UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED March 31, 2009
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
|
|
|
|
|
Commission |
Registrants, State of Incorporation, |
I.R.S. Employer |
||
001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
22-2625848 |
||
001-34232 |
PSEG POWER LLC |
22-3663480 |
||
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). Yes £ No £
(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
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 April 15, 2009, Public Service Enterprise Group Incorporated had outstanding 505,985,764 shares of its sole class of Common Stock, without par value. PSEG Power LLC is a wholly owned subsidiary of Public Service Enterprise Group Incorporated and meets the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General
Instruction H. As of April 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.
and Gas Company
TABLE OF CONTENTS
Page
ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
1
5
8
12
13
15
16
17
28
28
35
40
40
41
42
43
43
46
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
48
48
50
57
60
60
Item 3.
60
Item 4.
62
Item 1.
63
Item 1A.
63
Item 2.
63
Item 4.
64
Item 5.
64
Item 6.
66
67 i
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those
anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,”
variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those
contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 5. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings
we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:
•
Adverse changes in energy industry, policies and regulation, including market structures and rules. • New energy legislation. • 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 regulations that could increase our costs or limit operations of our generating units. • Changes in nuclear regulation and/or developments in the nuclear power industry generally, that could limit operations of our nuclear generating units. • Actions or activities at one of our nuclear units that might adversely affect our ability to continue to operate that unit or other units at the same site. • Any inability to balance our energy obligations, available supply and trading risks. • Any deterioration in our credit quality. • 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. • Increases in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units. • Delays or cost escalations in our construction and development activities. • Adverse investment performance of our decommissioning and defined benefit plan trust funds and changes in discount rates and funding requirements. • 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
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For the Three Months
2009
2008 OPERATING REVENUES
$
3,921
$
3,792 OPERATING EXPENSES Energy Costs
2,068
2,119 Operation and Maintenance
675
627 Depreciation and Amortization
207
192 Taxes Other Than Income Taxes
44
43 Total Operating Expenses
2,994
2,981 OPERATING INCOME
927
811 Income from Equity Method Investments
10
12 Other Income
71
93 Other Deductions
(115
)
(95
) Interest Expense
(145
)
(153
) INCOME FROM CONTINUING OPERATIONS
748
668 Income Tax Expense
(304
)
(233
) INCOME FROM CONTINUING OPERATIONS
444
435 Income from Discontinued Operations, net of tax expense of $6
—
13 NET INCOME
$
444
$
448 WEIGHTED AVERAGE COMMON SHARES BASIC
505,986
508,490 DILUTED
506,548
510,107 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS
$
0.88
$
0.86 NET INCOME
$
0.88
$
0.88 DILUTED INCOME FROM CONTINUING OPERATIONS
$
0.88
$
0.85 NET INCOME
$
0.88
$
0.88 DIVIDENDS PAID PER SHARE OF COMMON STOCK
$
0.3325
$
0.3225 See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Ended March 31,
BEFORE INCOME TAXES
OUTSTANDING (THOUSANDS):
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
1,232
$
321 Accounts Receivable, net of allowances of $72
in 2009 and $66 in 2008
1,285
1,398 Unbilled Revenues
521
454 Fuel
520
938 Materials and Supplies
326
317 Prepayments
81
150 Restricted Funds
15
118 Derivative Contracts
207
237 Other
91
66 Total Current Assets
4,278
3,999 PROPERTY, PLANT AND EQUIPMENT
21,172
20,818 Less: Accumulated Depreciation and Amortization
(6,531
)
(6,385
) Net Property, Plant and Equipment
14,641
14,433 NONCURRENT ASSETS Regulatory Assets
6,236
6,352 Long-Term Investments
2,570
2,695 Nuclear Decommissioning Trust (NDT) Funds
954
970 Other Special Funds
136
133 Goodwill and Other Intangibles
104
69 Derivative Contracts
155
160 Other
228
238 Total Noncurrent Assets
10,383
10,617 TOTAL ASSETS
$
29,302
$
29,049 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
1,055
$
1,033 Commercial Paper and Loans
—
19 Accounts Payable
925
1,227 Derivative Contracts
374
356 Accrued Interest
160
99 Accrued Taxes
387
8 Clean Energy Program
145
142 Obligation to Return Cash Collateral
105
102 Other
447
424 Total Current Liabilities
3,598
3,410 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
3,925
3,865 Regulatory Liabilities
415
355 Asset Retirement Obligations
586
576 Other Postretirement Benefit (OPEB) Costs
970
975 Accrued Pension Costs
962
1,196 Clean Energy Program
489
532 Environmental Costs
739
743 Derivative Contracts
135
164 Long-Term Accrued Taxes
1,200
1,241 Other
135
125 Total Noncurrent Liabilities
9,556
9,772 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION Long-Term Debt
6,521
6,621 Securitization Debt
1,297
1,342 Project Level, Non-Recourse Debt
41
42 Total Long-Term Debt
7,859
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
4,764
4,756 Treasury Stock, at cost, 2009—27,570,896 shares;
(583
)
(581
) Retained Earnings
4,049
3,773 Accumulated Other Comprehensive Loss
(31
)
(177
) Total Common Stockholders’ Equity
8,199
7,771 Noncontrolling Interest—Equity Investments
10
11 Total Capitalization
16,148
15,867 TOTAL LIABILITIES AND CAPITALIZATION
$
29,302
$
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 Three
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
444
$
448 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
207
193 Amortization of Nuclear Fuel
29
24 Provision for Deferred Income Taxes (Other than Leases) and ITC
19
3 Non-Cash Employee Benefit Plan Costs
87
42 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
(106
)
(26
) Undistributed Earnings from Affiliates
(7
)
(21
) Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives
(48
)
(20
) Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
60
(38
) Over Recovery of Societal Benefits Charge (SBC)
44
31 Cost of Removal
(9
)
(9
) Net Realized Losses and Expense from NDT Funds
39
8 Net Change in Certain Current Assets and Liabilities
927
400 Employee Benefit Plan Funding and Related Payments
(281
)
(24
) Other
(16
)
32 Net Cash Provided By Operating Activities
1,389
1,043 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(402
)
(323
) Proceeds from the Sale of Capital Leases and Investments
140
40 Proceeds from NDT Funds Sales
559
623 Investment in NDT Funds
(568
)
(631
) Restricted Funds
105
21 NDT Funds Interest and Dividends
10
11 Other
(9
)
(2
) Net Cash Used In Investing Activities
(165
)
(261
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans
(19
)
63 Issuance of Long-Term Debt
209
300 Payment of Long-Term Debt
(10
)
(1,013
) Payment of Non-Recourse Debt
(281
)
(13
) Payment of Securitization Debt
(42
)
(40
) Net Premium Paid on Early Extinguishment of Debt
—
(48
) Cash Dividends Paid on Common Stock
(168
)
(164
) Other
(2
)
4 Net Cash Used In Financing Activities
(313
)
(911
) Net Increase (Decrease) in Cash and Cash Equivalents
911
(129
) Cash and Cash Equivalents at Beginning of Period
321
380 Cash and Cash Equivalents at End of Period
$
1,232
$
251 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
9
$
133 Interest Paid, Net of Amounts Capitalized
$
76
$
89 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Months Ended
March 31,
PSEG POWER LLC
For the
2009
2008 OPERATING REVENUES
$
2,374
$
2,375 OPERATING EXPENSES Energy Costs
1,462
1,589 Operation and Maintenance
258
239 Depreciation and Amortization
47
38 Total Operating Expenses
1,767
1,866 OPERATING INCOME
607
509 Other Income
70
86 Other Deductions
(110
)
(91
) Interest Expense
(43
)
(42
) INCOME BEFORE INCOME TAXES
524
462 Income Tax Expense
(206
)
(187
) EARNINGS AVAILABLE TO PUBLIC SERVICE
$
318
$
275 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Three Months Ended
March 31,
ENTERPRISE GROUP INCORPORATED
PSEG POWER LLC
March 31,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
15
$
20 Accounts Receivable
360
472 Accounts Receivable—Affiliated Companies, net
486
732 Short-Term Loan to Affiliate
951
— Fuel
520
938 Materials and Supplies
237
233 Derivative Contracts
182
225 Restricted Funds
12
21 Prepayments
36
53 Other
19
11 Total Current Assets
2,818
2,705 PROPERTY, PLANT AND EQUIPMENT
7,604
7,441 Less: Accumulated Depreciation and Amortization
(2,040
)
(1,960
) Net Property, Plant and Equipment
5,564
5,481 NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Funds
954
970 Goodwill
16
16 Other Intangibles
78
43 Other Special Funds
27
27 Derivative Contracts
140
143 Other
69
74 Total Noncurrent Assets
1,284
1,273 TOTAL ASSETS
$
9,666
$
