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 June 30, 2009
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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Commission | Registrants, State of Incorporation, | I.R.S. Employer Identification No. | ||
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. YesS No£
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
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Public Service Enterprise Group Incorporated |
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PSEG Power LLC |
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Public Service Electric and Gas Company |
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(Cover continued on next page)
(Cover continued from previous page) Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Public Service Enterprise Group Incorporated Large accelerated filerS Accelerated filer£ Non-accelerated filer£ Smaller reporting company£ PSEG Power LLC Large accelerated filer£ Accelerated filer£ Non-accelerated filerS Smaller reporting company£ Public Service Electric Large accelerated filer£ Accelerated filer£ Non-accelerated filerS 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£ NoS As of July 15, 2009, Public Service Enterprise Group Incorporated had outstanding 505,981,904 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 July 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 Financial Statements 1 5 8 12 13 16 17 22 23 34 35 42 49 50 52 53 54 55 57 Management’s Discussion and Analysis of Financial Condition and Results of Operations 60 64 73 76 77 Qualitative and Quantitative Disclosures About Market Risk 77 Controls and Procedures 80 Legal Proceedings 81 Risk Factors 81 Unregistered Sales of Equity Securities and Use of Proceeds 82 Other Information 82 Exhibits 85 86 i
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 6. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to: • adverse changes in energy industry, law, policies and regulation, including market structures and rules, and reliability standards • any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, • changes in federal and/or state environmental requirements that could increase our costs or limit operations of our generating units, • changes in nuclear regulation and/or developments in the nuclear power industry generally, that could limit operations of our nuclear generating units, • actions or activities at one of our nuclear units that might adversely affect our ability to continue to operate that unit or other units at the same site, • any inability to balance our energy obligations, available supply and trading risks, • any deterioration in our credit quality, • availability of capital and credit at reasonable pricing terms and our ability to meet cash needs, • any inability to realize anticipated tax benefits or retain tax credits, • 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, and • changes in technology and/or increased customer conservation. Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors. All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. ii
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED For The Three Months For the Six Months 2009 2008 2009 2008 OPERATING REVENUES $ 2,561 $ 2,550 $ 6,482 $ 6,342 OPERATING EXPENSES Energy Costs 1,067 1,535 3,135 3,654 Operation and Maintenance 628 620 1,303 1,247 Depreciation and Amortization 203 191 410 383 Taxes Other Than Income Taxes 26 27 70 70 Total Operating Expenses 1,924 2,373 4,918 5,354 OPERATING INCOME 637 177 1,564 988 Income from Equity Method Investments 9 7 19 19 Impairment on Equity Method Investments (8 ) — (8 ) — Other Income 91 97 162 190 Other Deductions (44 ) (56 ) (99 ) (113 ) Other Than Temporary Impairments (1 ) (32 ) (61 ) (70 ) Interest Expense (133 ) (146 ) (278 ) (299 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 551 47 1,299 715 Income Tax Expense (240 ) (213 ) (544 ) (446 ) INCOME (LOSS) FROM CONTINUING OPERATIONS 311 (166 ) 755 269 Income from Discontinued Operations, net of tax expense of $5 and $13 for the three and six months ended 2008 — 16 — 29 NET INCOME (LOSS) $ 311 $ (150 ) $ 755 $ 298 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC 505,990 508,491 505,988 508,491 DILUTED 506,936 509,487 506,812 509,483 EARNINGS PER SHARE: BASIC INCOME (LOSS) FROM CONTINUING OPERATIONS $ 0.61 $ (0.32 ) $ 1.49 $ 0.53 NET INCOME (LOSS) $ 0.61 $ (0.29 ) $ 1.49 $ 0.59 DILUTED INCOME (LOSS) FROM CONTINUING OPERATIONS $ 0.61 $ (0.32 ) $ 1.49 $ 0.53 NET INCOME (LOSS) $ 0.61 $ (0.29 ) $ 1.49 $ 0.59 DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.3325 $ 0.3225 $ 0.6650 $ 0.6450 See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except Share Data)
