The $11 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was primarily due to the absence of a $9 million pre-tax gain from the award received in the
first quarter of 2007 relating to an arbitration proceeding against the Turkish government regarding the construction of a power plant in the Konya-Ilgin region of Turkey. Interest Expense The $15 million decrease for the quarter ended March 31, 2008, as compared to the same period in 2007, was due to a decrease in debt outstanding, primarily resulting from the maturity of $207 million
of 8.625% Senior Notes in February 2008 and the redemption of $400 million of 10% Senior Notes in January 2008. Income Taxes For the quarter ended March 31, 2008, Energy Holdings recorded an Income Tax Benefit of $15 million, as compared to Income Tax Expense of $17 million for the same period in 2007. The $32 million
variance was primarily due to an IRS approved refund claim at PSEG for earlier
tax years. Income from Discontinued Operations, net of tax SAESA Group On December 18, 2007, Global announced its plan to sell its investment in the SAESA group of companies. As a result, operating results for the SAESA Group have been presented as Discontinued
Operations. Income from Discontinued Operations related to the SAESA Group for each of the quarters ended March 31, 2008 and 2007 was $14 million. See Note 3. Discontinued Operations for
additional information. Electroandes On October 17, 2007, Global completed the sale of Electroandes for a total purchase price of $390 million, including the assumption of approximately $108 million of debt. There was no Income from
Discontinued Operations related to Electroandes for the quarter ended March 31, 2007. See Note 3. Discontinued Operations for additional information. 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, Power, PSE&G and Energy
Holdings. Operating Cash Flows PSEG For the quarter ended March 31, 2008, PSEG’s operating cash flow increased by $95 million from $948 million to $1.043 billion, as compared to the same period in 2007, due to changes from its
subsidiaries as discussed below. Power Power’s operating cash flow increased $114 million from $824 million to $938 million for the quarter ended March 31, 2008, as compared to the same period in 2007, primarily due to higher net income
of $62 million and to less of an increase in cash collateral requirements in the first quarter of 2008 than in the comparable period in 2007. 53
PSE&G PSE&G’s operating cash flow increased $200 million from $61 million to $261 million for the quarter ended March 31, 2008, as compared to the same period in 2007, primarily due to increased collections
of customer receivables. Energy Holdings Energy Holdings’ operating cash flow decreased $220 million from $82 million to $(138) million for the quarter ended March 31, 2008, as compared to the same period in 2007. The decrease was mainly
attributable to increased tax payments, primarily related to the sale of Chilquinta and LDS, combined with lower distributions from Global’s equity method investments for the quarter ended March 31,
2008, as compared to the same period in 2007. Common Stock Dividends Dividend payments on common stock for the quarters ended March 31, 2008 and 2007 were $0.3225 and $0.2925 per share, respectively, and totaled $164 million and $148 million, respectively. On April
15, 2008, PSEG’s Board of Directors approved a common stock dividend of $0.3225 per share for the second quarter of 2008, reflecting an indicated annual dividend rate of $1.29 per share. PSEG expects to
continue to pay cash dividends on its common stock; however, the declaration and payment of future dividends to holders of PSEG common stock will be at the discretion of the Board of Directors and will
depend upon many factors, including PSEG’s financial condition, earnings, cash flows, capital requirements of its business, alternate investment opportunities, legal requirements, regulatory constraints,
industry practice and other factors that the Board of Directors deems relevant. Short-Term Liquidity PSEG, Power and PSE&G As of March 31, 2008, PSEG, Power and PSE&G had the following committed credit facilities. Each of the facilities is restricted as to availability and use to the specific companies as listed below. PSEG,
Power and PSE&G believe sufficient liquidity exists to fund their respective short-term cash requirements. Company
Expiration
Total
Primary
Usage
Available
(Millions) PSEG: 5-year Credit Facility(A)
Dec 2012
$
1,000
CP Support/Fund-
$
46
(B)
$
954 Uncommitted Bilateral Agreement
N/A
N/A
Funding
$
—
$
N/A Power: (C) 5-year Credit Facility(A)
Dec 2012
$
1,600
Funding/Letters of
Credit
$
505
(B)
$
1,095 Bilateral Credit Facility
March 2010
$
100
Funding/Letters of
Credit
$
69
(B)
$
31 PSE&G: 5-year Credit Facility(A)
June 2012
$
600
CP Support/Fund-
$
128
$
472 Uncommitted Bilateral Agreement
N/A
N/A
Funding
$
—
N/A
(A)
In 2012, facilities reduce by $47 million, $75 million and $28 million for PSEG, Power and PSE&G, respectively. (B) These amounts relate to letters of credit outstanding. 54
Date
Facility
Purpose
as of
March 31,
2008
Liquidity
as of
March 31,
2008
ing/Letters of
Credit
ing/Letters of
Credit
(C) Power had a $200 million bilateral credit facility that expired in March 2008. In April 2008, Power renewed the facility, reducing it to $150 million with the same counterparty on similar terms. Power As of March 31, 2008, Power had loaned $407 million to PSEG in the form of an intercompany loan. During the quarter ending March 31, 2008, Power’s required margin postings for sales contracts entered into in the normal course of business increased significantly. The required margin postings will
fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are
fulfilled, liquidity requirements are reduced. In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit
rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance
assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset
portfolio. As of March 31, 2008, Power believes it has sufficient liquidity to meet its potential required posting of collateral which could result from a credit rating downgrade. See Note 5. Commitments and
Contingent Liabilities for further information. External Financings For
information related to External Financings, see Note 8. Changes in Capitalization. Debt Covenants PSEG’s, Power’s and PSE&G’s respective credit agreements may contain maximum debt to total capitalization ratios 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, Power and PSE&G, as to which no assurances can be given. The ratios
presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or liquidity measures. PSEG Financial covenants contained in PSEG’s note purchase agreements related to the private placement of debt include a ratio of total debt (excluding non-recourse project financings, securitization debt
and debt underlying preferred securities and including commercial paper and loans and certain letters of credit) to total capitalization (including preferred securities outstanding) covenant. This covenant
requires that such ratio not be more than 70.0%. As of March 31, 2008, PSEG’s ratio of debt to capitalization (as defined above)
was 51.2%. PSEG’s credit facility contains a similar but less restrictive financial covenant where total debt excludes letters of credit related to collateral postings and total capitalization excludes any impacts for
Accumulated Other Comprehensive Income/Loss adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with
Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This covenant requires that such ratio not be more than
70.0%. As of March 31, 2008, PSEG’s ratio of debt to capitalization (as defined above) was 47.1%. Power Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for
PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of March 31, 2008,
Power’s ratio of debt to total capitalization (as defined above) was 38.8%. 55
PSE&G Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total
capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of March 31, 2008, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 45.4%. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges
calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of March 31, 2008, PSE&G’s Mortgage coverage ratio was 3.6 to 1 and the Mortgage would permit up
to $2.1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous bondable additions and improvements to its property. Credit Ratings PSEG, Power and PSE&G If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, Power’s and PSE&G’s securities and serve to materially increase those
companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). 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.
Moody’s (A)
S&P (B)
Fitch (C) PSEG: Outlook
Neg
Stable
Stable Commercial Paper
P2
A2
F2 Power: Outlook
Stable
Stable
Stable Senior Notes
Baa1
BBB
BBB+ PSE&G: Outlook
Neg
Stable
Stable Mortgage Bonds
A3
A–
A Preferred Securities
Baa3
BB+
BBB+ Commercial Paper
P2
A2
F2
(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. (B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. (C) Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities. Other Comprehensive Income PSEG, Power and PSE&G For information related to Other Comprehensive Income/Loss, see Note 7. Comprehensive Income (Loss), Net of Tax. PSEG, Power and PSE&G It is expected that the majority of funding for capital requirements of Power and PSE&G will come from their respective internally generated funds. The balance will be provided by the issuance of debt
at the 56
respective subsidiary or project level and by equity contributions from PSEG. Projected construction and investment expenditures for PSEG, Power and PSE&G are materially consistent with amounts
disclosed in the Annual Reports on Form 10-K of PSEG, Power and PSE&G for the year ended December 31, 2007. Power During the quarter ended March 31, 2008, Power made $165 million of capital expenditures (excluding $9 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. For
additional information regarding current projects, see Note 5. Commitments and Contingent Liabilities. PSE&G During the quarter ended March 31, 2008, PSE&G made $145 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $145 million does not include
expenditures for cost of removal, net of salvage, of $9 million, which are included in operating cash flows. PSEG, Power and PSE&G For information related to recent accounting matters, see Note 2. Recent Accounting Standards. ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK PSEG, Power and PSE&G The market risk inherent in PSEG’s, Power’s and PSE&G’s 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 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, Power and PSE&G have a Risk Management Committee comprised of executive officers who utilize an independent risk oversight function to
ensure compliance with corporate policies and prudent risk management practices. Additionally, PSEG, Power and PSE&G are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which 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’s and
its subsidiaries’ Condensed Consolidated Financial Statements. Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, Power and PSE&G for the year ended December 31, 2007. Commodity Contracts The availability and price of energy-related 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. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity. Normal Operations and Hedging Activities Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce 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. 57
Under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in
Accumulated Other Comprehensive Loss, 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. Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement. Trading Power maintains a strategy of entering into 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, which have significantly decreased. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to
market in accordance with SFAS 133 with gains and losses recognized in earnings. Value-at-Risk (VaR) Models Power Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales
requirements, load requirements and financial derivative instruments. VaR represents 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 manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to
manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading MTM VaR consists of
MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading 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 the MTM trading and non-
trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively
manages its portfolio. Reduced trading activities by Power during 2008 have resulted in less trading risk although higher market prices and volatilities have lead to a higher non-trading VaR as compared to March 31, 2007
and December 31, 2007. As of March 31, 2008 and December 31, 2007, trading VaR was less than $1 million.