9,459 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
250
$
250 Accounts Payable
500
752 Short-Term Loan from Affiliate
—
3 Derivative Contracts
359
338 Accrued Interest
84
35 Other
173
155 Total Current Liabilities
1,366
1,533 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
441
335 Asset Retirement Obligations
341
334 Other Postretirement Benefit (OPEB) Costs
121
118 Derivative Contracts
95
111 Accrued Pension Costs
303
374 Environmental Costs
54
54 Long-Term Accrued Taxes
17
16 Other
57
47 Total Noncurrent Liabilities
1,429
1,389 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt
2,862
2,653 MEMBER’S EQUITY Contributed Capital
2,000
2,000 Basis Adjustment
(986
)
(986
) Retained Earnings
2,981
2,988 Accumulated Other Comprehensive Income (Loss)
14
(118
) Total Member’s Equity
4,009
3,884 TOTAL LIABILITIES AND MEMBER’S EQUITY
$
9,666
$
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
PSEG POWER LLC
For the Three
Months Ended
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
318
$
275 Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization
47
38 Amortization of Nuclear Fuel
29
24 Interest Accretion on Asset Retirement Obligations
7
6 Provision for Deferred Income Taxes and ITC
14
19 Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives
(53
)
(23
) Non-Cash Employee Benefit Plan Costs
19
6 Net Realized Losses and Expense from NDT Funds
39
8 Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies
414
405 Margin Deposit Asset
7
(65
) Margin Deposit Liability
151
— Accounts Receivable
218
7 Accounts Payable
(208
)
(12
) Accounts Receivable/Payable-Affiliated Companies, net
325
189 Accrued Interest Payable
49
47 Other Current Assets and Liabilities
(37
)
(3
) Employee Benefit Plan Funding and Related Payments
(78
)
— Other
2
17 Net Cash Provided By Operating Activities
1,263
938 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(207
)
(174
) Short-Term Loan—Affiliated Company, net
(951
)
(407
) Proceeds from NDT Funds Sales
559
623 NDT Funds Interest and Dividends
10
11 Investment in NDT Funds
(568
)
(631
) Restricted Funds
9
7 Other
(1
)
(6
) Net Cash Used In Investing Activities
(1,149
)
(577
) CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Recourse Long-Term Debt
209
— Cash Dividend Paid
(325
)
(125
) Short-Term Loan—Affiliated Company, net
(3
)
(238
) Net Cash Used In Financing Activities
(119
)
(363
) Net Decrease in Cash and Cash Equivalents
(5
)
(2
) Cash and Cash Equivalents at Beginning of Period
20
11 Cash and Cash Equivalents at End of Period
$
15
$
9 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
1
$
19 Interest Paid, Net of Amounts Capitalized
$
3
$
3 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
March 31,
Operating Activities:
[THIS PAGE INTENTIONALLY LEFT BLANK]
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For the Three Months
2009
2008 OPERATING REVENUES
$
2,735
$
2,618 OPERATING EXPENSES Energy Costs
1,859
1,793 Operation and Maintenance
395
360 Depreciation and Amortization
149
143 Taxes Other Than Income Taxes
44
43 Total Operating Expenses
2,447
2,339 OPERATING INCOME
288
279 Other Income
1
5 Other Deductions
(1
)
(1
) Interest Expense
(79
)
(81
) INCOME BEFORE INCOME TAXES
209
202 Income Tax Expense
(85
)
(65
) NET INCOME
124
137 Preferred Stock Dividends
(1
)
(1
) EARNINGS AVAILABLE TO PUBLIC
$
123
$
136 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 March 31,
SERVICE ENTERPRISE GROUP INCORPORATED
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
45
$
91 Accounts Receivable, net of allowances of $71 in 2009
928
909 Unbilled Revenues
521
454 Materials and Supplies
65
61 Prepayments
10
45 Restricted Funds
3
1 Derivative Contracts
1
— Deferred Income Taxes
54
52 Total Current Assets
1,627
1,613 PROPERTY, PLANT AND EQUIPMENT
12,453
12,258 Less: Accumulated Depreciation and Amortization
(4,184
)
(4,122
) Net Property, Plant and Equipment
8,269
8,136 NONCURRENT ASSETS Regulatory Assets
6,236
6,352 Long-Term Investments
165
158 Other Special Funds
47
46 Other
100
101 Total Noncurrent Assets
6,548
6,657 TOTAL ASSETS
$
16,444
$
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
and $65 in 2008, respectively
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
550
$
248 Commercial Paper and Loans
—
19 Accounts Payable
322
336 Accounts Payable—Affiliated Companies, net
774
763 Accrued Interest
59
58 Accrued Taxes
46
3 Clean Energy Program
145
142 Derivative Contracts
15
14 Obligation to Return Cash Collateral
105
102 Other
282
227 Total Current Liabilities
2,298
1,912 NONCURRENT LIABILITIES Deferred Income Taxes and ITC
2,544
2,533 Other Postretirement Benefit (OPEB) Costs
804
813 Accrued Pension Costs
498
634 Regulatory Liabilities
415
355 Clean Energy Program
489
532 Environmental Costs
685
689 Asset Retirement Obligations
243
240 Derivative Contracts
40
53 Long-Term Accrued Taxes
85
82 Other
32
31 Total Noncurrent Liabilities
5,835
5,962 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
3,164
3,463 Securitization Debt
1,297
1,342 Total Long-Term Debt
4,461
4,805 PREFERRED STOCK WITHOUT MANDATORY REDEMPTION,
80
80 COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized; issued and outstanding, 2009 and 2008—132,450,344 shares
892
892 Contributed Capital
170
170 Basis Adjustment
986
986 Retained Earnings
1,720
1,597 Accumulated Other Comprehensive Income
2
2 Total Common Stockholder’s Equity
3,770
3,647 Total Capitalization
8,311
8,532 TOTAL LIABILITIES AND CAPITALIZATION
$
16,444
$
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
$100 par value, 7,500,000 authorized;
issued and outstanding, 2009 and 2008—795,234 shares
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For The Three Months Ended
2009
2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
124
$
137 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
149
143 Provision for Deferred Income Taxes and ITC
6
(13
) Non-Cash Employee Benefit Plan Costs
59
33 Cost of Removal
(9
)
(9
) Over Recovery of Electric Energy Costs (BGS and NTC)
20
15 Over (Under) Recovery of Gas Costs
40
(53
) Over Recovery of SBC
44
31 Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues
(86
)
(130
) Materials and Supplies
(4
)
(6
) Prepayments
35
50 Accrued Taxes
43
37 Accrued Interest
1
(3
) Accounts Payable
(14
)
(38
) Accounts Receivable/Payable-Affiliated Companies, net
(62
)
(20
) Obligation to Return Cash Collateral
3
23 Other Current Assets and Liabilities
51
75 Employee Benefit Plan Funding and Related Payments
(172
)
(19
) Other
(12
)
8 Net Cash Provided By Operating Activities
216
261 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(194
)
(145
) Other
(6
)
— Net Cash Used In Investing Activities
(200
)
(145
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt
(19
)
63 Issuance of Long-Term Debt
—
300 Redemption of Long-Term Debt
—
(401
) Redemption of Securitization Debt
(42
)
(40
) Deferred Issuance Costs
—
(1
) Preferred Stock Dividends
(1
)
(1
) Net Cash Used In Financing Activities
(62
)
(80
) Net Increase (Decrease) In Cash and Cash Equivalents
(46
)
36 Cash and Cash Equivalents at Beginning of Period
91
32 Cash and Cash Equivalents at End of Period
$
45
$
68 Supplemental Disclosure of Cash Flow Information: Income Taxes Received
$
(12
)
$
— Interest Paid, Net of Amounts Capitalized
$
75
$
81 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)
March 31,
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:
•
PSEG Power LLC (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 function 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. • Public Service Electric and Gas Company (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 the FERC. • 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. Energy Holdings’ subsidiaries are subject to
regulation by the FERC and the states or countries in which they operate. • 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 Reports on Form 10-K for the year ended December 31, 2008. 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. Reclassifications A reclassification was made to PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2008 to conform to the 2009 presentation. In accordance with the adoption of a new accounting standard in 2009, $11 million of minority interests was reclassified from Other Noncurrent Liabilities
to Noncontrolling Interests. See Note 2. Recent Accounting Standards for additional information. 12
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 2. Recent Accounting Standards The following is a summary of new accounting guidance adopted in 2009 and guidance issued but not yet adopted that could impact our businesses. We do not anticipate that any of the guidance adopted in 2009 will have a material impact on our financial statements. Accounting standards adopted in 2009 Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007), “Business Combinations” (SFAS 141(R))
•
changes financial accounting and reporting of business combination transactions • requires all assets acquired and liabilities assumed in a business combination to be measured at their acquisition date fair value, with limited exceptions • requires acquisition-related costs and certain restructuring costs to be recognized separately from the business combination • applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree. We adopted SFAS 141(R) effective January 1, 2009. Any new business combination transactions will be accounted for under this guidance. SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS 160)