(Unaudited)
Ended June 30,
Ended June 30,
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED June 30, December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 393 $ 321 Accounts Receivable, net of allowances of $69 and $66 in 2009 and 2008, respectively 1,271 1,398 Unbilled Revenues 303 454 Fuel 730 938 Materials and Supplies 343 317 Prepayments 465 150 Restricted Funds 10 118 Derivative Contracts 259 237 Other 60 66 Total Current Assets 3,834 3,999 PROPERTY, PLANT AND EQUIPMENT 21,519 20,818 Less: Accumulated Depreciation and Amortization (6,620 ) (6,385 ) Net Property, Plant and Equipment 14,899 14,433 NONCURRENT ASSETS Regulatory Assets 6,022 6,352 Long-Term Investments 2,309 2,695 Nuclear Decommissioning Trust (NDT) Funds 1,059 970 Other Special Funds 140 133 Goodwill 16 16 Other Intangibles 108 53 Derivative Contracts 154 160 Other 219 238 Total Noncurrent Assets 10,027 10,617 TOTAL ASSETS $ 28,760 $ 29,049 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED June 30, December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 746 $ 1,033 Commercial Paper and Loans 333 19 Accounts Payable 941 1,227 Derivative Contracts 310 356 Accrued Interest 100 99 Accrued Taxes 206 8 Clean Energy Program 159 142 Obligation to Return Cash Collateral 96 102 Other 430 424 Total Current Liabilities 3,321 3,410 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 4,046 3,865 Regulatory Liabilities 396 355 Asset Retirement Obligations 595 576 Other Postretirement Benefit (OPEB) Costs 968 975 Accrued Pension Costs 877 1,196 Clean Energy Program 451 532 Environmental Costs 730 743 Derivative Contracts 106 164 Long-Term Accrued Taxes 856 1,241 Other 130 125 Total Noncurrent Liabilities 9,155 9,772 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) CAPITALIZATION Long-Term Debt 6,515 6,621 Securitization Debt 1,250 1,342 Project Level, Non-Recourse Debt 40 42 Total Long-Term Debt 7,805 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 4,772 4,756 Treasury Stock, at cost, 2009—27,571,375 shares; (587 ) (581 ) Retained Earnings 4,204 3,773 Accumulated Other Comprehensive Loss — (177 ) Total Common Stockholders’ Equity 8,389 7,771 Noncontrolling Interest—Equity Investments 10 11 Total Capitalization 16,284 15,867 TOTAL LIABILITIES AND CAPITALIZATION $ 28,760 $ 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 Six Months 2009 2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 755 $ 298 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 410 387 Amortization of Nuclear Fuel 57 48 Provision for Deferred Income Taxes (Other than Leases) and ITC 139 90 Non-Cash Employee Benefit Plan Costs 173 84 Lease Transaction Charges, net of tax — 490 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (364 ) (23 ) Gain on Sale of Investments (99 ) (1 ) Undistributed Earnings from Affiliates (11 ) (37 ) Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives (71 ) (50 ) Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs 8 (66 ) Over (Under) Recovery of Societal Benefits Charge (SBC) 47 (12 ) Cost of Removal (23 ) (20 ) Net Realized (Gains) Losses and Expense from NDT Funds (3 ) 5 Net Change in Certain Current Assets and Liabilities 307 (585 ) Employee Benefit Plan Funding and Related Payments (409 ) (30 ) Other (127 ) 45 Net Cash Provided By Operating Activities 789 623 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (816 ) (739 ) Proceeds from the Sale of Capital Leases and Investments 510 41 Proceeds from NDT Funds Sales 1,475 1,257 Investment in NDT Funds (1,491 ) (1,271 ) Restricted Funds 108 — NDT Funds Interest and Dividends 21 24 Other (17 ) (14 ) Net Cash Used In Investing Activities (210 ) (702 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans 314 854 Issuance of Long-Term Debt 209 700 Redemptions of Long-Term Debt (320 ) (1,263 ) Repayment of Non-Recourse Debt (283 ) (22 ) Redemption of Securitization Debt (87 ) (82 ) Net Premium Paid on Early Extinguishment of Debt — (80 ) Cash Dividends Paid on Common Stock (336 ) (328 ) Other (4 ) 3 Net Cash Used In Financing Activities (507 ) (218 ) Effect of Exchange Rate Change — 1 Net Increase (Decrease) in Cash and Cash Equivalents 72 (296 ) Cash and Cash Equivalents at Beginning of Period 321 380 Cash and Cash Equivalents at End of Period $ 393 $ 84 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 613 $ 454 Interest Paid, Net of Amounts Capitalized $ 254 $ 279 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended June 30,
