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 September 30, 2009
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 Identification No. |
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001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
22-2625848 |
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001-34232 |
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 the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
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Public Service Enterprise Group Incorporated |
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Yes S |
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No £ |
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PSEG Power LLC |
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Yes £ |
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No £ |
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Public Service Electric and Gas Company |
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Yes £ |
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No £ |
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(Cover continued on next page)
(Cover continued from previous page) Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Public Service Enterprise Group Incorporated
Large accelerated filer S
Accelerated filer £
Non-accelerated filer £
Smaller reporting company £ PSEG Power LLC
Large accelerated filer £
Accelerated filer £
Non-accelerated filer S
Smaller reporting company £ Public Service Electric and Gas Company
Large accelerated filer £
Accelerated filer £
Non-accelerated filer S
Smaller reporting company £ 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 October 15, 2009, Public Service Enterprise Group Incorporated had outstanding 505,980,424 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 October 15, 2009, 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.
Page
ii
Financial Statements
1
5
8
12
13
16
17
22
23
34
35
43
50
51
53
54
55
56
59
61
Management’s Discussion and Analysis of Financial Condition and Results of Operations
62
67
77
79
80
Qualitative and Quantitative Disclosures About Market Risk
80
Controls and Procedures
82
Legal Proceedings
83
Risk Factors
83
Unregistered Sales of Equity Securities and Use of Proceeds
84
Other Information
84
Exhibits
88
89 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 6. 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 law, policies and regulation, including market structures and rules, and reliability standards, • any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, • changes in federal and/or state environmental requirements 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, • availability of capital and credit at reasonable pricing terms and our ability to meet cash needs, • any inability to realize anticipated tax benefits or retain tax credits, • changes 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 investment performance of our decommissioning and defined benefit plan trust funds and changes in discount rates and funding requirements, and • changes in technology and/or increased customer conservation. Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors. 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. While we may elect to
update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws. 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
PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For The Three Months
For the Nine Months
2009
2008
2009
2008 OPERATING REVENUES
$
3,041
$
3,718
$
9,523
$
10,060 OPERATING EXPENSES Energy Costs
1,241
1,899
4,376
5,552 Operation and Maintenance
622
609
1,925
1,856 Depreciation and Amortization
224
214
634
597 Taxes Other Than Income Taxes
30
31
100
101 Total Operating Expenses
2,117
2,753
7,035
8,106 OPERATING INCOME
924
965
2,488
1,954 Income from Equity Method Investments
10
8
29
27 Impairment on Equity Method Investments
(4
)
(1
)
(12
)
(1
) Other Income
43
95
205
285 Other Deductions
(19
)
(43
)
(118
)
(156
) Other-Than-Temporary Impairments
—
(65
)
(61
)
(135
) Interest Expense
(129
)
(149
)
(407
)
(448
) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
825
810
2,124
1,526 Income Tax Expense
(337
)
(334
)
(881
)
(780
) INCOME FROM CONTINUING OPERATIONS
488
476
1,243
746 Income from Discontinued Operations, net of tax expense of $160 and $174 for the three and nine months ended 2008
—
180
—
208 NET INCOME
$
488
$
656
$
1,243
$
954 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC
505,982
507,724
505,986
508,233 DILUTED
507,242
508,326
506,957
508,890 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS
$
0.96
$
0.94
$
2.45
$
1.47 NET INCOME
$
0.96
$
1.29
$
2.45
$
1.88 DILUTED INCOME FROM CONTINUING OPERATIONS
$
0.96
$
0.94
$
2.45
$
1.47 NET INCOME
$
0.96
$
1.29
$
2.45
$
1.88 DIVIDENDS PAID PER SHARE OF COMMON STOCK
$
0.3325
$
0.3225
$
0.9975
$
0.9675 See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Ended September 30,
Ended September 30,
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
September 30,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
130
$
321 Accounts Receivable, net of allowances of $74 and $66 in 2009 and 2008, respectively
1,242
1,398 Unbilled Revenues
272
454 Fuel
942
938 Materials and Supplies
360
317 Prepayments
318
150 Restricted Funds
10
118 Derivative Contracts
217
237 Other
50
66 Total Current Assets
3,541
3,999 PROPERTY, PLANT AND EQUIPMENT
21,920
20,818 Less: Accumulated Depreciation and Amortization
(6,777
)
(6,385
) Net Property, Plant and Equipment
15,143
14,433 NONCURRENT ASSETS Regulatory Assets
5,806
6,352 Long-Term Investments
2,164
2,695 Nuclear Decommissioning Trust (NDT) Funds
1,177
970 Other Special Funds
145
133 Goodwill
16
16 Other Intangibles
110
53 Derivative Contracts
125
160 Other
207
238 Total Noncurrent Assets
9,750
10,617 TOTAL ASSETS
$
28,434
$
29,049 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
September 30,
December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
648
$
1,033 Commercial Paper and Loans
243
19 Accounts Payable
911
1,227 Derivative Contracts
232
356 Accrued Interest
146
99 Accrued Taxes
167
8 Clean Energy Program
163
142 Obligation to Return Cash Collateral
93
102 Other
390
424 Total Current Liabilities
2,993
3,410 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
4,090
3,865 Regulatory Liabilities
472
355 Asset Retirement Obligations
605
576 Other Postretirement Benefit (OPEB) Costs
972
975 Accrued Pension Costs
899
1,196 Clean Energy Program
434
532 Environmental Costs
715
743 Derivative Contracts
60
164 Long-Term Accrued Taxes
717
1,241 Other
136
125 Total Noncurrent Liabilities
9,100
9,772 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6)
CAPITALIZATION Long-Term Debt
6,326
6,621 Securitization Debt
1,201
1,342 Project Level, Non-Recourse Debt
39
42 Total Long-Term Debt
7,566
8,005 SUBSIDIARY’S PREFERRED STOCK WITHOUT MANDATORY REDEMPTION
80
80 STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued, 2009 and 2008—533,556,660 shares
4,780
4,756 Treasury Stock, at cost, 2009—27,575,156 shares;
(587
)
(581
) Retained Earnings
4,523
3,773 Accumulated Other Comprehensive Loss
(31
)
(177
) Total Common Stockholders’ Equity
8,685
7,771 Noncontrolling Interest - Equity Investments
10
11 Total Capitalization
16,341
15,867 TOTAL LIABILITIES AND CAPITALIZATION
$
28,434
$
29,049 See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
LONG-TERM DEBT
2008—27,538,762 shares
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For the Nine Months
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
1,243
$
954 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposal of Discontinued Operations
—
(374
) Depreciation and Amortization
634
599 Amortization of Nuclear Fuel
88
75 Provision for Deferred Income Taxes (Other than Leases) and ITC
209
1 Non-Cash Employee Benefit Plan Costs
260
126 Lease Transaction Reserves, net of tax
—
490 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
(542
)
20 Gain on Sale of Investments
(137
)
(1
) Undistributed Earnings from Affiliates
(19
)
(32
) Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives
(125
)
(77
) Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
55
(21
) Over (Under) Recovery of Societal Benefits Charge (SBC)
40
(42
) Cost of Removal
(38
)
(33
) Net Realized (Gains) Losses and (Income) Expense from NDT Funds
(25
)
22 Net Change in Certain Current Assets and Liabilities
252
(2
) Employee Benefit Plan Funding and Related Payments
(426
)
(122
) Other
(128
)
9 Net Cash Provided By Operating Activities
1,341
1,592 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(1,232
)
(1,237
) Proceeds from Sale of Discontinued Operations
—
772 Proceeds from the Sale of Capital Leases and Investments
729
37 Proceeds from NDT Funds Sales
1,631
1,839 Investment in NDT Funds
(1,653
)
(1,864
) Restricted Funds
113
(32
) NDT Funds Interest and Dividends
30
37 Increase in Solar Loan Investments
(18
)
— Investment in Joint Ventures and Partnerships
(11
)
— Other
(8
)
(11
) Net Cash Used In Investing Activities
(419
)
(459
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans
224
116 Issuance of Long-Term Debt
209