Trading VaR
Non-Trading
(Millions) For the Quarter Ended March 31, 2008 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End
$
1
$
84 Average for the Period
$
—
*
$
57 High
$
1
$
116 Low
$
—
*
$
42 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End
$
1
$
131 Average for the Period
$
1
$
90 High
$
1
$
181 Low
$
—
*
$
65 58
MTM VaR
*
less than $1 million
Other Supplemental Information Regarding Market Risk Power The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the three
months ended March 31, 2008. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the
information in this table highlights, MTM 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 MTM activities reported here are those relating to changes in fair value due to external movement in prices. For additional information, see Note 6.
Financial Risk Management Activities. Operating Revenues
Normal
Trading
Total
(Millions) MTM Activities: Unrealized MTM Gains (Losses) Changes in Fair Value of Open Position
$
14
$
2
$
16 Realization at Settlement of Contracts
(1
)
(2
)
(3
) Total Change in Unrealized Fair Value
13
—
13 Realized Net Settlement of Transactions Subject to MTM
1
2
3 Net MTM Gains
14
2
16 Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications
2,359
—
2,359 Total Operating Revenues
$
2,373
$
2
$
2,375
(A)
Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions (ABT) and hedging activities,
but excludes owned and contracted generation assets.
The following table indicates Power’s energy contracts, including Power’s hedging activity related to ABT and derivative instruments that qualify for hedge accounting under SFAS 133. This table and
the one that follows present amounts segregated by portfolio that are then netted for those counterparties with whom Power has the right to offset and therefore, are not necessarily indicative of amounts
presented on the Condensed Consolidated Balance Sheets. The balances with counterparties with whom Power has master netting agreements may also be offset against collateral amounts with those
counterparties. For the quarter ended March 31, 2008, $209 million of cash collateral was offset against a Net Energy Contract Liability of $665 million. This resulted in a Net Energy Contract Liability of
$456 million as presented on the Condensed Consolidated Balance Sheet. 59
For the Quarter Ended March 31, 2008
Operations
and
Hedging(A)
Energy Contract Net Assets/Liabilities
Normal
Trading
Total
(Millions) MTM Energy Assets Current Assets
$
148
$
25
$
173 Noncurrent Assets
9
2
11 Total MTM Energy Assets
157
27
184 MTM Energy Liabilities Current Liabilities
$
(538
)
$
(13
)
$
(551
) Noncurrent Liabilities
(296
)
(2
)
(298
) Total MTM Energy Liabilities
(834
)
(15
)
(849
) Total MTM Energy Contract Net (Liabilities) Assets
$
(677
)
$
12
$
(665
) The following table presents the maturity of net fair value of MTM energy contracts. Maturity of Net Fair Value of MTM Energy Trading Contracts
Maturities within
2008
2009
2010-2012
Total
(Millions) Trading
$
11
$
1
$
—
$
12 Normal Operations and Hedging
(308
)
(252
)
(117
)
(677
) Total Net Unrealized Losses on MTM Contracts
$
(297
)
$
(251
)
$
(117
)
$
(665
) 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. Global The following table describes the drivers of Global’s marketing activities and Operating Revenues included in PSEG’s Condensed Consolidated Statement of Operations for the quarter ended March
31, 2008. Normal operations and hedging activities represent the marketing of electricity available from Global’s owned generation sold into the market. Activities accounted for under the accrual method
account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. Operating Revenues
Normal
(Millions) MTM Activities: Unrealized MTM Gains Changes in Fair Value of Open Position
$
6 Realization at Settlement of Contracts
— Total Change in Unrealized Fair Value
6 Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications
102 Total Operating Revenues
$
108 60
As of March 31, 2008
Operations
and
Hedging
As of March 31, 2008
For the Quarter Ended March 31, 2008
Operations
and
Hedging(A)
(A)
Includes derivative contracts that Global enters into to hedge anticipated exposures related to its owned and contracted generation supply.