PSEG POWER LLC For the Three Months For the Six Months 2009 2008 2009 2008 OPERATING REVENUES $ 1,301 $ 1,623 $ 3,675 $ 3,998 OPERATING EXPENSES Energy Costs 563 867 2,025 2,456 Operation and Maintenance 271 275 529 514 Depreciation and Amortization 48 41 95 79 Total Operating Expenses 882 1,183 2,649 3,049 OPERATING INCOME 419 440 1,026 949 Other Income 86 93 156 179 Other Deductions (44 ) (55 ) (94 ) (108 ) Other Than Temporary Impairments — (32 ) (60 ) (70 ) Interest Expense (39 ) (41 ) (82 ) (83 ) INCOME BEFORE INCOME TAXES 422 405 946 867 Income Tax Expense (165 ) (165 ) (371 ) (352 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 257 $ 240 $ 575 $ 515 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
(Unaudited)
Ended June 30,
Ended June 30,
PSEG POWER LLC June 30, December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 20 $ 20 Accounts Receivable 362 472 Accounts Receivable—Affiliated Companies, net 499 732 Short-Term Loan to Affiliate 142 — Fuel 730 938 Materials and Supplies 247 233 Derivative Contracts 230 225 Restricted Funds 10 21 Prepayments 40 53 Other 2 11 Total Current Assets 2,282 2,705 PROPERTY, PLANT AND EQUIPMENT 7,770 7,441 Less: Accumulated Depreciation and Amortization (2,068 ) (1,960 ) Net Property, Plant and Equipment 5,702 5,481 NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Funds 1,059 970 Goodwill 16 16 Other Intangibles 99 43 Other Special Funds 28 27 Derivative Contracts 145 143 Other 75 74 Total Noncurrent Assets 1,422 1,273 TOTAL ASSETS $ 9,406 $ 9,459 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year $ — $ 250 Accounts Payable 513 752 Short-Term Loan from Affiliate — 3 Derivative Contracts 300 338 Accrued Interest 38 35 Other 159 155 Total Current Liabilities 1,010 1,533 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 567 335 Asset Retirement Obligations 347 334 Other Postretirement Benefit (OPEB) Costs 124 118 Derivative Contracts 62 111 Accrued Pension Costs 277 374 Environmental Costs 54 54 Long-Term Accrued Taxes 4 16 Other 59 47 Total Noncurrent Liabilities 1,494 1,389 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) 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 2,976 2,988 Accumulated Other Comprehensive Income (Loss) 50 (118 ) Total Member’s Equity 4,040 3,884 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 9,406 $ 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 Six Months 2009 2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 575 $ 515 Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization 95 79 Amortization of Nuclear Fuel 57 48 Interest Accretion on Asset Retirement Obligations 13 12 Provision for Deferred Income Taxes and ITC 79 70 Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives (76 ) (68 ) Non-Cash Employee Benefit Plan Costs 39 12 Net Realized (Gains) Losses and (Income) Expense from NDT Funds (3 ) 5 Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies 194 (43 ) Margin Deposit Asset (60 ) (389 ) Margin Deposit Liability 114 14 Accounts Receivable 296 (54 ) Accounts Payable (187 ) 139 Accounts Receivable/Payable-Affiliated Companies, net 233 138 Accrued Interest Payable 3 — Other Current Assets and Liabilities (42 ) (31 ) Employee Benefit Plan Funding and Related Payments (111 ) (1 ) Other (19 ) 20 Net Cash Provided By Operating Activities 1,200 466 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (425 ) (384 ) Short-Term Loan—Affiliated Company, net (142 ) — Proceeds from NDT Funds Sales 1,475 1,257 NDT Funds Interest and Dividends 21 24 Investment in NDT Funds (1,491 ) (1,271 ) Restricted Funds 11 13 Other (5 ) (11 ) Net Cash Used In Investing Activities (556 ) (372 ) CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Recourse Long-Term Debt 209 — Cash Dividend Paid (600 ) (250 ) Redemption of Long-term Debt (250 ) — Short-Term Loan—Affiliated Company, net (3 ) 162 Net Cash Used In Financing Activities (644 ) (88 ) Net Increase in Cash and Cash Equivalents — 6 Cash and Cash Equivalents at Beginning of Period 20 11 Cash and Cash Equivalents at End of Period $ 20 $ 17 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 312 $ 261 Interest Paid, Net of Amounts Capitalized $ 78 $ 80 See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements. 7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended June 30,
Operating Activities:
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For the Three Months For the Six Months 2009 2008 2009 2008 OPERATING REVENUES $ 1,643 $ 1,858 $ 4,378 $ 4,476 OPERATING EXPENSES Energy Costs 979 1,213 2,838 3,006 Operation and Maintenance 344 320 739 680 Depreciation and Amortization 144 139 293 282 Taxes Other Than Income Taxes 26 27 70 70 Total Operating Expenses 1,493 1,699 3,940 4,038 OPERATING INCOME 150 159 438 438 Other Income 4 2 5 7 Other Deductions (1 ) — (2 ) (1 ) Interest Expense (80 ) (81 ) (159 ) (162 ) INCOME BEFORE INCOME TAXES 73 80 282 282 Income Tax Expense (29 ) (28 ) (114 ) (93 ) NET INCOME 44 52 168 189 Preferred Stock Dividends (1 ) (1 ) (2 ) (2 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 43 $ 51 $ 166 $ 187 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 June 30,