700 Purchase of Common Treasury Stock
—
(92
) Redemptions of Long-Term Debt
(584
)
(1,263
) Repayment of Non-Recourse Debt
(284
)
(38
) Redemption of Securitization Debt
(133
)
(127
) Premium Paid on Debt Exchange
(36
)
— Net Premium Paid on Early Extinguishment of Debt
—
(80
) Cash Dividends Paid on Common Stock
(505
)
(492
) Other
(4
)
(8
) Net Cash Used In Financing Activities
(1,113
)
(1,284
) Net Decrease in Cash and Cash Equivalents
(191
)
(151
) Cash and Cash Equivalents at Beginning of Period
321
380 Cash and Cash Equivalents at End of Period
$
130
$
229 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
1,060
$
865 Interest Paid, Net of Amounts Capitalized
$
344
$
375 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended September 30,
PSEG POWER LLC
For The Three Months
For the Nine Months
2009
2008
2009
2008 OPERATING REVENUES
$
1,422
$
1,833
$
5,097
$
5,831 OPERATING EXPENSES Energy Costs
526
904
2,551
3,360 Operation and Maintenance
255
282
784
796 Depreciation and Amortization
44
42
139
121 Total Operating Expenses
825
1,228
3,474
4,277 OPERATING INCOME
597
605
1,623
1,554 Other Income
40
88
196
267 Other Deductions
(17
)
(39
)
(111
)
(147
) Other-Than-Temporary Impairments
—
(65
)
(60
)
(135
) Interest Expense
(37
)
(42
)
(119
)
(125
) INCOME BEFORE INCOME TAXES
583
547
1,529
1,414 Income Tax Expense
(236
)
(219
)
(607
)
(571
) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
$
347
$
328
$
922
$
843 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Ended September 30,
Ended September 30,
PSEG POWER LLC
September 30,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
17
$
20 Accounts Receivable
379
472 Accounts Receivable—Affiliated Companies, net
740
732 Fuel
942
938 Materials and Supplies
260
233 Derivative Contracts
188
225 Restricted Funds
6
21 Prepayments
56
53 Other
2
11 Total Current Assets
2,590
2,705 PROPERTY, PLANT AND EQUIPMENT
7,940
7,441 Less: Accumulated Depreciation and Amortization
(2,144
)
(1,960
) Net Property, Plant and Equipment
5,796
5,481 NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Funds
1,177
970 Goodwill
16
16 Other Intangibles
101
43 Other Special Funds
29
27 Derivative Contracts
117
143 Other
84
74 Total Noncurrent Assets
1,524
1,273 TOTAL ASSETS
$
9,910
$
9,459 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
—
$
250 Accounts Payable
475
752 Short-Term Loan from Affiliate
65
3 Derivative Contracts
224
338 Accrued Interest
80
35 Other
163
155 Total Current Liabilities
1,007
1,533 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
587
335 Asset Retirement Obligations
354
334 Other Postretirement Benefit (OPEB) Costs
126
118 Derivative Contracts
32
111 Accrued Pension Costs
284
374 Environmental Costs
52
54 Long-Term Accrued Taxes
5
16 Other
67
47 Total Noncurrent Liabilities
1,507
1,389
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) Total Long-Term Debt
3,166
2,653 MEMBER’S EQUITY Contributed Capital
2,000
2,000 Basis Adjustment
(986
)
(986
) Retained Earnings
3,197
2,988 Accumulated Other Comprehensive Income (Loss)
19
(118
) Total Member’s Equity
4,230
3,884 TOTAL LIABILITIES AND MEMBER’S EQUITY
$
9,910
$
9,459 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 6
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
LONG-TERM DEBT
PSEG POWER LLC
For the Nine Months
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
922
$
843 Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization
139
121 Amortization of Nuclear Fuel
88
75 Interest Accretion on Asset Retirement Obligations
20
19 Provision for Deferred Income Taxes and ITC
105
69 Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives
(126
)
(45
) Non-Cash Employee Benefit Plan Costs
58
18 Net Realized (Gains) Losses and (Income) Expense from NDT Funds
(25
)
22 Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies
(31
)
(287
) Margin Deposit Asset
(9
)
146 Margin Deposit Liability
72
18 Accounts Receivable
312
45 Accounts Payable
(229
)
(118
) Accounts Receivable/Payable-Affiliated Companies, net
258
209 Accrued Interest Payable
45
47 Other Current Assets and Liabilities
(43
)
5 Employee Benefit Plan Funding and Related Payments
(112
)
(20
) Other
(25
)
42 Net Cash Provided By Operating Activities
1,419
1,209 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(632
)
(677
) Proceeds from NDT Funds Sales
1,631
1,839 NDT Funds Interest and Dividends
30
37 Investment in NDT Funds
(1,653
)
(1,864
) Restricted Funds
15
22 Other
(8
)
(10
) Net Cash Used In Investing Activities
(617
)
(653
) CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Recourse Long-Term Debt
209
— Cash Dividend Paid
(725
)
(475
) Redemption of Long-term Debt
(250
)
— Short-Term Loan—Affiliated Company, net
62
(70
) Accounts Receivable due from Affiliate Related to Debt Exchange
(101
)
— Net Cash Used In Financing Activities
(805
)
(545
) Net Increase (Decrease) in Cash and Cash Equivalents
(3
)
11 Cash and Cash Equivalents at Beginning of Period
20
11 Cash and Cash Equivalents at End of Period
$
17
$
22 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
464
$
458 Interest Paid, Net of Amounts Capitalized
$
87
$
84 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended September 30,
Operating Activities:
[THIS PAGE INTENTIONALLY LEFT BLANK]
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For the Three Months
For the Nine Months
2009
2008
2009
2008 OPERATING REVENUES
$
1,943
$
2,274
$
6,321
$
6,750 OPERATING EXPENSES Energy Costs
1,167
1,521
4,005
4,527 Operation and Maintenance
351
313
1,090
993 Depreciation and Amortization
169
161
462
443 Taxes Other Than Income Taxes
30
31
100
101 Total Operating Expenses
1,717
2,026
5,657
6,064 OPERATING INCOME
226
248
664
686 Other Income
2
2
7
9 Other Deductions
—
(2
)
(2
)
(3
) Interest Expense
(77
)
(82
)
(236
)
(244
) INCOME BEFORE INCOME TAXES
151
166
433
448 Income Tax Expense
(63
)
(68
)
(177
)
(161
) NET INCOME
88
98
256
287 Preferred Stock Dividends
(1
)
(1
)
(3
)
(3
) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
$
87
$
97
$
253
$
284 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 8
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Ended September 30,
Ended September 30,
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
September 30,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
27
$
91 Accounts Receivable, net of allowances of $73 in 2009 and $65 in 2008, respectively
839
909 Unbilled Revenues
272
454 Materials and Supplies
70
61 Prepayments
227
45 Restricted Funds
4
1 Derivative Contracts
1
— Deferred Income Taxes
45
52 Total Current Assets
1,485
1,613 PROPERTY, PLANT AND EQUIPMENT
12,824
12,258 Less: Accumulated Depreciation and Amortization
(4,297
)
(4,122
) Net Property, Plant and Equipment
8,527
8,136 NONCURRENT ASSETS Regulatory Assets
5,806
6,352 Long-Term Investments
179
158 Other Special Funds
50
46 Other
97
101 Total Noncurrent Assets
6,132
6,657 TOTAL ASSETS
$
16,144
$
16,406 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 9
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
September 30,
December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
594
$
248 Commercial Paper and Loans
73
19 Accounts Payable
330
336 Accounts Payable—Affiliated Companies, net
283
763 Accrued Interest
59
58 Accrued Taxes
3
3 Clean Energy Program
163
142 Derivative Contracts
8
14 Obligation to Return Cash Collateral
93
102 Other
190
227 Total Current Liabilities
1,796
1,912 NONCURRENT LIABILITIES Deferred Income Taxes and ITC
2,628
2,533 Other Postretirement Benefit (OPEB) Costs
799
813 Accrued Pension Costs
459
634 Regulatory Liabilities
472
355 Clean Energy Program
434
532 Environmental Costs
663
689 Asset Retirement Obligations
249
240 Derivative Contracts
24
53 Long-Term Accrued Taxes
94
82 Other
28
31 Total Noncurrent Liabilities
5,850
5,962 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
3,065
3,463 Securitization Debt
1,201
1,342 Total Long-Term Debt
4,266
4,805 Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized;
80
80 STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized;
892
892 Contributed Capital
420
170 Basis Adjustment
986
986 Retained Earnings
1,850
1,597 Accumulated Other Comprehensive Income
4
2 Total Stockholder’s Equity
4,152
3,647 Total Capitalization
8,498
8,532 TOTAL LIABILITIES AND CAPITALIZATION
$
16,144
$
16,406 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 10
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
issued and outstanding, 2009 and 2008—795,234 shares
issued and outstanding, 2009 and 2008—132,450,344 shares
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For The Nine Months
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
256
$
287 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
462
443 Provision for Deferred Income Taxes and ITC
99
33 Non-Cash Employee Benefit Plan Costs
177
97 Non-Cash Interest Expense
11
11 (Under) Over Recovery of Electric Energy Costs (BGS and NTC)
(9
)
32 Over (Under) Under Recovery of Gas Costs
64
(53
) Over (Under) Recovery of SBC
40
(42
) Other Non-Cash Charges
(2
)
(3
) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues
253
198 Materials and Supplies
(9
)
(12
) Prepayments
(182
)
(157
) Accrued Taxes
—
(26
) Accounts Payable
(6
)