The following table indicates Global’s energy contract net assets. Energy Contract Net Assets/Liabilities
Normal
(Millions) MTM Energy Assets Current Assets
$
20 Noncurrent Assets
46 Total MTM Energy Assets
66 MTM Energy Liabilities Current Liabilities
$
34 Noncurrent Liabilities
— Total MTM Energy Liabilities
34 Total MTM Energy Contract Net Assets
$
32 The following table presents the maturity of net fair value of MTM energy contracts. Maturity of Net Fair Value of MTM Energy Contracts
Maturities within
2008
2009
2010-
Total
(Millions) Total Net Unrealized (Losses) Gains on MTM Contracts
$
(24
)
$
29
$
27
$
32 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. PSEG and Power 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 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 and Power 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, net of taxes that are expected to be reclassified
out of Accumulated Other Comprehensive Loss and into earnings over the next twelve months. Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
Accumulated
Portion
(Millions) Commodities
$
(493
)
$
(295
) Interest Rates
(7
)
(6
) Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss
$
(500
)
$
(301
) 61
As of March 31, 2008
Operations
and
Hedging
As of March 31, 2008
2012
As of March 31, 2008
Other
Comprehensive
Loss
Expected
to be
Reclassified
in next 12
months
Power Credit Risk The following table provides information on Power’s credit exposure, net of collateral, as of March 31, 2008. Credit exposure 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 Rating
Current
Securities
Net
Number of
Net
(Millions)
(Millions) Investment Grade—External Rating
$
418
$
13
$
414
1
(A)
$
317 Non-Investment Grade—External Rating
416
—
416
1
(B)
401 Investment Grade—No External Rating
—
—
—
—
— Non-Investment Grade—No External Rating
38
1
37
—
— Total
$
872
$
14
$
867
2
$
718
(A)
PSE&G is a counterparty with net exposure of $317 million. (B) Credit exposure with non-investment grade counterparty is with a coal supplier to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than
payment risk. Coal prices have risen sharply since the beginning of 2008. 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 March 31, 2008, Power had 117 active counterparties. ITEM 4. CONTROLS AND PROCEDURES PSEG, Power and PSE&G Disclosure Controls and Procedures PSEG, Power and PSE&G have established and maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in the reports
that are filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. These disclosure
controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that such information is accumulated and communicated to management, including the
Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within those entities to allow timely decisions regarding required disclosure. PSEG, Power and
PSE&G have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective
company. The committee monitors and evaluates the effectiveness of 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 and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in achieving their objectives at the reasonable
assurance level as of March 31, 2008. Internal Controls PSEG, Power and PSE&G continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no
changes in internal control over financial reporting that occurred during the first quarter of 2008 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control
over financial reporting. 62
As of March 31, 2008
Exposure
Held as
Collateral
Exposure
Counterparties
>10%
Exposure of
Counterparties
>10%
PSEG, Power and PSE&G PSEG,
Power and PSE&G are parties to various lawsuits and regulatory matters
in the ordinary course of business. For information regarding material legal
proceedings, including updates to information reported under Item 3 of Part
I of the respective 2007 Annual Reports on Form 10-K of PSEG, Power and PSE&G,
see Note 5. Commitments and Contingent Liabilities and Item 5. Other Information,
Regulatory
Issues. There
are no risk factors to be added to the Risk Factors disclosed in Part I Item
1A included in PSEG’s, Power’s and PSE&G’s
respective 2007 Annual Reports on Form 10-K. The risk factors set forth in the
2007 Annual Report of Form 10-K should be read in light of the following
developments: 2007 Form 10-K Page 32. Treatment of ITC included in previous write-down of generation assets: The
Treasury issued final regulations confirming the conclusion reached in the
private letter ruling which PSE&G
received from the IRS in May 2006. 2007 Form 10-K Page 35. We may be adversely affected by changes in energy deregulation policies, including market design rules. A draft EMP was released in April 2008 with a final plan expected