Ended June 30,
PUBLIC SERVICE ELECTRIC AND GAS COMPANY June 30, December 31, ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 23 $ 91 Accounts Receivable, net of allowances of $69 in 2009 and $65 in 2008, respectively 875 909 Unbilled Revenues 303 454 Materials and Supplies 69 61 Prepayments 391 45 Restricted Funds — 1 Deferred Income Taxes 54 52 Total Current Assets 1,715 1,613 PROPERTY, PLANT AND EQUIPMENT 12,623 12,258 Less: Accumulated Depreciation and Amortization (4,232 ) (4,122 ) Net Property, Plant and Equipment 8,391 8,136 NONCURRENT ASSETS Regulatory Assets 6,022 6,352 Long-Term Investments 173 158 Other Special Funds 48 46 Other 92 101 Total Noncurrent Assets 6,335 6,657 TOTAL ASSETS $ 16,441 $ 16,406 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 9
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
2009
2008
PUBLIC SERVICE ELECTRIC AND GAS COMPANY June 30, December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 492 $ 248 Commercial Paper and Loans 333 19 Accounts Payable 327 336 Accounts Payable—Affiliated Companies, net 415 763 Accrued Interest 56 58 Accrued Taxes 3 3 Clean Energy Program 159 142 Derivative Contracts 10 14 Obligation to Return Cash Collateral 96 102 Other 242 227 Total Current Liabilities 2,133 1,912 NONCURRENT LIABILITIES Deferred Income Taxes and ITC 2,591 2,533 Other Postretirement Benefit (OPEB) Costs 798 813 Accrued Pension Costs 447 634 Regulatory Liabilities 396 355 Clean Energy Program 451 532 Environmental Costs 676 689 Asset Retirement Obligations 246 240 Derivative Contracts 28 53 Long-Term Accrued Taxes 88 82 Other 29 31 Total Noncurrent Liabilities 5,750 5,962 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 6) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 3,164 3,463 Securitization Debt 1,250 1,342 Total Long-Term Debt 4,414 4,805 Preferred Stock Without Mandatory Redemption, 80 80 STOCKHOLDERS’ EQUITY Common Stock; 150,000,000 shares authorized; 892 892 Contributed Capital 420 170 Basis Adjustment 986 986 Retained Earnings 1,763 1,597 Accumulated Other Comprehensive Income 3 2 Total Stockholders’ Equity 4,064 3,647 Total Capitalization 8,558 8,532 TOTAL LIABILITIES AND CAPITALIZATION $ 16,441 $ 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
issued and outstanding, 2009 and 2008—132,450,344 shares
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For The Six Months 2009 2008 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 168 $ 189 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 293 282 Provision for Deferred Income Taxes and ITC 51 23 Non-Cash Employee Benefit Plan Costs 118 65 Cost of Removal (23 ) (20 ) Employee Benefit Plan Funding and Related Payments (255 ) (28 ) Under Recovery of Electric Energy Costs (BGS and NTC) (45 ) (12 ) Over (Under) Recovery of Gas Costs 53 (54 ) Over (Under) Recovery of SBC 47 (12 ) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues 184 128 Materials and Supplies (8 ) (10 ) Prepayments (346 ) (304 ) Accrued Taxes 1 (26 ) Accounts Payable (9 ) 74 Accounts Receivable/Payable-Affiliated Companies, net (316 ) (191 ) Obligation to Return Cash Collateral (6 ) 178 Other Current Assets and Liabilities 4 (6 ) Other (6 ) 6 Net Cash (Used In) Provided By Operating Activities (95 ) 282 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (379 ) (345 ) Other (9 ) — Net Cash Used In Investing Activities (388 ) (345 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 314 135 Issuance of Long-Term Debt — 700 Redemption of Long-Term Debt (60 ) (651 ) Redemption of Securitization Debt (87 ) (82 ) Contributed Capital 250 — Deferred Issuance Costs — (4 ) Premium Paid on Early Retirement of Debt — (32 ) Preferred Stock Dividends (2 ) (2 ) Net Cash Provided By Financing Activities 415 64 Net (Decrease) Increase In Cash and Cash Equivalents (68 ) 1 Cash and Cash Equivalents at Beginning of Period 91 32 Cash and Cash Equivalents at End of Period $ 23 $ 33 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 41 $ 40 Interest Paid, Net of Amounts Capitalized $ 153 $ 153 See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements. 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