40 Accounts Receivable/Payable-Affiliated Companies, net
(334
)
(264
) Obligation to Return Cash Collateral
(9
)
102 Other Current Assets and Liabilities
(50
)
(16
) Cost of Removal
(38
)
(33
) Employee Benefit Plan Funding and Related Payments
(270
)
(92
) Other
(31
)
— Net Cash Provided By Operating Activities
422
545 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(580
)
(534
) Proceeds from the Sale of Property, Plant and Equipment
2
1 Restricted Funds
2
(1
) Increase in Solar Loan Investment
(18
)
— Net Cash Used In Investing Activities
(594
)
(534
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt
54
116 Issuance of Long-Term Debt
—
700 Redemption of Long-Term Debt
(60
)
(651
) Redemption of Securitization Debt
(133
)
(127
) Contributed Capital
250
— Deferred Issuance Costs
—
(4
) Premium Paid on Early Retirement of Debt
—
(32
) Preferred Stock Dividends
(3
)
(3
) Net Cash Provided By (Used In) Financing Activities
108
(1
) Net (Decrease) Increase In Cash and Cash Equivalents
(64
)
10 Cash and Cash Equivalents at Beginning of Period
91
32 Cash and Cash Equivalents at End of Period
$
27
$
42 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
47
$
109 Interest Paid, Net of Amounts Capitalized
$
223
$
235 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended September 30,
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 relating to any individual company is filed by such company on its own behalf. Power and PSE&G
each is only responsible for information about itself and its subsidiaries. Note 1. Organization and Basis of Presentation Organization PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s four principal direct wholly owned subsidiaries are:
•
Power—which 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 functions through three principal direct wholly owned
subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate. • PSE&G—which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity 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 FERC. PSE&G is also investing
in the development of solar generation projects and energy efficiency programs within its service territory. • PSEG Energy Holdings L.L.C. (Energy Holdings)—which owns and operates primarily domestic projects engaged in the generation of energy and has invested in energy-related leveraged leases through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject
to regulation by FERC and the states in which they operate. Energy Holdings is also investing in solar generation projects and exploring opportunities for other investments in renewable generation. • PSEG Services Corporation (Services)—which provides management and administrative and general services to PSEG and its subsidiaries. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to 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 Report on Form 10-K for the year ended December 31, 2008 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2009 and June 30, 2009. 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, 2008. 12
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Reclassifications Certain reclassifications were made to the prior period financial statements in accordance with new accounting guidance adopted in 2009. Minority interests of $11 million were reclassified from Other Noncurrent Liabilities to Noncontrolling Interests in PSEG’s Condensed Consolidated Balance
Sheet as of December 31, 2008. In addition, other-than-temporary impairments related to Power’s credit losses on available-for-sale debt securities in its Nuclear Decommissioning Trust (NDT) Funds were reclassified from Other Deductions to a separate line caption in the Condensed Consolidated Statement of Operations of
PSEG and Power, for the three and nine months ended September 30, 2008. Certain reclassifications have also been made to the prior period financial statements to conform to the current presentation. Income from Equity Method Investments, as well as any impairments or gains/losses on the sale of equity method investments which were reflected in Operating Revenues and Operating Expenses prior to the fourth quarter of 2008, have been reclassified to below Operating Income in the
Consolidated Statements of Operations of PSEG for the three and nine months ended September 30, 2008 since these equity method investments are no longer an integral part of the business. Note 2. Recent Accounting Standards New Standards Adopted during 2009 During 2009, we have adopted new accounting standards relating to
•
Noncontrolling Interests in Consolidated Financial Statements, • Disclosures about Derivative Instruments and Hedging Activities, • Subsequent Events, • Recognition and Presentation of Other-Than-Temporary Impairments, • Interim Disclosures about Fair Value of Financial Instruments, and • the Financial Accounting Standards Board (FASB) Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (GAAP). The new standards adopted did not have a material impact on our financial statements. The following is a summary of the requirements and impacts of the new guidance: Noncontrolling Interests in Consolidated Financial Statements
•
changes the financial reporting relationship between a parent and noncontrolling interests, • requires all entities to report noncontrolling interests in subsidiaries as a separate component of equity in the consolidated financial statements, • requires net income attributable to the noncontrolling interests to be shown on the face of the income statement in addition to net income attributable to the controlling interest, and • applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. 13
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS We revised the balance sheet and income statement presentations as required by the standard. The income statement impact was immaterial. Disclosures about Derivative Instruments and Hedging Activities
•
requires an entity to disclose an understanding of
how and why it uses derivatives, ¡ how derivatives and related hedged items are accounted for, and ¡ the overall impact of derivatives on an entity’s financial statements. The required disclosures are included in Note 8. Financial Risk Management Activities. Subsequent Events
•
establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and • requires the disclosure of the date through which subsequent events have been evaluated and whether that date is the date on which the financial statements were issued or the date on which the financial statements were available to be issued. We evaluated any subsequent events through October 30, 2009, which is the date the financial statements were issued. See Note 17. Subsequent Events. Recognition and Presentation of Other-Than-Temporary Impairments
•
revises recognition guidance in determining whether a debt security is other-than-temporarily impaired. A debt security is considered other-than-temporarily impaired in either of the following circumstances if the fair value is less than the amortized cost
an entity has an intent to sell the security, or it is more-likely-than-not that an entity will be required to sell the security prior to the recovery of its amortized cost basis, or ¡ an entity does not expect to recover the entire amortized cost basis of the security.
•
provides further guidance to determine the amount of impairment to be recorded in earnings (credit-related loss) and/or Accumulated Other Comprehensive Income (Loss) (non-credit related loss).
This standard was adopted April 1, 2009 and we recorded a cumulative-effect adjustment to reclassify $12 million of non-credit losses, net-of-tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss). The expanded disclosures required by the standard are included in Note
4. Available-for-Sale Securities. Interim Disclosures about Fair Value of Financial Instruments
requires a publicly traded company to disclose the following information, in the notes to the financial statements:
fair value of its financial instruments in interim and annual reporting periods, together with the related carrying amounts, ¡ methods and significant assumptions used to estimate the fair value, and ¡ changes in methods and significant assumptions, if any. The required disclosures are included in Note 9. Fair Value Measurements. 14
(UNAUDITED)
¡
¡
•
¡
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles
•
issued as the single source of authoritative non-governmental GAAP other than the SEC rules and regulations, and • does not change current GAAP, but is intended to simplify user access by providing all the authoritative GAAP literature related to a particular topic in one place. We eliminated specific accounting references in our SEC filings and other documents and replaced them with more general topical references. New Accounting Standards issued but not yet adopted Measuring Liabilities at Fair Value
•
issued by the FASB in August 2009, • provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value of such liability using one or more of the techniques prescribed by this standard, and
•
re-affirms the practice of measuring fair value using quoted market prices when a liability is traded as an asset.