to be completed later in the year. See Item 5. Other Information for additional discussion of the EMP. In addition, the following risk factor is restated in its entirety: 2007 Form 10-k, Page 37. Certain of our leveraged lease transactions at Resources may be successfully challenged by the IRS, which would have a material adverse effect on our taxes, operating
results and cash flows. On November 16, 2006, the IRS issued its Revenue Agent’s Report for tax years 1997 through 2000, which disallowed all deductions associated with certain lease transactions that are similar to a type
that the IRS publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest of these
findings with the Office of Appeals of the IRS. On April 9, 2008, the IRS issued its Revenue Agent’s Report for tax years 2001 through 2003, which disallowed all deductions associated with lease transactions similar to those disallowed in its 1997
through 2000 Report. As in its prior report, the IRS imposed a 20% penalty. PSEG is presently preparing a protest to this report which will be filed with the Office of Appeals of the IRS. As of March 31, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1.5 billion. PSEG has been in discussions with the Office of Appeals of the IRS concerning the deductions that have been disallowed. The outcome of such discussions cannot be predicted. Based
on developments in tax cases involving other entities and its ongoing discussions
with the IRS, PSEG anticipates that, absent reaching an agreement with the
IRS to resolve this issue, a decision to proceed to litigation may occur
in 2008. It is also reasonably possible that a re-measurement of unrecognized
tax benefits related to these lease transactions will occur during the next
12 months. Such re-measurement could result in a material charge to earnings
and a corresponding material impact to the Condensed Consolidated Balance
Sheet; however, such impacts cannot be estimated at this time. If all deductions associated with these lease transactions are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s Condensed Consolidated Financial Statements and
could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law. If the IRS’ disallowance of tax benefits associated with all of these lease transactions were sustained, $904 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease
accounting through March 31, 2008 would become currently payable. In addition, as of March 31, 2008 interest of $195 million, after-tax, and penalties of $173 million may become payable, with potential
additional interest and penalties of $15 million continuing to accrue quarterly. 63
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PSEG’s
Annual Meeting of Stockholders was held on April 15, 2008. Proxies for the
meeting were solicited pursuant to Regulation 14A under the Securities Act
of 1934. There was no solicitation of proxies in opposition to management’s
nominees as listed in the proxy statement and all of management’s nominees
were elected to the Board of Directors. Details of the voting are provided
below:
Votes For
Votes Withheld Proposal 1: Election of Directors Terms expiring in 2009 Conrad K. Harper
443,437,354
9,428,617 Shirley Ann Jackson
438,859,800
14,006,171 Thomas A. Renyi
443,506,148
9,359,823
Votes For
Votes
Abstentions Proposal 2: Ratification of Appointment of Deloitte & Touche LLP as Independent Auditor
442,087,678
5,971,613
4,806,679 Proposal 3: To modify the system of compensation for senior executives
22,818,086
359,901,179
8,868,573 Proposal 4: To nominate candidates for the Board of Directors from stockholders of long-term tenure without age restriction
15,671,201
366,300,406
9,616,231 Proposal 5: For Board of Directors to nominate at least two candidates for each open board position
18,438,450
364,141,565
9,007,823 64
Against
Certain information reported under the 2007 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of
the 2007 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed. REGULATORY ISSUES Federal Regulation FERC PSEG, Power and PSE&G Regulation of Wholesale Sales—Generation/Market Issues 2007 Form 10-K, Page 15. Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. Public utilities may sell power at cost-based rates or may
apply to the FERC for authority to sell power at market-based rates (MBR). In order to obtain approval to sell power at MBR, the FERC must first make a determination that the requesting company
lacks market power in the relevant markets. Once this determination is made, and MBR authority is granted, the public utility’s individual sales made under the MBR authority are not reviewed or
approved by the FERC but are reported to the FERC in quarterly reports. In
January 2008, PSE&G, ER&T and Power Connecticut LLC (Power Connecticut)
filed with the FERC their initial respective updated market power reports
as required by the FERC’s new MBR rules.