Ended June 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G each is only responsible for information about itself and its subsidiaries. Note 1. Organization and Basis of Presentation Organization PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s four principal direct wholly owned subsidiaries are: • Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management 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. • 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. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in which they operate. Energy Holdings is also exploring opportunities for investment in renewable generation projects. • PSEG Services Corporation (Services)—which provides management and administrative and general services to PSEG and its subsidiaries. Basis of Presentation The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, PSEG’s, Power’s and PSE&G’s respective Annual Report on Form 10-K for the year ended December 31, 2008 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2009. The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2008. Reclassifications Certain reclassifications were made to the prior period financial statements in accordance with new accounting guidance adopted in 2009. Minority interests of $11 million were reclassified from Other 12
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Noncurrent Liabilities to Noncontrolling Interests in PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2008. In addition, other-than-temporary impairments related to Power’s credit losses on available-for-sale debt securities in its Nuclear Decommissioning Trust (NDT) Funds were reclassified from Other Deductions to a separate line caption in the Condensed Consolidated Statement of Operations of PSEG and Power, for the three and six months ended June 30, 2008. Certain reclassifications have also been made to the prior period financial statements to conform to the current presentation. Operating results for Bioenergie S.p.A. (Bioenergie) were reclassified to Income (Loss) from Discontinued Operations in the Consolidated Statements of Operations of PSEG for the three and six months ended June 30, 2008. See Note 3. Discontinued Operations and Dispositions. Income from Equity Method Investments, as well as any impairments or gain/losses on the sale of equity method investments which were reflected in Operating Revenues and Operating Expenses prior to the fourth quarter of 2008, have been reclassified to below Operating Income in the Consolidated Statements of Operations of PSEG for the three and six months ended June 30, 2008 since these equity method investments are no longer an integral part of the business. 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. The new accounting guidance adopted in 2009 did not 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, • applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree, • requires all assets acquired and liabilities assumed in a business combination to be measured at their acquisition date fair value, with limited exceptions, and • requires acquisition-related costs and certain restructuring costs to be recognized separately from the business combination. 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 non-controlling 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, and 13
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS • applies prospectively, except for presentation and disclosure requirements, which are applied retrospectively. We adopted SFAS 160 effective January 1, 2009 and revised the balance sheet and income statement presentations as required by the standard. The income statement impact was 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. For additional information / disclosures, see Note 8. Financial Risk Management Activities. SFAS No. 165, “Subsequent Events” (SFAS 165) • establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued and • requires the disclosure of the date through which subsequent events have been evaluated and whether that date is the date on which the financial statements were issued or the date on which the financial statements were available to be issued. We adopted SFAS 165 effective for our second quarter 2009 reporting. We evaluated any subsequent events through July 31, 2009, which is the date the financial statements were issued. 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) • revises recognition guidance in determining whether a debt security is other-than-temporarily impaired. A debt security is considered other-than-temporarily impaired in either of the following circumstances if the fair value is less than the amortized cost:
(UNAUDITED) ¡
An entity has an intent to sell the security, or it is more likely than not that an entity will be required to sell the security prior to the recovery of its amortized cost basis or
¡
an entity does not expect to recover the entire amortized cost basis of the security.