We will adopt this standard effective for 2009 year-end reporting and do not anticipate a material impact on our financial statements. Investments in Certain Entities That Calculate Net Asset Value Per Share
issued by the FASB in September 2009, • provides guidance on measuring fair value of certain alternative investments, and • permits the use of an investment’s net asset value to estimate its fair value, as a practical expedient, under certain circumstances. We will adopt this standard for alternative investments, which are mainly included within our pension asset portfolio, effective for 2009 year-end reporting. We are currently assessing the impact of this standard on our financial statements. Employers’ Disclosures about Postretirement Benefit Plan Assets This accounting standard requires additional disclosures about the fair value of plan assets of a defined benefit pension or other postretirement plan, including
•
how investment allocation decisions are made by management, • major categories of plan assets, • significant concentrations of risk within plan assets, and • inputs and valuation techniques used to measure the fair value of plan assets and effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period. We will adopt this standard effective for 2009 year-end reporting and do not anticipate that it will have a material impact on our financial statements. 15
(UNAUDITED)
•
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Consolidation of Variable Interest Entities (VIEs) New accounting guidance has been issued to amend the requirements for consolidation of VIEs which
•
removes the exception of applying consolidation guidance to qualifying special-purpose entities, • requires ongoing assessment of our involvement in the activities of the VIEs, and • amends the criteria in determination of a primary beneficiary, such that a primary beneficiary would be an enterprise with the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE and the obligation to absorb losses or the right to receive
benefits of the VIE that could potentially be significant to the VIE. We will adopt this guidance effective January 1, 2010. We are currently evaluating the impact of this guidance on our financial statements. Note 3. Discontinued Operations and Dispositions Discontinued Operations Bioenergie In November 2008, Energy Holdings sold its 85% ownership interest in Bioenergie for $40 million. The sale resulted in an after-tax loss of $15 million. Net cash proceeds, after realization of tax benefits, were approximately $70 million. Bioenergie’s operating results for the quarter and nine months ended September 30, 2008, which were reclassified to Discontinued Operations, are summarized below:
Three Months Ended
Nine Months Ended
Millions Operating Revenues
$
13
$
35 Loss Before Income Taxes
$
(29
)
$
(28
) Net Loss
$
(8
)
$
(9
) SAESA Group In July 2008, Energy Holdings sold its investment in the SAESA Group for a total of $1.3 billion, including the assumption of $413 million of the consolidated debt of the group. The sale resulted in an after-tax gain of $187 million. Net cash proceeds, after Chilean and U.S. taxes of $269
million, were $612 million. SAESA Group’s operating results for the quarter and nine months ended September 30, 2008, which were reclassified to Discontinued Operations, are summarized below:
Three Months Ended
Nine Months Ended
Millions Operating Revenues
$
38
$
379 Income (Loss) Before Income Taxes
$
(5
)
$
36 Net Income
$
1
$
30 16
(UNAUDITED)
September 30,
2008
September 30,
2008
September 30,
2008
September 30,
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Dispositions GWF Energy LLC (GWF Energy) In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it will sell, in two separate transactions, its 60% ownership interest in GWF Energy, an equity method investment, for a total purchase price of $70 million. As a result, Energy Holdings recorded an after-
tax impairment charge of $3 million. Energy Holdings completed the first stage of the sale in June 2009, selling a 10.1% interest in GWF Energy for approximately $7 million. The sale of Energy Holdings’ remaining 49.9% interest is subject to certain conditions, including the approval of a power purchase agreement by the
California Public Utilities Commission and FERC’s approval of the sale. PPN Power Generating Company Limited (PPN) In May 2009, Energy Holdings sold its 20% ownership interest in PPN, which owns and operates a 330 MW generation facility in India for approximately book value. Leveraged Leases During 2009, Energy Holdings sold its interest in 12 leveraged leases with a total book value of approximately $551 million, including ten international leases for which the IRS has disallowed deductions taken in prior years. Total proceeds for the sales were approximately $679 million and
resulted in after-tax gains of $52 million. Proceeds from these transactions are being used to reduce the tax exposure related to these lease investments. For additional information see Note 6. Commitments and Contingent Liabilities. Other In May 2009, Energy Holdings sold its 6.5% interest in the Midland Cogeneration Venture LP (MCV) for an after-tax gain of $2 million. Note 4. Available-for-Sale Securities NDT Funds In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operations. As a general practice, each nuclear owner places funds in independent
external trust accounts it maintains to provide for decommissioning. Power maintains the external master nuclear decommissioning trust which contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. In the most recent study of the
total cost of decommissioning, Power’s share related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of September 30, 2009 was approximately $315 million and is included in the
Asset Retirement Obligation (ARO). The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power. 17
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power classifies investments in the NDT Funds as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Funds:
As of September 30, 2009
Cost
Gross
Gross
Estimated
Millions Equity Securities
$
458
$
166
$
(2
)
$
622 Debt Securities Government Obligations
293
6
(1
)
298 Other Debt Securities
210
12
(3
)
219 Total Debt Securities
503
18
(4
)
517 Other Securities
39
—
(1
)
38 Total Available-for-Sale Securities
$
1,000
$
184
$
(7
)
$
1,177
As of December 31, 2008
Cost
Gross
Gross
Estimated
Millions Equity Securities
$
386
$
32
$
(5
)
$
413 Debt Securities Government Obligations
192
3
—
195 Other Debt Securities
284
6
—
290 Total Debt Securities
476
9
—
485 Other Securities
72
1
(1
)
72 Total Available-for-Sale Securities
$
934
$
42
$
(6
)
$
970 18
(UNAUDITED)
Unrealized
Gains
Unrealized
Losses
Fair Value
Unrealized
Gains
Unrealized
Losses
Fair Value
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table shows the value of securities in the NDT Funds that have been in an unrealized loss position for less than 12 months:
As of September 30, 2009
As of December 31, 2008
Fair
Gross
Fair
Gross Equity Securities (A)
$
34
$
(2
)
$
85
$
(5
) Debt Securities Government Obligations (B)
42
(1
)
—
— Other Debt Securities (C)
36
(3
)
—
— Total Debt Securities
78
(4
)
—
— Other Securities
1
(1
)
—
(1
) Total Available-for-Sale Securities
$
113
$
(7
)
$
85
$
(6
)
*
There were no gross unrealized losses as of each of September 30, 2009 and December 31, 2008 for 12 months or longer. (A) Equity Securities—Investments in marketable equity securities within the NDT fund are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over several hundred companies with limited impairment durations and a
severity that is generally less than ten percent of cost. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2009. (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in US Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the US government or an agency of the US government,
it is not expected that these securities will settle for less that their amortized cost basis, assuming Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of September 30, 2009. (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily with investment grade securities. It is not expected that these securities would settle at less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not
required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of September 30, 2009. The proceeds from the sales of and the net realized gains on securities in the NDT Funds were:
Three Months
Three Months
Nine Months
Nine Months
Millions Proceeds from Sales
$
156
$
582
$
1,631
$
1,839 Net Realized Gains: Gross Realized Gains
$
29
$
74
$
156
$
221 Gross Realized Losses
(14
)
(38
)
(125
)
(141
) Net Realized Gains
$
15
$
36
$
31
$
80 19
(UNAUDITED)
Less Than 12 Months*
Less Than 12 Months*
Millions
Value
Unrealized
Losses
Value
Unrealized
Losses
Ended
September 30, 2009
Ended
September 30, 2008
Ended
September 30, 2009
Ended
September 30, 2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in Power’s Consolidated Statement of Operations. Net unrealized gains of $88 million (after-tax) were recognized in Accumulated Other Comprehensive Income in Power’s Condensed
Consolidated Balance Sheet as of September 30, 2009. The available-for-sale debt securities held as of September 30, 2009 had the following maturities:
•
$5 million less than one year, • $83 million after one through five years, • $126 million after five through 10 years, $51 million after 10 through 15 years, and • $12 million after 15 through 20 years, and $240 million over 20 years. The cost of these securities was determined on the basis of specific identification. Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit
recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed
income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Other Comprehensive Income (OCI).
In 2009, other-than-temporary impairments of $60 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is recognized in income. The assessment of fair
market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities. Rabbi Trusts PSEG maintains certain unfunded nonqualified benefit plans; assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain key employees. PSEG classifies investments in the Rabbi Trusts as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts.
As of September 30, 2009
Cost
Gross
Gross
Estimated
Millions Equity Securities
$
10
$
3
$
—
$
13 Debt Securities
101
17
—
118 Other Securities
14
—
—
14 Total PSEG Available-for-Sale Securities
$
125
$
20
$
—
$
145 20
(UNAUDITED)
Unrealized
Gains
Unrealized
Losses
Fair Value
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2008
Cost
Gross
Gross
Estimated
Millions Equity Securities
$
11
$
—
$
(2
)
$
9 Debt Securities
102
9
(1
)
110 Other Securities
14
—
—
14 Total PSEG Available-for-Sale Securities
$
127
$
9
$
(3
)
$
133 The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair
market value below cost are recorded as a charge to earnings. In the first nine months of 2009, other-than-temporary impairments of $1 million were recognized on the equity investments of the Rabbi Trusts.