In addition, in this filing, Fossil and Nuclear, which currently sell all of
their power to ER&T under FERC-approved cost-based rates, have asked
for the authority to sell power at MBR. PSE&G, ER&T, Power
Connecticut, Fossil and Nuclear asserted in their MBR filing that they either
lack any generation market power or, if they do possess any market power,
that market power is being effectively mitigated. PSE&G, ER&T, Power
Connecticut, Fossil and Nuclear further asserted in their initial filing
that, to the extent that the FERC analyzes market power held in the small
sub-market of Northern PSEG, PJM mitigation rules (including price capping
for bids) eliminate the potential for the exercise of market power in this
sub-market. PSE&G, ER&T, Power Connecticut, Fossil and Nuclear plan,
however, to make a supplemental filing to reflect a decision rendered by
the FERC on April 17, 2008 that (i) eliminates the need for these companies
to conduct a market power analysis within the Northern PSEG sub-market; (ii)
adopts a rebuttable presumption that existing Regional Transmission Organization
(RTO) mitigation schemes eliminate any market power concerns; and (iii) requires
additional market power studies. This MBR filing is currently pending, though
no substantive protests were filed by any party to the proceeding. The outcome
of this filing cannot be predicted at this time. PJM’s wholesale markets depend upon PJM’s Market Monitoring Unit (MMU) being viewed as a well-functioning and independent entity capable of effectively analyzing and addressing market power
issues within PJM and stepping in to impose mitigation measures when required. In 2007, various state commissions and consumer groups filed a complaint at the FERC challenging the MMU’s
independence by alleging that PJM was interfering with the MMU’s operations. On March 21, 2008, the FERC approved the settlement of this matter, under which the MMU will be a stand-alone company,
engaged by contract (initial 6-year term) by PJM, with separate employees. This approach differs from the pre-existing internal MMU model. The Cross Hudson Project 2007
Form 10-K, Page 16. In December 2007, Power submitted a response
to a request by the New York Power Authority (NYPA) for additional power
supply to New York City. Power proposed to disconnect its existing Bergen
2 generation station from the PJM grid and connect the station to the
New York Independent System Operator (NYISO) transmission grid via a
direct generator lead which will be constructed by a third party. On
January 17, 2008, Power and the third party filed a request for a declaratory
order at FERC seeking clarification from FERC on the status and use of
the proposed generator lead. Power and the third party requested that
FERC make a determination that it will not order the generator lead to
be reconnected to the PJM system, that Power’s use of the generator
lead will not be displaced by another party and the negotiated economic
terms for the use of the generator lead are appropriate under the Federal
Power Act. A number of parties, including the BPU and the New Jersey
Division of Ratepayer Advocate, filed protests in the FERC declaratory
order 65
proceeding opposing the proposed disconnection of Bergen 2 from the PJM grid. On April 1, 2008, the FERC issued an order partially granting the request for a declaratory order which dismissed the
claims of the BPU and others that the project should not be allowed to proceed and granted the request for negotiated rates for use of the generator lead. The FERC did not rule on the issue of whether it
could order the generator lead line to be reconnected to the PJM system in the future. On April 29, 2008, the NYPA accepted the proposal of another supplier, subject to negotiation of a written agreement. Capacity Market Issues 2007 Form 10-K, Page 16. Reliability Pricing Model (RPM) is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM,
generators located in constrained areas within PJM are paid more for their capacity so that they are incented to locate in those areas where generation capacity is most needed. Four PJM capacity auctions
covering commitment periods extending from June 1, 2007 through May 31, 2011 have been held to date. In a proceeding in which PSE&G, Power and ER&T are petitioners, PJM’s RPM has been challenged
in the United States Court of Appeals for the District of Columbia Circuit. PSE&G, Power and ER&T strongly support the RPM design but believe that certain components of the design should be modified. In
early 2006, certain interested market participants in New England agreed
to a settlement that establishes the design of the region’s market for
installed capacity and which will be implemented gradually over four years.
Commencing in December 2006, all generators in New England began receiving
forward capacity market payments that escalate gradually over the transition
period. Reliability Must Run (RMR) contracts, such as Power’s, which
provide cost-based compensation to a generation owner when a unit proposed
for retirement is asked to continue operating for reliability purposes, continue
to be effective until the implementation of the new market design in 2010.