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| provides further guidance to determine the amount of impairment to be recorded in earnings (credit-related loss) and/ or Accumulated Other Comprehensive Income/(Loss) (non-credit related loss). | ||||||||||||||||||
We adopted FSP FAS 115-2 and FAS 124-2 effective April 1, 2009 and recorded a cumulative-effect adjustment to reclassify $12 million of non-credit losses, net-of-tax, from retained earnings to Accumulated Other Comprehensive Income (Loss). The expanded disclosures related to FSP FAS 115-2 and FAS 124-2 are included in Note 4. Available-for-Sale Securities.
FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1)
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requires a publicly traded company to disclose the following information, in the notes to the financial statements:
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fair value of its financial instruments in interim and annual reporting periods, together with the related carrying amounts,
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ¡ methods and significant assumptions used to estimate the fair value, and ¡ changes in methods and significant assumptions, if any. We adopted FSP FAS 107-1 and APB 28-1 effective April 1, 2009. For additional information / disclosures, see Note 9. Fair Value Measurements. 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)
(UNAUDITED) •
provides guidance:
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| to determine if there has been a significant decrease in the volume and level of activity for the asset or liability and | ||||||||||||||||||
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| to estimate fair values, when transactions or quoted prices are not determinative of fair value. | ||||||||||||||||||
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| 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. | ||||||||||||||||||
We adopted FSP FAS 157-4 effective April 1, 2009. For additional information / disclosures, see Note 9. Fair Value Measurements.
Accounting standards to be adopted effective for third quarter 2009 reporting
SFAS No. 168, “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles—a replacement of FASB Statement No. 162” (SFAS 168)
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| the single source of authoritative non-governmental U.S. GAAP other than the SEC rules, regulations, interpretive releases and the SEC staff guidance, | ||||||||||||||||||
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| does not change current U.S. GAAP, but is intended to simplify user access to all authoritative U.S. GAAP by providing all the authoritative literature related to a particular topic in one place, and | ||||||||||||||||||
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| will not have any impact on our financial condition or results of operations. We are currently evaluating the impact to our financial reporting process which includes providing accounting references in our SEC filings and other documents. We anticipate eliminating specific accounting references and replacing them with more general topical references. | ||||||||||||||||||
Accounting standard to be adopted effective for 2009 year-end reporting
FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132(R)-1)
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| issued by the FASB in December 2008, | ||||||||||||||||||
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| requires additional disclosures about the fair value of plan assets of a defined benefit pension or other postretirement plan, including: | ||||||||||||||||||
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15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS ¡ 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 do not anticipate that this guidance will have a material impact on our financial statements. Accounting standards to be adopted effective January 1, 2010 SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (SFAS 167) • issued by the FASB in June 2009, • removes the exception from applying consolidation guidance to qualifying special-purpose entities, • requires ongoing assessment of the Company’s involvement in the activities of a Variable Interest Entity (VIE), and • amends the criteria in determination of a primary beneficiary, such that a primary beneficiary would be an enterprise with ¡ the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE and ¡ the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. We are currently evaluating the 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 and six months ended June 30, 2008, which were reclassified to Discontinued Operations, are summarized below: Three Months Ended Six Months Ended Millions Operating Revenues $ 11 $ 22 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 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. 16
(UNAUDITED)
June 30,
2008
June 30,