•
changes the financial reporting relationship between a parent and non-controlling interests • requires all entities to report minority interests in subsidiaries as a separate component of equity in the consolidated financial statements • requires net income attributable to the non-controlling interest to be shown on the face of the income statement in addition to net income attributable to the controlling interest • applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. We adopted SFAS 160 effective January 1, 2009 and revised our balance sheet presentation as required by the standard. The income statement impact is immaterial. SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (SFAS 161)
•
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. We adopted SFAS 161 effective January 1, 2009. Accounting standards to be adopted effective April 1, 2009 FASB Staff Position (FSP) FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2 and FAS 124-2)
•
issued by the FASB in April 2009
13
(UNAUDITED)
¡
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS • revises recognition guidance in determining whether a debt security is other-than-temporarily impaired. A debt security is considered other-than-temporarily impaired if the fair value is less than the amortized cost, and in any of the following circumstances:
An entity has the 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, and ¡ 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 and/ or other comprehensive income.
We are currently assessing the impact of this standard on our financial statements. FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)
issued by the FASB in April 2009 • requires a publicly traded company to disclose 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 fair value, and ¡ changes in methods and significant assumptions, if any. Upon adoption, the standard will impact our interim financial statements by requiring additional fair value information. FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP FAS 157-4)
•
issued by the FASB in April 2009 • provides guidance:
¡
to determine if there has been a significant decrease in the volume and level of activity for the asset or liability, and ¡ to estimate fair values, when transactions or quoted process are not determinative of fair value
•
requires management to use judgment to determine whether a market is distressed or not orderly, even if there has been a significant decrease in the volume and level of activity for the asset or liability.
Upon adoption, we do not anticipate that this standard will have a material impact on our financial statements. Accounting standard to be adopted for 2009 year-end reporting FSP FAS 132(R)-1, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (FSP FAS 132(R)-1)
issued by the FASB in December 2008
14
(UNAUDITED)
¡
•
•
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS • requires additional disclosures about the fair value of plan assets of a defined benefit 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 are currently assessing the potential impact of this standard 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 ended March 31, 2008, which were reclassified to Discontinued Operations, are summarized below:
Quarter Ended
(Millions) Operating Revenues
$
11 Income Before Income Taxes
$
1 Net Loss
$
(1
) SAESA Group In July 2008, Energy Holdings sold its investment in the SAESA Group for a total purchase price 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 ended March 31, 2008, which were reclassified to Discontinued Operations, are summarized below:
Quarter Ended
(Millions) Operating Revenues
$
186 Income Before Income Taxes
$
20 Net Income
$
14 15
(UNAUDITED)
¡
March 31,
2008
March 31,
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Dispositions PPN Power Generating Company Limited (PPN) In March 2009, Energy Holdings entered into an agreement to sell its 20% ownership interest in PPN, which owns and operates a 330 MW naphtha and natural gas-fired combined cycle plant in Tamil Nadu, India. The sale is expected to close in the second quarter. The sale price is expected to
be approximately $15 million, which is the book value of the investment as of March 31, 2009. This amount is included in Other Current Assets in PSEG’s Condensed Consolidated Balance Sheet. Leveraged Leases In February 2009, Energy Holdings sold its interest in the Westland gas distribution facility leveraged lease and its interest in the Whitehorn gas turbine facility leveraged lease for an after-tax gain of $8 million. In January 2009, Energy Holdings sold its 51% interest in the EPZ Swentibold facility leveraged lease and its interest in the Dutch Rail Locomotives leveraged lease for an after-tax gain of $4 million. 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
2009
2008
2009
2008
(Millions) Components of Net Periodic Benefit Cost: Service Cost
$
19
$
19
$
3
$
4 Interest Cost
59
57
18
18 Expected Return on Plan Assets
(54
)
(72
)
(3
)
(4
) Amortization of Net Transition Obligation
—
—
7
7 Prior Service Cost
2
2
4
3 Actuarial Loss (Gain)
28
3
(1
)
— Net Periodic Benefit Cost
$
54
$
9
$
28
$
28 Effect of Regulatory Asset
—
—
5
5 Total Benefit Expense, Including Effect of
$
54
$
9
$
33
$
33 16
(UNAUDITED)
Quarters Ended
March 31,
Quarters Ended
March 31,
Regulatory Asset
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Pension costs and OPEB costs for PSEG, Power and PSE&G are detailed as follows:
Pension Benefits
OPEB
2009
2008
2009
2008
(Millions) Power
$
16
$
3
$
3
$
3 PSE&G
30
4
29
29 Other
8
2
1
1 Total Benefit Costs
$
54
$
9
$
33
$
33 During the quarter ended March 31, 2009, PSEG contributed $257 million of the approximately $370 million it expects to contribute into its pension plans in the calendar year 2009. During the first quarter of 2009, PSEG contributed $8 million of its $11 million planned contribution for the
calendar year 2009 into its postretirement healthcare plan. Note 5. 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 a 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 exposure 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. 17
(UNAUDITED)
Quarters Ended
March 31,
Quarters Ended
March 31,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The face value of outstanding guarantees, current exposure and margin positions as of March 31, 2009 and December 31, 2008 are as follows:
March 31,
December 31,
(Millions) Face value of outstanding guarantees
$
2,041
$
1,856 Exposure under current guarantees
$
589
$
585 Letters of Credit Margin Posted
$
128
$
201 Letters of Credit Margin Received
$
258
$
250 Net Cash Received Counterparty Cash Margin Deposited
$
3
$
3 Counterparty Cash Margin (Received)
(232
)
(81
) Net Broker Balance (Received) Deposited
(81
)
(74
) Total Net Cash Received
$
(310
)
$
(152
) Power nets the fair value of cash collateral receivables and payables with the corresponding net energy contract balances. As a result, of the net cash received, Power has included $282 million and $112 million in its corresponding net derivative contract positions as of March 31, 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 further performance assurance. As of March 31, 2009, if Power were to lose its
investment grade rating, additional collateral of approximately $1.2 billion could be required. As of March 31, 2009, there was $2.7 billion of available liquidity under PSEG and Power’s credit facilities that could be used to post collateral. In addition to amounts in the table above, Power had
posted $105 million and $121 million in letters of credit as of March 31, 2009 and December 31, 2008, respectively, to support various other contractual and environmental obligations. The available liquidity as of March 31, 2009 does not include $150 million under a bilateral credit facility that
Power executed in April 2009 to replace a credit agreement that expired during March 2009. 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) and has undertaken a study of the river. The study area includes 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. 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. Power assumed
any environmental liabilities of the Essex Site when it was transferred from PSE&G, and PSE&G obtained releases and indemnities for liabilities arising out of the former generating station when it was sold. The costs associated with the MGP Remediation Program have historically been recovered
through the Societal Benefits Clause (SBC) charges to PSE&G ratepayers. 18
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The EPA has indicated that it believed hazardous substances had been released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. In 2006, the EPA notified the potentially responsible parties (PRPs) that