Three Months
Three Months
Nine Months
Nine Months
Millions Proceeds from Sales
$
—
$
—
$
2
$
23 Net Realized Gains (Losses): Gross Realized Gains
$
—
$
—
$
—
$
2 Gross Realized Losses
—
—
(1
)
— Net Realized Gains (Losses):
$
—
$
—
$
(1
)
$
2 The cost of these securities was determined on the basis of specific identification. The estimated fair value of the Rabbi Trusts related to PSEG, Power and PSE&G are detailed as follows:
As of
As of
Millions Power
$
29
$
27 PSE&G
50
46 Other
66
60 Total PSEG Available-for-Sale Securities
$
145
$
133 21
(UNAUDITED)
Unrealized
Gains
Unrealized
Losses
Fair Value
Ended
September 30, 2009
Ended
September 30, 2008
Ended
September 30, 2009
Ended
September 30, 2008
September 30,
2009
December 31,
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit 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
Pension Benefits
OPEB
2009
2008
2009
2008
2009
2008
2009
2008
Millions Components of Net Periodic Benefit Cost: Service Cost
$
19
$
19
$
3
$
4
$
57
$
58
$
9
$
11 Interest Cost
58
56
18
18
176
170
54
54 Expected Return on Plan Assets
(54
)
(72
)
(3
)
(4
)
(162
)
(217
)
(9
)
(11
) Amortization of Net Transition Obligation
—
—
7
7
—
—
21
21 Prior Service Cost
2
2
3
4
6
7
10
10 Actuarial Loss
29
4
—
—
85
10
(2
)
(1
) Net Periodic Benefit Cost
$
54
$
9
$
28
$
29
$
162
$
28
$
83
$
84 Effect of Regulatory Asset
—
—
5
4
—
—
15
14 Total Benefit Expense, Including Effect of Regulatory Asset
$
54
$
9
$
33
$
33
$
162
$
28
$
98
$
98 Pension and OPEB costs for PSEG, Power and PSE&G are detailed as follows:
Pension
OPEB
Pension
OPEB
2009
2008
2009
2008
2009
2008
2009
2008
Millions Power
$
16
$
2
$
3
$
4
$
49
$
8
$
9
$
10 PSE&G
30
4
29
28
90
12
87
85 Other
8
3
1
1
23
8
2
3 Total Benefit Costs
$
54
$
9
$
33
$
33
$
162
$
28
$
98
$
98 During the nine months ended September 30, 2009, PSEG contributed its planned contributions for the year 2009 of $364 million and $11 million into its pension and postretirement healthcare plans respectively. 22
(UNAUDITED)
Three Months
Ended
September 30,
Three Months
Ended
September 30,
Nine Months
Ended
September 30,
Nine Months
Ended
September 30,
Three Months
Ended
September 30,
Three Months
Ended
September 30,
Nine Months
Ended
September 30,
Nine Months
Ended
September 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 6. Commitments and Contingent Liabilities Guaranteed Obligations Power has unconditionally guaranteed payments by its subsidiaries in commodity-related transactions to support current exposure, interest and other costs on sums due and payable in the ordinary course of business. These 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. In order for Power to incur liability for the face value of the outstanding guarantees, its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of the related contracts would have to be “out-of-the-money” (if the
contracts are terminated, Power would owe money to the counterparties). The probability of this is highly unlikely due to offsetting positions within the portfolio. For this reason, the current risk that others have from us at any point in time is a more meaningful representation of the potential
liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. Changes in commodity prices can have a material impact on margin requirements under such contracts,
which are posted and received primarily in the form of letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on
market movement and in accordance with exchange rules. The face value of outstanding guarantees, current exposure and margin positions as of September 30, 2009 and December 31, 2008 are as follows:
As of September 30,
As of December 31,
Millions Face value of outstanding guarantees
$
1,981
$
1,856 Exposure under current guarantees
$
385
$
585 Letters of Credit Margin Posted
$
190
$
201 Letters of Credit Margin Received
$
185
$
250 Net Cash Received Counterparty Cash Margin Deposited
$
—
$
3 Counterparty Cash Margin Received
(150
)
(81
) Net Broker Balance Received
(65
)
(74
) Total Net Cash Received
$
(215
)
$
(152
) Power nets the fair value of cash collateral receivables and payables with the corresponding net energy contract balances. Of the net cash received, Power has included $223 million and $112 million in its corresponding net derivative contract positions as of September 30, 2009 and December 31,
2008 respectively. The remaining balance of net cash (received) deposited shown above is primarily included in Accounts Payable. 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 23
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS further performance assurance. As of September 30, 2009, if Power was to lose its investment grade rating, additional collateral of approximately $850 million could be required. As of September 30, 2009, there was $2.6 billion of available liquidity that could be used to post collateral under the PSEG and Power credit facilities. In addition to amounts in the table above, Power had posted $96 million and $101 million in letters of credit as of September 30, 2009 and December 31, 2008 respectively, to support various other contractual and environmental obligations. Environmental Matters 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). The EPA later expanded its study area to include the entire 17-mile tidal reach of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the river. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former Manufactured Gas Plant
(MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities. The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million.
73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed-upon formula. The PRP group is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former
MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim. In 2007, the EPA released a draft “Focused Feasibility Study” that proposes six options to address the contamination cleanup of the lower eight miles of the Passaic River, with estimated costs from $900 million to $2.3 billion. The work contemplated by the study is not subject to the cost sharing
agreement discussed above. A revised focused feasibility study is expected to be released in 2010. In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs,
including Power and PSE&G. NJDEP Litigation In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of
hazardous substances into the Passaic River. In February 2009, third-party complaints were filed against some 320 third-party defendants, including Power and PSE&G, claiming that each of the third-party defendants is responsible for its proportionate share of the clean-up costs for the hazardous
substances they allegedly discharged into the Passaic River. The third-party complaints seek statutory contribution and contribution under the New Jersey Spill Compensation and Control Act (Spill Act) to recover past and future removal costs and damages. Power and PSE&G believe they have
good and valid defenses to the allegations contained in the third-party complaints and will vigorously assert those defenses. 24
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Natural Resource Damage Claims In 2003, the NJDEP directed PSEG, PSE&G and 56 other 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 NJ Spill Act. The NJDEP alleged that hazardous
substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the
United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In November 2008, PSEG and a number of other PRPs agreed in an interim cooperative assessment agreement
to pay an aggregate of $1 million for past costs incurred by the Federal trustees, and certain costs the trustees will incur going forward, and to work with the trustees for a 12-month period to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That initial
12 month period ends in December, 2009 and it is presently uncertain whether that effort will continue into 2010. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect
to contamination in the Study Area. The notice letter requested that the PRPs fund an 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 that OCC
was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating
in and partially funding this study. 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, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be
material. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also 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 was PSE&G’s
former Camden Coke facility. During the second quarter of 2009, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $704 million and $804 million from June 30, 2009 through 2021. Since no amount within the range was considered to
be most likely, PSE&G reflected a liability of $704 million in its Condensed Consolidated Balance Sheet as of June 30, 2009. During the third quarter of 2009 PSE&G had $2 million of expenditures, reducing the liability to $702 million as of September 30, 2009. Of this amount, $39 million was
recorded in Other Current Liabilities and $663 million was reflected as Environmental Costs in Noncurrent Liabilities. As such, PSE&G has recorded a $702 million Regulatory Asset with respect to these costs. 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, 25
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 ranging
from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred. In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power’s generating stations. Under this agreement, Power was 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 (SO2), nitrogen oxide (NOx), particulate matter and mercury. As of December 2008, Power had installed selective catalytic reduction equipment and placed baghouses in service at Mercer at a total
cost of $381 million. The remaining projects necessary to implement the balance of this program are expected to be completed by 2010 at an estimated cost of $200 million to $250 million for Mercer and $700 million to $750 million for Hudson, of which $643 million has been spent on both
projects as of September 30, 2009. In January 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were made at the plant which are considered modifications (or major modifications)
causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA
alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict
the outcome of this matter. 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. In February 2008, the United States Court of Appeals for the
District of Columbia Circuit issued a decision rejecting the EPA’s mercury emissions program and requiring the EPA to develop standards for mercury and nickel emissions that adhere to the Maximum Available Control Technology (MACT) provisions of the Clean Air Act. Although the EPA
initially filed a petition with the U.S. Supreme Court to review the lower court’s decision, in February 2009, the EPA withdrew its petition with the U.S. Supreme Court and indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the
Court’s ruling. While certain industry litigants also petitioned the U.S. Supreme Court to review the lower court’s decision, in February 2009, the Supreme Court denied the petition. The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements, which
the EPA has agreed to finalize by November 2011, will require more stringent control than the cap-and-trade program struck down by the D.C. Circuit Court; however, the costs of compliance with mercury MACT standards will have to be compared with the existing state mercury-control
requirements, as described below. Pennsylvania In February 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal-fired electric generating units. These requirements were more stringent than the EPA’s Clean Air Mercury Rule (vacated by the court in February 2008) but not as stringent as would
be required by a MACT process. In January 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it is inconsistent with the Clean Air Act. The Commonwealth Court’s decision has been appealed to the Supreme
Court of Pennsylvania. If the Commonwealth Court’s decision were to be overturned and the above-mentioned requirements are upheld, the Keystone and Conemaugh generating stations would be positioned by 2010 to meet Phase I of the 26
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Pennsylvania mercury rule by benefiting from reductions realized from the installation of planned or completed controls for compliance with SO2 and NOx reductions. Total estimated costs for compliance for ongoing projects are between $150 million and $200 million with $137 million spent as
of September 30, 2009. Power will evaluate Phase II of the Pennsylvania mercury rule after a full evaluation of the Phase I reductions. If the Commonwealth Court’s ruling is sustained and the EPA undertakes a MACT process, it is uncertain whether the Keystone and Conemaugh generating
stations will be able to achieve the necessary reductions at these stations with currently planned capital projects. Connecticut Mercury emissions control standards were effective in July 2008 and require coal-fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. With the recently installed activated carbon injection and
baghouse at Bridgeport Unit 3, it has demonstrated that it complies with the mercury limits in these standards. New Jersey New Jersey regulations required coal-fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such
reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has or will achieve the required reductions with mercury-control technologies that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above. NOx Reduction New Jersey In April 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule will have a significant impact on Power’s generation fleet, as it imposes NOx