The forward capacity market design (FCM) consists of a forward-looking auction
for installed capacity that is intended to recognize the locational value
of generators on the system and contains incentive mechanisms to encourage
generator availability during generation shortages. The first New England
auction covering the commitment period from June 1, 2010 to May 31, 2011
occurred in February 2008. In a proceeding in which Power was a party, except
for a procedural challenge that is not expected to affect FCM implementation,
claims regarding New England’s FCM were rejected by the United States
Court of Appeals for the District of Columbia Circuit in March 2008. Capacity
market rules in both PJM and in New England have also been criticized in
various forums, including FERC, by certain customer and consumer groups as
well as state regulatory authorities and governmental officials. One component
of the RPM and FCM calculations is the cost of new entry (CONE). If the CONE
is set too low, generators in the New England and PJM markets may not be
adequately compensated for existing capacity and may decline to participate
in RPM and FCM auctions and may not have sufficient incentives to construct
new generating units for which they do not anticipate receiving an acceptable
return. In April 2008, the FERC rejected PJM’s filing to increase the
CONE for a new gas-fired peaking unit to be used in the calculation of capacity
prices to be set by future RPM auctions. The period for appeal has not expired. Power can not predict how capacity market design may change in the future. FERC Transmission Regulation PJM Economic Transmission Construction Rules 2007
Form 10-K, Page 17. PJM has proposed significant changes to the
rules establishing how economic transmission gets built within PJM. Economic
transmission is transmission that is being built not to address a reliability
problem, but instead to reduce economic congestion on the system, as
congestion can result in higher electricity prices paid by consumers
located within congested areas. PJM proposes to forecast congestion levels
well into the future and to use these forecasts as the basis for determining
the benefits of an economic transmission project. Moreover, PJM’s
proposal permits economic transmission that is rate-based (i.e. transmission
that is funded by a company’s
ratepayers and for which the company itself is not at financial risk) to be
constructed as a first resort, rather than permit market solutions (transmission,
generation and/or demand response) to first come forward to address congestion
issues as is currently permitted in the NYISO. On April 17, 2008, the FERC both accepted and rejected aspects of PJM’s proposed economic transmission rules, while accepting the general tariff mechanism that will allow rate-based economic
transmission projects to move forward in PJM. In this proceeding, Power and PSE&G had recommended the 66
implementation of a voting mechanism that will permit the identified beneficiaries of an economic transmission project to vote on the merits of a particular economic transmission project and to decide
whether it gets built. The FERC rejected this argument in its April 2008 order but PSEG plans to challenge this rejection on rehearing. Transmission Expansion 2007 Form 10-K, Page 17. In June 2007, PSE&G endorsed the construction of three new 500 kV transmission lines intended to significantly improve the reliability of the electrical grid serving New
Jersey customers. PSE&G has since endorsed another new 500 kV line for reliability purposes. Also in June 2007, PJM approved construction of one of the proposed lines (Susquehanna-Roseland line) and
construction responsibility was ultimately assigned to PSE&G and Pennsylvania Power and Light Company for their respective service territories. The estimated cost of PSE&G’s portion of this construction
project is between $600 million and $650 million, and the line currently has an expected in-service date of 2012. The three other lines which PSE&G has endorsed have not yet been submitted to PJM for
approval. Construction of the Susquehanna-Roseland line and the other transmission projects that have been endorsed by PSE&G is contingent upon obtaining all necessary landowner, municipal and state
permits and approvals. In March 2008, the FERC approved in its entirety PSE&G’s filing to classify as transmission (rather than distribution) certain separate 69 kV facilities that PSE&G will construct. On April 17, 2008, the FERC approved incentive rate treatment for the Susquehanna-Roseland line consisting of:
•
a 125 basis point adder to return on equity for the Susquehanna-Roseland line; • a 50 basis point adder for continued membership in PJM; • 100% recovery of prudently incurred construction work-in-progress expenses to be included in rate base; • abandonment expenses; and • the authority to transfer certain incentives to affiliates that are members of RTOs. U.S. Department of Energy (DOE) Congestion Study 2007 Form 10-K, Page 17. In early 2007, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress. This Congestion Study identified two areas in
the U.S. as critical congestion areas; one of the areas is the region between New York and Washington, D.C. and encompassing all of New Jersey. The DOE has the ability to designate transmission
corridors in these critical congestion areas, which then gives the FERC the ability to site transmission projects within these corridors should the relevant state(s) fail to act in a timely manner. In October 2007, the DOE acted to designate transmission corridors within these critical congestion areas. One of the corridors designated, for a twelve year period, is the Mid-Atlantic Area National
Corridor. This corridor designation covers most of the PJM territory. In March 2008, the DOE affirmed its report on rehearing, though it remains subject to challenge in court; thus the final outcome of this
proceeding cannot be predicted. Should the Mid-Atlantic Area corridor designation remain intact, entities seeking to build transmission within its geographic scope, which includes New Jersey, most of
Pennsylvania and New York, will be able to use the FERC’s backstop eminent domain authority in the future, if necessary to site transmission. Nuclear Regulatory Commission (NRC) Power Additional NRC Oversight 2007 Form 10-K, Page 19. Power has been advised by the NRC that Salem Unit 1 will be subject to additional oversight. The additional NRC oversight is due to a negative change in the performance
indicator related to the plant’s diesel back-up power system. In December 2007, one of Salem Unit 1’s emergency diesel generators failed to start during NRC testing. This test failure, combined with
another instance earlier in the year in which another of the unit’s diesel generators failed to start and a third failure in 2005 in which 67
an emergency diesel generator failed to run led to the NRC’s action to downgrade the indicator. The change will result in a corresponding increase in the NRC’s inspection and assessment oversight at
Salem Unit 1. This increased oversight will include a supplemental inspection to provide assurance that the problem has been adequately addressed. Power will continue to be under heightened oversight
until inspection and reviews are completed by the NRC. State Regulation Power and PSE&G BGSS 2007 Form 10-K, Page 21. BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of
each year, with an effective date of October 1. Revenues are matched with costs using deferred accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In addition,
PSE&G has the ability to put in place two self-implementing BGSS increases on December 1 and February 1 of up to 5% and also may reduce the BGSS rate at any time. PSE&G has a full-requirements contract through 2012 with Power to meet the supply requirements of PSE&G’s default service gas customers. Power charges PSE&G for gas commodity costs which PSE&G
recovers from its customers. Any difference between rates charged by Power under the BGSS contract and rates charged to PSE&G’s residential customers are deferred and collected or refunded through
adjustments in future rates. PSE&G earns no margin on the provision of BGSS. There were no changes to the BGSS rate in 2007. In June 2007, PSE&G requested an increase in annual BGSS revenues of $39 million, excluding Sales and Use Tax, to be effective October 1, 2007.