the cost of its study will greatly exceed its original estimated cost of $20 million. 73 PRPs, including Power and PSE&G, have agreed to assume responsibility for the study and to divide the associated costs among themselves according to a mutually agreed-upon formula. The PRP group is
presently executing the study. The percentage of costs allocable to Power and PSE&G has varied depending on the number of PRPs funding the study and currently is approximately 6% of the study cost, approximately 80% of which is attributable to PSE&G’s former MGP sites and approximately
20% 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 contamination cleanup in the lower eight miles of the Passaic River, with estimated costs ranging from $900 million to $2.3 billion, in addition to a “No Action” alternative. 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 later in 2009. 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. The work will cost an estimated $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. In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and related companies in New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects on the Passaic River of the PRP’s
former operations which resulted in the discharge of hazardous substances. On February 4, 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 it discharged into the Passaic River and seeking statutory contribution and contribution under the New Jersey Spill Compensation and Control Act (Spill Act) to recover past and future removal costs and damages. 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 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 a letter 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 companies 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. Newark Bay Study Area The EPA established the Newark Bay Study Area, which it defined as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. 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 this 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 is
conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack 19
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding the 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, Newark Bay Study Area or other 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 fourth quarter of 2008, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $709 million and $820 million from December 31, 2008 through 2021. Since no amount within the range was considered
to be most likely, PSE&G recorded a liability of $709 million as of December 31, 2008. As of March 31, 2009, PSE&G’s remaining accrual was $705 million. Of this amount, $20 million was recorded in Other Current Liabilities and $685 million was reflected as Environmental Costs in Noncurrent
Liabilities. As such, PSE&G has recorded a $705 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, 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 Power’s Mercer, Hudson and Bergen generating stations. Under this agreement, Power is required to undertake a number of technology projects, plant modifications and
operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter and mercury and to repower Bergen Unit 2 utilizing low-emission combined cycle combustion turbine technology. Pursuant to this program, Power has installed selective catalytic reduction equipment at Mercer at a cost of $118 million and baghouses were placed in service in December 2008, with costs as of March 31, 2009 of $260 million. The cost of assets to be placed in service in order to implement the
balance of the agreement is estimated at $200 million to $250 million for Mercer, to be completed by May 2010, and $700 million to $750 million for Hudson, to be completed by the end of 2010, of which $334 million has been spent through March 31, 2009. All back end pollution control
technology construction is expected to be completed by the end of 2010. Bergen Unit 2 was repowered in 2002 consistent with the consent decree. On January 14, 2009, the EPA issued a notice of violation to Power and 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 20
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. In October 2008, the
EPA filed a petition with the U.S. Supreme Court to review the lower court’s decision. On February 6, 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, although certain industry litigants pursued Supreme Court review of the lower court’s decision. On February 23, 2009, the Supreme Court denied the petition. The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements 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 New Jersey and Connecticut mercury-control requirements, as described below. Some uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations, discussed below. The estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired units in New Jersey and
Pennsylvania have been incurred or are included in Power’s capital expenditure forecast. Total estimated costs for each project are between $150 million and $200 million. 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, are permitted to postpone such
reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power achieved the reductions required in 2007 through the installation of carbon injection technology and baghouses at both Mercer units and anticipates compliance with the remaining reductions required by December 2012 will be achieved through the installation of a baghouse at its Hudson
plant by the end of 2010. The mercury-control technologies are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above. 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 as required under a strict interpretation of the Clean Air Act. On January 30, 2009, the Commonwealth Court of Pennsylvania struck down the 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 Pennsylvania mercury rule by benefiting from reductions realized from the installation of planned or completed controls for compliance with SO2 and NOx reductions. Power will evaluate Phase II of the 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 21
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS uncertain at this time whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions with their respective currently planned capital expenditures. Emission Fees Section 185 of the Clean Air Act requires states (or in the absence of state action, the EPA) in severe and extreme non-attainment areas to adopt a penalty fee for major stationary sources if the area fails to attain the one-hour ozone National Ambient Air Quality Standard (NAAQS) set by the
EPA. In June 2007, the U.S. Court of Appeals for the District of Columbia Circuit ruled against the EPA, which had sought to vacate imposition of fees for NOx emissions because the one hour standard was superseded by an eight-hour standard. Power operates electric generation stations, major
stationary sources, in the New Jersey-Connecticut severe non-attainment area that did not meet the required NAAQS by November 2007. Neither the EPA nor the states in the non-attainment areas in which Power operates have initiated any process for imposing fees in compliance with the court
ruling; however, preliminary analysis suggests that penalty fees could be approximately $6 million annually, which Power is currently accruing. This analysis could change if the EPA or the states issue additional guidance addressing the imposition of fees, or if Power is able to reduce its
emissions of NOx in the future. On January 9, 2009, the NJDEP provided notice that it is in the process of assessing fees under Section 185 for 2008 emissions. These fees are expected to be paid in 2010 after the NJDEP determines the need for statutory or regulatory changes. NOx Reduction 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 is expected to have a significant impact on Power’s generation fleet, including the
likely retirement of a significant portion of Power’s units by April 30, 2015. The rule is expected to require the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW). 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. Power cannot predict the financial impact resulting from compliance with this rulemaking. 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 had a $50 million liability as of March 31, 2009 and December 31, 2008, respectively, 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 prepared in accordance with the Federal Water Pollution Control Act’s (FWPCA) Section 316(b) and the Phase II 316(b) rules, allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. 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 22
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson, and the Connecticut Department of Environmental Protection for Bridgeport. A renewal application is expected to be filed for Sewaren later this year. 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, 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. • instructed the EPA to reconsider the definition of “best technology available” without comparing the costs of the best performing technology to its benefits. In May 2007, Power and other industry petitioners filed a request for a rehearing with the Second Circuit Court, which was denied. The parties, including Power, requested U.S. Supreme Court review of the matter. On April 1, 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the EPA permissibly relied 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. It is premature to determine when the Second Circuit will act on this ruling or its ultimate disposition of the case. However, because there were major portions of the Phase II regulations which were originally remanded by the Second Circuit that were not considered by the Supreme Court, the