emissions limits that will likely require the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generation units (approximately 800 MW) by April 30, 2015. Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time for it to address the retirement of electric generation units. Power cannot predict the financial impact resulting from compliance with this
rulemaking. Connecticut Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities utilize Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. Power’s agreements with the State of Connecticut
authorizing the DERC’s expire on May 1, 2010. If not extended, Power could potentially be forced to utilize lower NOx-producing fuels, or install NOx emission controls in order to operate the units. Power cannot predict the financial impact of such costs, but such costs could be material and
could impact the continued viability of these units. New Jersey Industrial Site Recovery Act (ISRA) Potential environmental liabilities related to the alleged discharge of hazardous substances 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 has a $50 million liability as of September 30, 2009 and December 31, 2008 27
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS related to these obligations, which is included in Environmental Costs in 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 existing cooling water intake system. In February 2006, Power filed with the NJDEP a
renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the Federal Water Pollution Control Act’s (FWPCA) Section 316(b) and the Phase II 316(b) rules, which govern cooling water intake structures at large electric generating facilities. Under these rules, Power had historically 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. The Phase II Rule would also have been applicable to Bridgeport, and possibly, Sewaren and New Haven stations. In addition to the
Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson and Sewaren, and to the Connecticut Department of Environmental Protection for Bridgeport. In January 2007, the U.S. Court of Appeals for the Second Circuit issued a 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, Connecticut, and New York, the Utility Water Act
Group and several of its members, including Power. In its ruling, 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; and • instructed the EPA to reconsider the definition of “best technology available” without comparing the costs of the best performing technology to its benefits. On April 1, 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations. The
Supreme Court’s decision became effective on April 27, 2009, and the matter was sent back to the Second Circuit for further proceedings consistent with the Supreme Court’s opinion. On September 29, 2009, the Second Circuit issued an order remanding the matter to the EPA in light of the
Supreme Court’s opinion. The EPA will have to undertake a rulemaking which takes into account the Supreme Court’s opinion concerning the use of cost-benefit analysis, and the Second Circuit’s opinion with respect to significant portions of the Phase II rule which were remanded by the Second
Circuit but which were not considered by the Supreme Court. The Supreme Court’s ruling allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. However, the results of further proceedings on this matter could have a material impact on our ability to renew
permits at our larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to our existing intake structures and cooling systems. The costs of those upgrades to one or more of our once-through cooled
plants could be material and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem are
approximately $1 billion, of which Power’s share would be approximately $575 million. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. 28
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Stormwater In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated
pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has now determined that Hudson is no longer eligible to utilize this general permit and must apply for an individual NJPDES permit for stormwater
discharges. While the full extent of these requirements remains unclear, to the extent Power may be required to reduce or eliminate the exposure of coal to stormwater, or be required to construct technologies preventing the discharge of stormwater to surface water or groundwater, those costs
could be material. New Generation and Development Nuclear Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at Peach Bottom Units 2 and 3. Completion of these upgrades is expected to result in an increase of Power’s share of nominal capacity by 32 MW (14 MW at Unit 3 in 2011 and 18
MW at Unit 2 in 2012). Total expenditures through September 2009 are $18 million and are expected to continue through 2012. We anticipate expenditures in pursuit of additional output through an extended power up-rate of our co-owned Peach Bottom nuclear plants. The up-rate is expected to
be in service in 2015 for Unit 2 and 2016 for Unit 3. Our share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million. Connecticut Power has been selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas-fired peaking capacity. Final approval has been received and construction is expected to commence in June 2011. The project is expected to be in-service by June
2012. Power estimates the cost of these generating units to be $130 million to $140 million. Total capitalized expenditures through September 2009 are $13 million, which are included in Other Noncurrent Assets in the Condensed Consolidated Balance Sheets of PSEG and Power. PJM Interconnection L.L.C. (PJM) Power plans to construct 178 MW of gas-fired peaking capacity at the Kearny site. This capacity was bid into and has cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to
commence in the third quarter of 2011. The project is expected to be in-service by June 2012. Power estimates the cost of these generating units to be $160 million to $200 million. Total capitalized expenditures to date were $8 million which are included in Property, Plant and Equipment in
Power’s and PSEG’s Condensed Consolidated Balance Sheets. Solar Source Energy Holdings has developed a solar project in western New Jersey and has acquired two additional solar projects to be developed in Florida and Ohio, which together have a total capacity of approximately 29 MW. Completion of the additional projects is expected by the end of 2010 with a
total investment of approximately $100 million. Energy Holdings has issued guarantees of up to $95 million for payment of obligations related to the construction of these two projects. These guarantees will terminate upon successful completion of the projects. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, 29
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The
winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and 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 the sale of most of 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 also 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 2006 2007 2008 2009 36-Month Terms Ending May 2009 May 2010 May 2011 May 2012 (a) Load (MW) 2,882 2,758 2,840 2,840 $per kWh 0.10251 0.09888 0.11150 0.10372 (a) Prices set in the 2009 BGS auction became effective on June 1, 2009 when 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 PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 15. Related-Party Transactions. Minimum Fuel Purchase Requirements Power has various long-term fuel purchase commitments for coal and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas. Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its
sales contracts. Power’s strategy is to maintain certain levels of uranium concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below include estimated quantities to be purchased that are in excess of contractual minimum
quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2011 and a portion for 2012 and 2013 at Salem, Hope Creek and Peach Bottom. As of September 30, 2009, the total minimum purchase requirements included in these commitments are as follows: 30
(UNAUDITED)
the 2006 BGS auction agreements expired.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Fuel Type
Commitments
Power’s Share
Millions Nuclear Fuel Uranium
$
772
$
487 Enrichment
$
445
$
252 Fabrication
$
261
$
171 Natural Gas
$
1,000
$
1,000 Coal/Oil
$
811
$
811 Included in the $811 million commitment for coal and oil above is $433 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. Through September 2009, Power has cancelled one million tons of coal and twelve freight shipments related to
that coal at a total cost of approximately $17 million. Power has entered into gas supply option agreements for the anticipated fuel requirements at the Texas generation facilities to satisfy obligations under the facilities forward energy sales contracts. As of September 30, 2009, Power’s fuel purchase options totaled $19 million under those agreements,
which is not included in the above table. The Texas generation facilities also have a contract for low BTU content gas commencing in late 2009 with a term of 15 years and a minimum volume of approximately 13 MMbtu’s per year. The gas must meet an availability and quality specification. PSEG has the right to cancel delivery of
the gas at a minimal cost. Nuclear Fuel Disposal The Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund. Under the contracts, the US Department of
Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. Earlier this year, the Federal government announced that it would form a group to study and provide recommendations for a long-term resolution of the nuclear waste issue. Given the
uncertainty of the timing and nature of the recommendations, it is not clear when the government will begin taking possession of the spent nuclear fuel. On September 30, 2009, Power signed an agreement with the DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE’s delay in accepting spent nuclear fuel for permanent disposition. Under this
settlement, we will receive approximately $47 million for our spent fuel management costs incurred through December 2007. Payment was received in October 2009. A similar settlement agreement was reached related to Peach Bottom in 2004. The majority of this amount is related to the
recovery of the capitalized costs of building on-site storage and related improvements, therefore nearly all of this payment will result in a reduction of previously capitalized plant-related costs rather than an increase in earnings. Power has on-site storage facilities that are expected to satisfy its
storage needs through current licensed lives plus an additional twenty years of operation. Regulatory Proceedings Competition Act In April 2007, PSE&G and PSE&G Transition Funding LLC (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 stranded cost recovery provisions of the Competition Act,
seeking injunctive 31
(UNAUDITED)
through 2013
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional. In July 2007, the 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. In July 2007, PSE&G filed a motion to dismiss the amended Complaint, or, in the alternative, for summary
judgment. In October 2007, PSE&G’s and Transition Funding’s motion to dismiss the amended Complaint was granted. In November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division
affirmed the decision of the lower court dismissing the case. In May 2009 the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision. In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition, which remains pending. 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. That report, which addresses SBC, Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all material respects with applicable BPU Orders. It also 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 matter was referred to the Office of Administrative Law. The amount in dispute is $114 million, which if
required to be refunded to customers with interest through September 2009, would be $142 million. Hearings before an administrative law judge (ALJ) were held in July 2008. In January 2009, the ALJ issued a decision which upheld PSE&G’s central contention that the 2004 BPU Order approving the Phase I settlement resolved the issues being raised by the Staff and Advocate, and that these
issues should not be subject to re-litigation in respect of the first three years of the transition period. The ALJ’s decision stated that the BPU could elect to convene a separate proceeding to address the fourth and final year reconciliation of MTC recoveries. The amount in dispute with respect to
this Phase II period is approximately $50 million. The BPU requested supplemental briefs which were filed in September 2009 reiterating PSE&G’s position that the accounting approach followed was consistent with the BPU’s Restructuring Order. Reply briefs were filed in October 2009. New Jersey Clean Energy Program In the third quarter of 2008, the BPU approved funding requirements for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&G’s share of the $1.2 billion program
is $705 million. PSE&G has recorded a discounted liability of $597 million as of September 30, 2009. Of this amount, $163 million was recorded as a current liability and $434 million as a noncurrent liability. The 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. 32
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Leveraged Lease Investments The Internal Revenue Service (IRS) has issued reports with respect to its audits of PSEG’s federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial
understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS. PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, five
cases have been decided at the trial court level, three of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fourth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties.