However, as a result of lower forward gas prices after the filing, the parties to the proceeding agreed that the requested increase was not necessary. The current BGSS rate will remain in effect and is
considered final. A Stipulation including final terms has been executed and the BPU approved the agreement in a written Order dated March 4, 2008. Solar Initiative 2007 Form 10-K, Page 22. On April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. Under the plan, PSE&G
will invest approximately $105 million over two years following BPU approval of the plan in a pilot program to help finance the installation of solar systems throughout its service area. PSE&G will loan
money to customers in its electric service territory for the installation of solar photovoltaic systems on the customers’ premises. The borrowers will repay the loans over a period of either 10 years (for
residential customer loans) or 15 years (for all other loans) by providing PSE&G with solar renewable energy certificates (SRECs). Borrowers will also have the option to repay the loans with cash. PSE&G’s
proposal is conditioned on it being allowed to earn a fair return on and of its investment, and recover its administrative costs to implement the program, through its regulated rates. The program will support 30 MW of solar power in the following two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard requirements in PSE&G’s service area for energy years
2009 and 2010. On March 18, 2008, PSE&G, BPU Staff and the New Jersey Division of Rate Counsel reached a settlement agreement paving the way for PSE&G to invest approximately $105 million in a solar
energy pilot program. This program received final BPU approval on April 8, 2008 and a written BPU order on April 16, 2008. Implementation of the program will follow. New Jersey Energy Master Plan (EMP) 2007 Form 10-K, Page 22. State law in New Jersey requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster
economic growth and development and protect the environment. A draft EMP was released in April 2008 with a final plan expected to be completed later in the year. It proposes a number of the actions to
improve energy 68
efficiency and increase the use of renewable resources and clean central station power for addressing climate change, including to:
•
conduct a complete review of the BGS auction process; • maximize
energy conservation and energy efficiency to reduce New Jersey’s
projected energy use by 20% by the year 2020; • reduce
prices by decreasing peak demand by 5,700 MW by 2020; • meet
22.5% of New Jersey’s electricity needs from renewable sources; • develop
new low carbon emitting, efficient power plants to help close the gap
between the supply and demand of electricity; • invest
in innovative clean energy technologies and businesses to stimulate the
industry’s growth in New Jersey; and • consider
the establishment of a state power authority or a state energy council. PSE&G has stated its desire to be a partner to the state in the EMP. To this end PSE&G has proposed several programs in filings with the BPU addressing different components of the EMP goals, has
submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation and has been actively involved in the broad-based constituent working
groups created to develop these strategies. PSEG and PSE&G will participate in the upcoming public proceedings to review the conclusions and recommendations of the EMP. 69
A listing of exhibits being filed with this document is as follows:
a.
PSEG:
Exhibit 12:
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
Exhibit 31.1:
Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:
Certification by Ralph Izzo 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
b.
Power:
Exhibit 12.1:
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31.2:
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.3:
Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.2:
Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32.3:
Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
c.
PSE&G:
Exhibit 12.2:
Computation of Ratios of Earnings to Fixed Charges
Exhibit 12.3:
Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements
Exhibit 31.4:
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 31.5:
Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32.4:
Certification by Ralph Izzo 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 70
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. PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: May 6, 2008 71
(Registrant)
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. PSEG POWER LLC
By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: May 6, 2008 72
(Registrant)
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. PUBLIC SERVICE ELECTRIC AND GAS COMPANY
By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: May 6, 2008 73
(Registrant)
Vice President and Controller
(Principal Accounting Officer)