EPA will need to undertake a rulemaking in the future. 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 costs estimated 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. 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. 23
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Generation and Development Nuclear Power has approved the expenditure of $192 million for 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). Significant project expenditures will begin later in 2009 and continue through 2012. 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 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 to date are $11 million which are included in Other Noncurrent Assets in Power’s and PSEG’s Consolidated Balance Sheets. 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, 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 Interconnection L.L.C. (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 February 2009 BGS Auction will become 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 14. Related-Party Transactions. 24
(UNAUDITED)
the 2006 Auction Year agreements expire.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 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 March 31, 2009, the total minimum purchase requirements included in these commitments are as follows:
Fuel Type
Commitments
Power’s share
(Millions) Nuclear Fuel Uranium
$
704
$
441 Enrichment
$
475
$
270 Fabrication
$
245
$
149 Natural Gas
$
910
$
910 Coal/Oil
$
955
$
955 Included in the $955 million commitment for coal and oil above is $457 million related to a certain coal contract under which Power can cancel tonnage at minimal cost. Power has entered into gas supply option agreements for the anticipated fuel requirements at the PSEG Texas generation facilities to satisfy obligations under their forward energy sales contracts. As of March 31, 2009, Power’s fuel purchase options totaled $51 million under those agreements,
which is not included in the above table. PSEG Texas also has 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 Texas also has the right to cancel delivery of the gas at
a minimal cost. 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 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. 25
(UNAUDITED)
through 2013
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. The plaintiff has filed a petition for certification with the New Jersey Supreme Court requesting that the Appellate Division decision be overturned. 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 March 2009, would be $141 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. Exceptions to the ALJ’s decision were filed on February 9, 2009. The BPU may choose to accept, modify or reject the ALJ’s decision in reaching its final decision. A BPU decision is expected by June 1, 2009. We cannot predict the final outcome of this proceeding. 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 $634 million as of March 31, 2009. Of this amount, $145 million was recorded as a current liability and $489 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. Leveraged Lease Investments In November 2006, the Internal Revenue Service (IRS) issued Revenue Agent’s Reports with respect to its audit of PSEG’s federal corporate income tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain lease transactions that are similar to a type that
the IRS publicly announced its intention to challenge. In addition, the IRS Reports proposed a 20% penalty for substantial 26
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS understatement of tax liability. In February 2007, PSEG filed a protest of these findings with the Office of Appeals of the IRS. In April 2008, the IRS issued its Revenue Agent’s Report for tax years 2001 through 2003, which disallowed all deductions associated with lease transactions similar to those disallowed in its 1997 through 2000 Report. As in its prior report, the IRS proposed a 20% penalty. PSEG also filed a
protest to this report with the Office of Appeals of the IRS. As of March 31, 2009 and December 31, 2008, PSEG’s total gross investment in such transactions was $924 million and $1 billion, respectively. There are several tax cases involving other taxpayers with similar leveraged lease investments that are pending. To date, three cases have been decided at the trial court level, two of which were decided in favor of the government. An appeal of one of these decisions was recently affirmed. The
third case involves a jury verdict that is currently being challenged by both parties on inconsistency grounds. In August 2008, the IRS publicly announced that it was issuing letters to a number of taxpayers with these types of lease transactions containing a generic settlement offer. PSEG did not accept the IRS’ settlement offer and will likely proceed to litigation. Earnings Impact Assuming all rental payments are made pursuant to the original lease agreement, and there are no changes in tax legislation and rates, the total cash and income included in a leveraged lease transaction will not change over the lease term. However, the timing of the cash flow can change due to
changes in the timing of tax deductions. Changes in the timing of cash flows affect the overall return, or yield, that is recorded as income at a constant rate throughout the lease term. If there is a change in cash flow timing, pursuant to FSP 13-2, “Accounting for a Change or Projected Change in
the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction,” the lease must be recalculated from inception assuming the new lease yield. Differences between the current gross lease investment and the gross lease investment per the recalculated lease must be
recognized immediately in income. In the second quarter of 2008, PSEG recalculated its lease transactions, incorporating potential cash payments (discussed below) consistent with the FIN 48 reserve position, 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 in PSEG’s Condensed Consolidated Statement of Operations. The $355 million is being recognized as income over the remaining term of the affected leases. This represents PSEG’s view of most of the financial statement exposure related to these lease transactions, although a total loss, consistent with the broad settlement offer recently proposed by the IRS, would result in an additional earnings charge of $100 million to $120 million. Cash Impact As of March 31, 2009, an aggregate $1.2 billion would become currently payable if PSEG conceded 100% of deductions taken through that date. PSEG has deposited $180 million with the IRS to defray potential interest costs associated with this disputed tax liability. In the event PSEG is
successful in defense of its position, the deposit is fully refundable with interest. These deposits reduce the $1.2 billion cash exposure noted above to $1 billion. As of March 31, 2009, penalties of $152 million would also become payable if the IRS was successful in its deficiency claims against PSEG, and asserted and successfully litigated a case against PSEG regarding
penalties. 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. 27
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Should PSEG lose its case in litigation, and the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $130 million to $150 million of tax would be due for tax positions through March 31, 2009. PSEG currently anticipates that it will pay between $230 million and $370 million in tax, interest and penalties for the tax years 1997 through 2000 during the second half of 2009 and subsequently commence litigation to recover these amounts. Further it is possible that an additional payment of
between $270 million and $550 million could be required in late 2009 for tax years 2001 through 2003 followed by further litigation to recover those taxes. These amounts are in addition to tax deposits already made. The actions described above concerning the leveraged lease investments are not expected to violate any covenant or result in a default under either Energy Holdings’ credit facility or Senior Notes indenture. Note 6. Changes in Capitalization The following capital transactions occurred in the first quarter of 2009: Power
•
Converted $44 million of 4.00% Pollution Control Bonds to variable rate demand bonds backed by letters of credit. • 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 (callable in one year), and ¡ issued $48 million of 6% MTNs due January 2013 (callable in one year).
•
paid a cash dividend of $325 million to PSEG.
PSE&G
paid $42 million of Transition Funding’s securitization debt.