One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer. The IRS has also issued letters to a number of taxpayers with these types of lease transactions containing settlement offers. While many bank lessors have agreed to settle on terms that are favorable to the IRS, PSEG has analyzed potential settlements with the IRS and to date has declined to
participate. In order to reduce the cash tax exposure related to these leases, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Energy Holdings has terminated ten of these leasing transactions in 2009 and one in
December 2008 and reduced the related cash tax exposure by $525 million. As of September 30, 2009 and December 31, 2008, PSEG’s total gross investment in such transactions was $490 million and $1 billion respectively. Cash Impact As of September 30, 2009, an aggregate of approximately $780 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing its
potential cash exposure to $460 million. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. As of September 30, 2009, penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest
and penalty exposure grow at the rate of $9 million per quarter during 2009. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $100 million to $130 million of tax would be due for tax positions
through September 30, 2009. PSEG currently anticipates that it may be required to pay between $120 million and $290 million in tax, interest and penalties for the tax years 1997-2000 during the first quarter of 2010 and subsequently commence litigation to recover these amounts. Further it is possible that an additional
payment of between $220 million and $510 million could be required in the first quarter of 2010 for tax years 2001-2003 followed by further litigation to recover those taxes. These amounts are in addition to tax deposits already made. Earnings Impact As a result of the changes in the timing of projected cash flows related to these leases, in the second quarter of 2008, PSEG recalculated its lease transactions and recorded an after-tax charge of $355 million. This charge was reflected as a reduction in Operating Revenues of $485 million with a
partially offsetting reduction in Income Tax Expense of $130 million. This represents PSEG’s view of most of the earnings impact related to these transactions, although a total loss, consistent with the broad settlement offer proposed by the IRS, would result in an additional earnings charge of
$100 million to $120 million. 33
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7. Changes in Capitalization Power and Energy Holdings In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Under this transaction, an aggregate principal amount of $368 million, or 74% of Energy Holdings’ Senior Notes, was
exchanged for total consideration from Power of $404 million. The $404 million was comprised of $303 million of newly issued 5.32% Senior Notes due September 2016 and cash payments of $101 million. Since the debt exchange was between two subsidiaries of the same parent company,
PSEG, the resulting premium of $36 million was deferred and will be amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on PSEG’s Condensed Consolidated Balance Sheet. As of September 30, 2009, Power had a receivable from Energy Holdings for the full consideration Power provided to Energy Holdings’ bondholders in this transaction. Energy Holdings had a payable to Power for the same amount. See Note 17. Subsequent Events for additional information. Energy Holdings has $127 million of 8.50% Senior Notes due 2011 still outstanding as of September 30, 2009. In addition to the debt exchange, the following capital transactions occurred in the first nine months of 2009: PSEG
•
paid $200 million of 4.66% Senior Notes at maturity in September.
Power
converted $44 million of 4.00% Pollution Control Bonds to variable rate demand bonds backed by letters of credit expiring in 2012, and • established a program for the issuance of up to $500 million of unsecured medium-term notes (MTNs) to retail investors in January. Under this program we
¡
issued $161 million of 6.5% MTNs due January 2014 (issued January, callable in one year), and ¡ issued $48 million of 6% MTNs due January 2013 (issued January, callable in one year).
•
paid cash dividends of $725 million to PSEG, and • paid $250 million of 3.75% Senior Notes at maturity in April. PSE&G
•
paid $44 million of 8.10% MTNs, Series A at maturity in May, • paid $16 million of 8.16% MTNs, Series A at maturity in May, • received a $250 million equity contribution from PSEG, • paid $128 million of Transition Funding’s securitization debt, and • paid $5 million of Transition Funding II’s securitization debt. Energy Holdings
•
redeemed $280 million of floating rate non-recourse project debt due in December 2009 associated with PSEG Texas,
34
(UNAUDITED)
•
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS • repurchased $10 million of its 8.5% Senior Notes due 2011, and • paid a total of $4 million of non-recourse project debt other than PSEG Texas. In October 2009, PSEG paid $49 million of 6.89% Senior Notes at maturity. In addition, PSE&G purchased $100 million (Series 2003 B-1 and 2003 B-2) of tax-exempt variable rate bonds of the Pollution Control Financing Authority of Salem County (Salem County Authority Bonds). These bonds
are serviced and secured by like principal amount of PSE&G’s pollution control Mortgage Bonds and were held by the broker/dealer or tendered by bondholders upon the mandatory tender in October 2009. These purchases were recorded as a reduction of PSE&G’s Long-Term Debt Due Within One
Year included in its Condensed Consolidated Balance Sheets. Note 8. Financial Risk Management Activities The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and,
when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative
instruments. Commodity Prices The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power and Energy Holdings use physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Contracts that do not qualify for hedge accounting are marked to market with changes in fair value recorded in the
income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. The financial
effect of using such modeling techniques is not material to PSEG’s or Power’s financial statements. Cash Flow Hedges Power and Energy Holdings use forward sale and purchase contracts, swaps, futures and firm transmission right contracts to hedge
forecasted energy sales from their generation stations and the related load obligations and • the price of fuel to meet their fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges. As of September 30, 2009 and December 31, 2008, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows: 35
(UNAUDITED)
•
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
As of September 30,
As of December 31,
Millions Power Fair Value of Cash Flow Hedges
$
372
$
331
* Impact on Accumulated Other Comprehensive Income (Loss) (after tax)
$
225
$
176 Energy Holdings Fair Value of Cash Flow Hedges
$
—
$
3 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)
$
2
$
2
*
Power’s fair value of cash flow hedges of $331 million at December 31, 2008 shown in the table above was corrected from $320 million disclosed in our 2008 Form 10-K.
The expiration date of the longest-dated cash flow hedge at Power is in 2011. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the 12 months ending September 30, 2010 and September 30, 2011 are $133 million and $76 million
respectively. Ineffectiveness associated with these hedges was $6 million at September 30, 2009. The expiration date of the longest-dated cash flow hedge for Energy Holdings is in 2009. Therefore, substantially all of the after-tax unrealized gains on its commodity derivatives are expected to be reclassified to earnings during 2009. There was no ineffectiveness associated with these hedges. Trading Derivatives In general, the main purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Power does engage in some trading of electricity and energy-related products where such
transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned
generation. Such trading activities represent approximately one percent of Power’s gross margin. Other Derivatives Power and Energy Holdings enter into other contracts that are derivatives, but do not qualify for cash flow hedge accounting. For Power, most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Prior to June 2009, some of the derivative contracts were also used in Power’s NDT Funds. For Energy Holdings, these are electricity forward and capacity sale contracts entered into to sell a portion of the Texas facilities’ capacity and gas purchase contracts to support the electricity forward sales contracts. 36
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of September 30, 2009 and December 31, 2008 was as follows:
As of September 30,
As of December 31,
Millions Net Fair Value of Other Derivatives Power
$
(16
)
$
67
* Energy Holdings
$
28
$
32
*
The net fair value of other derivatives related to energy contracts for Power of $67 million at December 31, 2008 in the table above was corrected from $(9) million disclosed in our 2008 Form 10-K.