Energy Holdings
Redeemed $280 million of floating rate non-recourse project debt due on December 31, 2009 associated with PSEG Texas. • Repurchased $10 million of its 8.5% Senior Notes due 2011. In April 2009, Power paid $250 million of 3.75% Senior Notes at maturity. Note 7. 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. 28
(UNAUDITED)
•
•
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 in accordance with SFAS 133, with changes in
fair value charged to 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 effect of using such modeling techniques is not material to Power’s or Energy Holdings’ financial statements. Cash Flow Hedges Power uses forward sale and purchase contracts, swaps, futures and firm transmission right contracts to hedge:
•
forecasted energy sales from its generation stations and the related load obligations; and • the price of fuel to meet its fuel purchase requirements. Energy Holdings uses forward sale and purchase contracts and swaps to hedge:
•
forecasted energy sales from its Texas generation stations; and • to hedge the price of fuel for one of the Texas generation facilities. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of March 31, 2009 and December 31, 2008, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:
March 31,
December 31,
(Millions) Power Fair Values of Cash Flow Hedges
$
498
$
331
* Impact on Accumulated Other Comprehensive Income (Loss) (after tax)
$
300
$
176 Energy Holdings Fair Values of Cash Flow Hedges
$
—
$
3 Impact on Accumulated Other Comprehensive Income (Loss) (after tax)
$
12
$
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 March 31, 2010 and March 31, 2011 are $170 million and $80 million, respectively.
Ineffectiveness associated with these hedges, as defined in SFAS 133, was $15 million at March 31, 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 29
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of load deals 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 less than one percent of Power’s revenues. 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. A portion is also used in Power’s Nuclear Decommissioning Trust (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. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of March 31, 2009 and December 31, 2008 was as follows:
March 31,
December 31,
(Millions) Net Fair Value of Other Derivatives Power
$
88
$
67
* Energy Holdings
$
40
$
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 On April 1, 2009, PSEG’s interest rate swap that had converted Power’s $250 million of 3.75% Senior Notes due April 2009 into variable-rate debt matured. The interest rate swap was designated and effective as a fair value hedge. The fair value changes of the interest rate swap were fully offset
by the fair value changes in the underlying debt. Cash Flow Hedges 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 March 31, 2009, there was no hedge ineffectiveness associated
with these hedges. The fair values of our interest rate derivatives were
$(1) million and $(7) million as of March 31, 2009 and December 31, 2008,
respectively. The AOCI related to interest rate derivatives designated as
cash flow hedges was $(3) million and $(6) million as of March 31, 2009 and
December 31, 2008, respectively. 30
(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: Derivatives Designated as
Derivatives in Asset Position
Derivatives in Liability Position
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
(Millions)
(Millions) PSEG Interest Rate Swaps
$
—
Derivative Contracts-
$
(1
) PSEG & Power (A) Energy-Related Contracts
Derivative Contracts-
$
673
Derivative Contracts-
$
(336
) Energy-Related Contracts
Derivative Contracts-
538
Derivative Contracts-
(271
) Energy-Related Contracts
Derivative Contracts-
108
Derivative Contracts-
(176
) Energy-Related Contracts
Derivative Contracts-
43
Derivative Contracts-
(81
) Margin Collateral
(362
)
16 Total PSEG & Power
$
1,000
Total PSEG & Power
$
(848
) 31
(UNAUDITED)
Hedging Instruments
under SFAS 133
as of March 31, 2009
as of March 31, 2009
Current Liabilities
Current Assets
Current Assets
Noncurrent Assets
Noncurrent Assets
Current Liabilities
Current Liabilities
Noncurrent Liabilities
Noncurrent Liabilities
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivatives Not Designated
Derivatives in Asset Position
Derivatives in Liability Position
Balance Sheet Location
Fair Value
Balance Sheet Location
Fair Value
(Millions)
(Millions) PSEG Energy-Related Contracts
Derivative Contracts-
$
566
Derivative Contracts-
$
(481
) Energy-Related Contracts
Derivative Contracts-
221
Derivative Contracts-
(145
) Energy-Related Contracts
Derivative Contracts-
502
Derivative Contracts-
(905
) Energy-Related Contracts
Derivative Contracts-
126
Derivative Contracts-
(247
) Margin Collateral
(40
)
105 Other Contracts
NDT Funds
127
NDT Funds
(19
) Total PSEG
$
1,502
Total PSEG
$
(1,692
) Power (A) Energy-Related Contracts
Derivative Contracts-
$
540
Derivative Contracts-
$
(481
) Energy-Related Contracts
Derivative Contracts-
206
Derivative Contracts-
(145
) Energy-Related Contracts
Derivative Contracts-
502
Derivative Contracts-
(890
) Energy-Related Contracts
Derivative Contracts-
126
Derivative Contracts-
(207
) Margin Collateral
(40
)
105 Other Contracts
NDT Funds
$
127
NDT Funds
$
(19
) Total Power
$
1,461
Total Power
$
(1,637
) PSE&G Energy-Related Contracts
Derivative Contracts-
Current Assets
$
1
Derivative Contracts-
Current Liabilities
$
(15
) Energy-Related Contracts
—
Derivative Contracts-
Noncurrent Liabilities
(40
) Total PSE&G
$
1
Total PSE&G
$
(55
) Energy Holdings Energy-Related Contracts
Derivative Contracts-
Current Assets
$
25
$
— Energy-Related Contracts
Derivative Contracts-
Noncurrent Assets
15
— Total Energy Holdings
$
40
$
—
(A)
Energy-related contracts for Power are subject to master netting arrangements with the right of offset for certain counterparties. Contract amounts are shown gross in the above table and are not necessarily reflective of amounts presented in the Condensed Consolidated Balance Sheets.
The aggregate fair value of derivative contracts in a liability position as of March 31, 2009 that contain triggers for additional collateral is $787 million. This potential additional collateral is included in the $1.2 billion discussed in Note 5. Commitments and Contingent Liabilities. 32
(UNAUDITED)
as Hedges in SFAS
133 Fair Value
Hedging Relationships
as of March 31, 2009
as of March 31, 2009
Current Assets
Current Assets
Noncurrent Assets
Noncurrent Assets
Current Liabilities
Current Liabilities
Noncurrent Liabilities
Noncurrent Liabilities
Current Assets
Current Assets
Noncurrent Assets
Noncurrent Assets
Current Liabilities
Current Liabilities
Noncurrent Liabilities
Noncurrent Liabilities
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 quarter ended March 31, 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 Energy-Related Contracts
$
382
Operating Revenue
$
156
Operating Revenue
8
Energy-Related Contracts
(28
Energy Costs
(26
)
— Interest Rate Swaps
—
Interest Expense
(4
— Total PSEG
$
354
$
126
$ 8 PSEG Power Energy-Related Contracts
$
354
Operating Revenue
$
142
Operating Revenue
$ 8 Energy-Related Contracts
(21
Energy Costs
(19
)
— Total Power
$
333
$
123
$ 8 Energy Holdings Energy-Related Contracts
$
28
Operating Revenue
$
14
$
— Energy-Related Contracts
(7
Energy Costs
(7
)
— Interest Rate Swaps
—
Interest Expense
(4
— Total Energy Holdings
$
21
$
3
$
— The
following reconciles the Accumulated Other Comprehensive Income for derivative
activity included in the Accumulated Other Comprehensive Loss of PSEG on
a pre-tax and after-tax basis: Accumulated
Other Comprehensive Income Balance
as of December 31, 2008 $ 292 $ 172 Gain
Recognized in AOCI (Effective Portion) 354 211 Less: Gain
Reclassified into Income (Effective Portion) (126 (74 Balance
as of March 31, 2009 $ 520 $ 309 33
(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)
$
)
)
)
)
)
(Millions)
)
)
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 quarter ended March 31, 2009: Derivatives
Not Designated as Hedges Location of Pre-Tax
Amount of Pre-Tax
(Millions) PSEG Energy-Related Contracts Operating Revenues
$
131 Energy-Related Contracts Energy Costs
(87
) Interest Rate Swaps Interest Expense
(1
) Derivatives in NDT Funds Other Income
9 Total PSEG
$
52 Power Energy-Related Contracts Operating Revenue
$
71 Energy-Related Contracts Energy Costs
(75
) Derivatives in NDT Funds Other Income
9 Total Power
$
5 Energy Holdings Energy-Related Contracts Operating Revenue
$
60 Energy-Related Contracts Energy Costs
(12
) Interest Rate Swap Interest Expense
(1
) Total Energy Holdings
$
47 Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of those contracts are marked-to-market in accordance with SFAS 133. The tables
above do not include contracts for which Power has elected the normal purchase/normal sales exemption under SFAS 133, such as its BGS contracts and certain other load-type contracts that it has with other utilities and companies with retail load. The following reflects the gross volume, on an absolute value basis, of derivatives as of March 31, 2009:
Type
Notional
Total
PSEG
Power
PSE&G
Energy
(Millions) Natural Gas
Dth
1,200
—
947
253
— Electricity
MWh
138
—
138
—
— Capacity
MW days
2
—
2
—
— FTRs
MWh
7
—
7
—
— Emissions Allowances
Tons
1
—
1
—
— Oil
Barrels
2
—
2
—
— Foreign Currency Option
Indian Rupees
800
—
—
—
800 Interest Rate Swaps
US Dollars
290
250
—
40
— 34
(UNAUDITED)
Gain (Loss)
Recognized in
Income on Derivatives
Gain (Loss)
Recognized in Income
on Derivatives
Holdings
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 8. Fair Value Measurements Effective January 1, 2008, PSEG, Power and PSE&G adopted SFAS No. 157, “Fair Value Measurements” (SFAS 157), except for non-financial assets and liabilities as described in FSP FAS 157-2. PSEG, Power and PSE&G adopted SFAS 157 for non-financial assets and liabilities on January 1,
2009. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own
assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities, exchange traded derivatives and certain U.S. government treasury securities. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals.
These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level
within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various financial transmission rights, other longer term capacity and transportation contracts and certain commingled securities. In addition to establishing a measurement framework, SFAS 157 nullifies the guidance of EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” which did not allow an entity to
recognize an unrealized gain or loss at the inception of a derivative instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions or based on a valuation
technique incorporating observable market data. 35
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following tables present information about PSEG’s, Power’s, and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis at March 31, 2009 and December 31, 2008, including the fair value measurements and the levels of inputs used in determining those fair
values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.
Recurring Fair Value Measurements as of March 31, 2009
Description
Total
Cash
Quoted Market Prices
Significant Other
Significant
(Millions) PSEG Assets: Derivative Contracts: Energy-Related Contracts (A)
$
362
$
(402
)
$
—
$
546
$
218 NDT Funds (C)
$
954
$
—
$
366
$
566
$
22 Rabbi Trusts (C)
$
136
$
—
$
8
$
113
$
15 Other Long-Term Investments (D)
$
1
$
—
$
1
$
—
$
— Liabilities: Derivative Contracts: Energy-Related Contracts (A)
$
(509
)
$
120
$
—
$
(577
)
$
(52
) Interest Rate Swaps (B)
$
(1
)
$
—
$
—
$
(1
)
$
— Power Assets: Derivative Contracts: Energy-Related Contracts (A)
$
322
$
(402
)
$
—
$
547
$
177 NDT Funds (C)
$
954
$
—
$
366
$
566
$
22 Rabbi Trusts (C)
$
27
$
—
$
2
$
22
$
3 Liabilities: Derivative Contracts: Energy-Related Contracts (A)
$
(454
)
$
120
$
—
$
(577
)
$
3 PSE&G Assets: Derivative Contracts: Energy-Related Contracts (A)
$
1
$
—
$
—
$
—
$
1 Rabbi Trusts (C)
$
47
$
—
$
3
$
39
$
5 Liabilities: Energy-Related Contracts (A)
$
(55
)
$
—
$
—
$
—
$
(55
) 36
(UNAUDITED)
Collateral
Netting (E)
of Identical Assets
(Level 1)
Observable Inputs
(Level 2)
Unobservable
Inputs
(Level 3)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Recurring Fair Value Measurements as of December 31, 2008
Description
Total
Cash
Quoted Market Prices
Significant Other
Significant
(Millions) PSEG Assets: Derivative Contracts: Energy-Related Contracts (A)
$
399
$
(154
)
$
—
$
439
*
114
*
NDT Funds (C)
$
970
$
—
$
413
$
516
$
41 Rabbi Trusts (C)
$
133
$
—
$
9
$
110
$
14 Other Long-Term Investments (D)
$
1
$
—
$
1
$
—
$
— Liabilities: Derivative Contracts: Energy-Related Contracts (A)
$
(510
)
$
42
$
—
$
(470
)*
$
(82
)* Interest Rate Swaps (B)
$
(10
)
$
—
$
—
$
(10
)
$
— Power Assets: Derivative Contracts: Energy-Related Contracts (A)
$
368
$
(154
)
$
—
$
450
*
$
72
* NDT Funds (C)
$
970
$
—
$
413
$
516
$
41 Rabbi Trusts (C)
$
27
$
—
$
2
$
22
$
3 Liabilities: Derivative Contracts: Energy-Related Contracts (A)
$
(449
)
$
42
$
—
$
(480
)*
$
(11
)* PSE&G Assets: Derivative Contracts: Energy-Related Contracts (A)
$
2
$
—
$
—
$
—
$
2 Rabbi Trusts (C)
$
46
$
—
$
3
$
38
$
5 Liabilities: Derivative Contracts: Energy-Related Contracts (A)
$
(66
)
$
—
$
—
$
—
$
(66
) Interest Rate Swaps (B)
$
(1
)
$
—
$
—
$
(1
)
$
—
*
The amounts shown in energy-related contract assets and liabilities in the table above have been corrected from such amounts shown in our 2008 Form 10-K to reflect a $22 million increase in the Level 2 net liability and corresponding increase in the Level 3 net asset. (A) Whenever possible, fair values for energy related contracts are obtained from quoted market sources in active markets. When this pricing is unavailable, contracts are valued using broker or dealer quotes or auction prices (primarily Level 2). For energy related contracts which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk
factors, as applicable (primarily Level 3). (B) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant
management judgment. (C) The NDT Funds and the Rabbi Trusts maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, 37
(UNAUDITED)
Collateral
Netting (E)
of Identical Assets
(Level 1)
Observable Inputs
(Level 2)
Unobservable Inputs
(Level 3)
$
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases
midpoint, bid or ask price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued based upon internal matrices using observable market prices or market
parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). (D) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices. (E) Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under FIN 39-1. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis Description
Balance as of
Total Gains or (Losses)
Purchases and
Balance
Included in
Included in
(Millions) PSEG Net Derivative Assets
$
32
$
131
$
10
$
(7
)
$
166 NDT Funds
$
41
$
—
$
—
$
(19
)
$
22 Rabbi Trust Funds
$
14
$
—
$
—
$
1
$
15 Power Net Derivative Assets
$
61
$
126
$
—
$
(7
)
$
180 NDT Funds
$
41
$
—
$
—
$
(19
)
$
22 Rabbi Trust Funds
$
3
$
—
$
—
$
—
$
3 PSE&G Net Derivative Liabilities
$
(64
)
$
—
$
10
$
—
$
(54
) Rabbi Trust Funds
$
5
$
—
$
—
$
—
$
5
(A)
PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $102 million is included in Operating Revenues and $29 million is included in Other Comprehensive Income. Of the $102 million in Operating Revenues, $5 million (unrealized) is at
PSEG Texas and $ 97 million (unrealized) is at Power. The $29 million included in Other Comprehensive Income is at Power. (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset and are expected to be recovered from PSE&G’s customers. As of March 31, 2009, PSEG carried approximately $943 million of net assets that are measured at fair value on a recurring basis, of which approximately $203 million were measured using unobservable inputs 38
(UNAUDITED)
for the Quarter Ended March 31, 2009
January 1,
2009
Realized/Unrealized
(Sales) and
Settlements
March 31,
2009
Income (A)
Regulatory Assets/
Liabilities (B)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets. Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis Description
Balance as of
Total Gains or (Losses)
Purchases/
Balance
Included in
Included in
(Millions) PSEG Net Derivative Assets/(Liabilities)
$
(11
)
$
18
$
(22
)
$
9
$
(6
) NDT Funds
$
27
$
(1
)
$
—
$
1
$
27 Rabbi Trust Funds
$
16
$
—
$
—
$
(2
)
$
14 Power Net Derivative Assets/(Liabilities)
$
10
$
(15
)
$
—
$
9
$
4 NDT Funds
$
27
$
(1
)
$
—
$
1
$
27 Rabbi Trust Funds
$
3
$
—
$
—
$
—
$
3 PSE&G Net Derivative Assets/(Liabilities)
$
(49
)
$
—
$
(22
)
$
—
$
(71
) Rabbi Trust Funds
$
6
$
—
$
—
$
(1
)
$
5
(A)
PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $22 million is included in Operating Revenues and $(4) million is included in Other Comprehensive Income. Of the $22 million in Operating Revenues, $33 million (unrealized) is at
PSEG Texas and $(11) million (of which $(10) is unrealized) is at Power. The $(4) million included in Other Comprehensive Income is at Power. (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset and are expected to be recovered from PSE&G’s customers. As of March 31, 2008, PSEG carried approximately $911 million of net assets that are measured at fair value on a recurring basis, of which approximately $35 million are measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets
represent less than 1% of PSEG’s total assets. 39
(UNAUDITED)
for the Quarter Ended March 31, 2008
January 1,
2008
Realized/Unrealized
(Sales) and
Settlements
March 31,
2008
Income (A)
Regulatory Assets/
Liabilities (B)
NOTES TO CONDENSED CONSOLIDATED STATEMENTS Note 9. Other Income and Deductions
Other Income:
Power
PSE&G
Other (A)
Consolidated
(Millions) Quarter Ended March 31, 2009 NDT Fund Realized Gains
$
50
$
—
$
—
$
50 NDT Interest, Dividend and Other Income
17
—
—
17 Other Interest and Dividend Income
3
—
(1
)
2 Other
—
1
1
2 Total Other Income
$
70
$
1
$
—
$
71 Quarter Ended March 31, 2008 NDT Fund Realized Gains
$
75
$
—
$
—
$
75 NDT Interest, Dividend and Other Income
8
—
—
8 Other Interest and Dividend Income
2
2
1
5 Other
1
3
1
5 Total Other Income
$
86
$
5
$
2
$
93 Other Deductions: Quarter Ended March 31, 2009 NDT Fund Realized Losses and Expenses
$
46
$
—
$
—
$
46 Loss on Disposition of Assets
4
—
—
4 Other-Than-Temporary Impairment of Investments
60
—
—
60 Other
—
1
4
5 Total Other Deductions
$
110
$
1
$
4
$
115 Quarter Ended March 31, 2008 NDT Fund Realized Losses and Expenses
$
53
$
—
$
—
$
53 Other-Than-Temporary Impairment of Investments
38
—
—
38 Other
—
1
3
4 Total Other Deductions
$
91
$
1
$
3
$
95
(A)
Other primarily consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations.
PSEG’s effective tax rate for the quarter ended March 31, 2009 was 40.6% as compared to 34.9% for the quarter ended March 31, 2008. The increase in the effective tax rate was primarily due to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim and the sale of
leveraged lease assets in 2009. Power’s effective tax rate for the quarter ended March 31, 2009 was 39.3% as compared to 40.5% for the quarter ended March 31, 2008. The decrease in the effective tax rate was due to primarily due to lower earnings in the Nuclear Decommissioning Trust Funds and increased benefits of a
manufacturing deduction under the American Jobs Creation Act of 2004. 40
(UNAUDITED)
Total
NOTES TO CONDENSED CONSOLIDATED STATEMENTS PSE&G’s effective tax rate for the quarter ended March 31, 2009 was 40.7% as compared to 32.2% for the quarter ended March 31, 2008. The increase in the effective tax rate was primarily due to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim. PSEG, Power and PSE&G have $1,359 million, $17 million and $26 million, respectively of unrecognized tax benefits as of March 31, 2009 which have not materially changed since December 31, 2008. It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease by approximately $168 million within the next 12 months due to either agreement with various taxing authorities upon audit or the expiration of the Statute of Limitations. This amount
includes a $13 million decrease for Power, a $7 million decrease for PSE&G, a $25 million decrease for Services, a $128 million decrease for Energy Holdings and a $5 million increase for PSEG. Note 11. Comprehensive Income (Loss), Net of Tax
Power (A)
PSE&G
Other (B)
Consolidated
(Millions) Quarter Ended March 31, 2009: Net Income
$
318
$
124
$
2
$
444 Other Comprehensive Income
132
—
14
146 Comprehensive Income
$
450
$
124
$
16
$
590 Quarter Ended March 31, 2008: Net Income
$
275
$
137
$
36
$
448 Other Comprehensive Income (Loss)
(272
)
—
52
(220
) Comprehensive Income
$
3
$
137
$
88
$
228
(A)
Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2009 and 2008, as detailed below. (B) Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. Accumulated Other Comprehensive Income (Loss):
Balance as of
Power
PSE&G
Other
Balance as of
(Millions) Quarter Ended March 31, 2009: Derivative Contracts
$
172
$
124
$
—
$
13
$
309 Pension and OPEB Plans
(371
)
6
—
—
(365
) NDT Funds
18
2
—
—
20 Other
4
—
—
1
5
$
(177
)
$
132
$
—
$
14
$
(31
) 41
(UNAUDITED)
Total
December 31, 2008
March 31, 2009
NOTES TO CONDENSED CONSOLIDATED STATEMENTS
Balance as of
Power
PSE&G
Other
Balance as of
(Millions) Quarter Ended March 31, 2008: Derivative Contracts
$
(259
)
$
(242
)
$
—
$
(4
)
$
(505
) Pension and OPEB Plans
(167
)
—
—
—
(167
) Currency Translation Adjustment
107
—
—
56
163 NDT Funds
97
(30
)
(UNAUDITED)
December 31, 2007
March 31, 2008