Interest Rates PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed through the use of fixed and floating rate debt and interest rate derivatives. Fair Value Hedges In May and June 2009, we entered into three interest rate swaps to convert Power’s $250 million of 5.00% Senior Notes due April 2014 and $300 million of 5.50% Senior Notes due December 2015 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges.
The fair value changes of the interest rate swaps are fully offset by the fair value changes in the underlying debt. As of September 30, 2009, the fair value of the underlying hedges was $4 million. Cash Flow Hedges PSEG, PSE&G and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of September 30, 2009, there was no hedge
ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was less than $(1) million and $(7) million as of September 30, 2009 and December 31, 2008 respectively. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated
as cash flow hedges was $(5) million and $(6) million as of September 30, 2009 and December 31, 2008 respectively. 37
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Fair Values of Derivative Instruments The following are the fair values of derivative instruments in the Condensed Consolidated Balance Sheets: Balance Sheet
As of September 30, 2009
Power (A)
PSE&G
Energy
Consolidated
Cash
Flow
Hedges
Non
Hedges
Netting (B)
Total Power
Non
Hedges
Non
Hedges
Total
Energy-
Energy-
Energy-
Energy-
Millions Derivative Contracts Current Assets
$
469
$
559
$
(840
)
$
188
$
1
$
20
$
217 Noncurrent Assets
$
383
$
160
$
(426
)
$
117
$
—
$
8
$
125 Total Mark-to-Market Derivative Assets
$
852
$
719
$
(1,266
)
$
305
$
1
$
28
$
342 Derivative Contracts Current Liabilities
$
(100
)
$
(699
)
$
575
$
(224
)
$
(8
)
$
—
$
(232
) Noncurrent Liabilities
$
(39
)
$
(123
)
$
130
$
(32
)
$
(24
)
$
—
$
(60
) Total Mark-to-Market Derivative (Liabilities)
$
(139
)
$
(822
)
$
705
$
(256
)
$
(32
)
$
—
$
(292
) Total Net Mark-to-Market Derivative Assets (Liabilities)
$
713
$
(103
)
$
(561
)
$
49
$
(31
)
$
28
$
50 Other Noncurrent Assets
$
—
$
—
$
—
$
—
$
—
$
—
$
—
(A)
The table above excludes intercompany derivatives between Power and Energy Holdings. (B) Represents the netting of fair value balances with the same counterparty and the application of collateral. Includes cash collateral of $(190) million and $(140) million netted against current assets and noncurrent assets respectively. Includes cash collateral of $74 million and $33 million
netted against current liabilities and noncurrent liabilities respectively. (C) Includes PSEG parent company interest rate swap assets of $8 million and interest rate swap liability of $(4) million, designated as fair value hedges, recorded in Current Assets-Derivative Contracts and Noncurrent Liability-Derivative Contracts respectively. The aggregate fair value of derivative contracts in a liability position as of September 30, 2009 that contain triggers for additional collateral was $600 million. This potential additional collateral is included in the $850 million discussed in Note 6. Commitments and Contingent Liabilities. 38
(UNAUDITED)
Location
Holdings
(A)
Derivatives (C)
Related
Contracts
Related
Contracts
Related
Contracts
Related
Contracts
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended September 30, 2009: Derivatives in SFAS 133
Amount of Pre-Tax
Location of Pre-Tax
Amount of Pre-Tax
Location of Pre-Tax
Amount of Pre-Tax
Millions PSEG (A) Energy-Related Contracts
$
(19
)
Operating Revenue
$
141
Operating Revenue
$
(8
) Energy-Related Contracts
(6
)
Energy Costs
(19
)
— Interest Rate Swaps
(3
)
Interest Expense
(1
)
— Total PSEG
$
(28
)
$
121
$
(8
) PSEG Power Energy-Related Contracts
$
(20
)
Operating Revenue
$
129
Operating Revenue
$
(8
) Energy-Related Contracts
(6
)
Energy Costs
(11
)
— Total Power
$
(26
)
$
118
$
(8
) PSE&G Interest Rate Swaps
$
—
Interest Expense
$
—
$
— Total PSE&G
$
—
$
—
$
— Energy Holdings Energy-Related Contracts
$
1
Operating Revenue
$
12
$
— Energy-Related Contracts
—
Energy Costs
(8
)
— Interest Rate Swaps
—
Interest Expense
—
— Total Energy Holdings
$
1
$
4
$
—
(A)
Includes amounts for PSEG parent.
39
(UNAUDITED)
Cash Flow Hedging
Relationships
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective Portion)
Gain (Loss)
Reclassified from
AOCI into
Income
Gain (Loss)
Reclassified from
AOCI into
Income
(Effective Portion)
Gain (Loss)
Recognized
in Income on
Derivatives
(Ineffective
Portion)
Gain (Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the nine months ended September 30, 2009: Derivatives in SFAS 133
Amount of Pre-Tax
Location of Pre-Tax
Amount of Pre-Tax
Location of Pre-Tax
Amount of Pre-Tax
Millions PSEG (A) Energy-Related Contracts
$
502
Operating Revenue
$
452
Operating Revenue
$
(17
) Interest Rate Swaps
—
Income from
(1
)
— Energy-Related Contracts
(50
)
Energy Costs
(82
)
— Interest Rate Swaps
(4
)
Interest Expense
(7
)
— Total PSEG
$
448
$
362
$
(17
) PSEG Power Energy-Related Contracts
$
483
Operating Revenue
$
417
Operating Revenue
$
(17
) Energy-Related Contracts
(42
)
Energy Costs
(59
)
— Total Power
$
441
$
358
$
(17
) PSE&G Interest Rate Swaps
$
(1
)
Interest Expense
$
(2
)
$
— Total PSE&G
$
(1
)
$
(2
)
$
— Energy Holdings Energy-Related Contracts
$
19
Operating Revenue
$
35
$
— Interest Rate Swaps
$
—
Income from
Equity Method
Investments
$
(1
)
$
— Energy-Related Contracts
(8
)
Energy Costs
(23
)
— Interest Rate Swaps
—
Interest Expense
(4
)
— Total Energy Holdings
$
11
$
7
$
—
(A)
Includes amounts for PSEG parent.
The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Income of PSEG on a pre-tax and after-tax basis:
Accumulated Other Comprehensive Income
Pre-Tax
After-Tax
Millions Balance as of December 31, 2008
$
292
$
172 Gain Recognized in AOCI (Effective Portion)
477
282 Less: Gain Reclassified into Income (Effective Portion)
(243
)
(143
) Balance as of June 30, 2009
$
526
$
311 Loss Recognized in AOCI (Effective Portion)
(28
)
(16
) Less: Gain Reclassified into Income (Effective Portion)
(121
)
(73
) Balance as of September 30, 2009
$
377
$
222 40
(UNAUDITED)
Cash Flow Hedging
Relationships
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective Portion)
Gain (Loss)
Reclassified from
AOCI into
Income
Gain (Loss)
Reclassified from
AOCI into
Income
(Effective Portion)
Gain (Loss)
Recognized
in Income on
Derivatives
(Ineffective
Portion)
Gain (Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)
Equity Method
Investments
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and nine months ended September 30, 2009: Derivatives Not Designated Location of Pre-Tax
Amount of Pre-Tax Gain (Loss)
Three Months Ended
Nine Months Ended
Millions PSEG Energy-Related Contracts Operating Revenues
$
65
$
269 Energy-Related Contracts Energy Costs
(33
)
(157
) Interest Rate Swaps Interest Expense
—
1 Derivatives in NDT Funds Other Income
—
13 Total PSEG
$
32
$
126 Power Energy-Related Contracts Operating Revenue
$
(13
)
$
111 Energy-Related Contracts Energy Costs
(33
)
(140
) Derivatives in NDT Funds Other Income
—
13 Total Power
$
(46
)
$
(16
) Energy Holdings Operating Revenue
$
78
$
158 Energy-Related Contracts
(UNAUDITED)
as Hedges
Gain (Loss)
Recognized in
Income on Derivatives
Recognized in Income on Derivatives
September 30, 2009
September 30, 2009