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS SAESA Group’s operating results for the quarter and six months ended June 30, 2008, which are included in Discontinued Operations, are summarized below: Three Months Ended Six Months Ended Millions Operating Revenues $ 156 $ 342 Income Before Income Taxes $ 21 $ 41 Net Income $ 16 $ 30 Dispositions GWF Energy LLC (GWF Energy) In May 2009, Energy Holdings entered into a Memorandum of Understanding under which it will sell, in two separate transactions, its 60% ownership interest in GWF Energy, an equity method investment, for a total purchase price of $70 million. As a result, Energy Holdings recorded an after- tax impairment charge of $3 million. Energy Holdings completed the first stage of the sale in June 2009, selling a 10.1% interest in GWF Energy for approximately $7 million. The sale of Energy Holdings’ remaining 49.9% interest is subject to certain conditions, including the execution of a new power purchase agreement (PPA) with its customer and the related approval of the PPA by the California Public Utilities Commission. PPN Power Generating Company Limited (PPN) In May 2009, Energy Holdings sold its 20% ownership interest in PPN, which owns and operates a 330 MW generation facility in India for approximately book value. Leveraged Leases In the first six months of 2009, Energy Holdings sold its interest in nine leveraged leases with a combined book value of approximately $369 million, including seven international leases for which the IRS has disallowed deductions taken in prior years. Total proceeds for the sales were approximately $460 million and resulted in an after-tax gain of $35 million. Proceeds from these transactions are being used to reduce Energy Holdings’ tax exposure related to these lease investments. For additional information see Note 6. Commitments and Contingent Liabilities. Other In May 2009, Energy Holdings sold its 6.5% interest in the Midland Cogeneration Venture LP (MCV) for an after-tax gain of $2 million. Note 4. Available-for-Sale Securities NDT Funds In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. Power maintains the external master nuclear decommissioning trust which contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of 17
(UNAUDITED)
June 30,
2008
June 30,
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS money that can be contributed into a qualified fund. In the most recent study of the total cost of decommissioning, Power’s share related to its five nuclear units was estimated at approximately $2.1 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of June 30, 2009 was approximately $309 million and is included in the Asset Retirement Obligation (ARO). The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power’s NDT Investment Committee. Power classifies investments in the NDT Funds as available-for-sale under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” (SFAS 115). The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Funds. As of June 30, 2009 Cost Gross Gross Estimated Millions Equity Securities $ 441 $ 88 $ (2 ) $ 527 Debt Securities Government Obligations 296 4 (4 ) 296 Other Debt Securities 212 14 (20 ) 206 Total Debt Securities 508 18 (24 ) 502 Other Securities 30 — — 30 Total Available-for-Sale Securities $ 979 $ 106 $ (26 ) $ 1,059 As of December 31, 2008 Cost Gross Gross Estimated Millions Equity Securities $ 386 $ 32 $ (5 ) $ 413 Debt Securities Government Obligations 192 3 — 195 Other Debt Securities 284 6 — 290 Total Debt Securities 476 9 — 485 Other Securities 72 1 (1 ) 72 Total Available-for-Sale Securities $ 934 $ 42 $ (6 ) $ 970 18
(UNAUDITED)
Unrealized
Gains
Unrealized
Losses
Fair Value
Unrealized
Gains
Unrealized
Losses
Fair Value
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table shows the value of securities in the NDT Funds that have been in an unrealized position for less than 12 months, or for 12 months or longer. As of As of As of Fair Gross Fair Gross Fair Gross Millions Equity Securities (A) $ — $ — $ 43 $ (2 ) $ 85 $ (5 ) Debt Securities Government Obligations (B) — — 148 (4 ) — — Other Debt Securities (C) 57 (13 ) 86 (7 ) — — Total Debt Securities 57 (13 ) 234 (11 ) — — Other Securities — — — — — (1 ) Total Available-for-Sale Securities $ 57 $ (13 ) $ 277 $ (13 ) $ 85 $ (6 ) * There were no gross unrealized losses as of December 31, 2008 for 12 months or longer. (A) Equity Securities—Investments in marketable equity securities within the NDT fund are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over several hundred companies with an impairment duration of three months or less and a severity that is generally ten percent or less than cost. The Company does not consider these securities to be other-than-temporarily impaired as of June 30, 2009. (B) Debt Securities (Government)—Unrealized losses on Power’s NDT investments in US Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the US government or an agency of the US government, it is not expected that these securities will settle for less that their amortized cost basis, assuming the Company does not intend to sell nor will they be more likely than not required to sell. The Company does not consider these securities to be other-than-temporarily impaired as of June 30, 2009. (C) Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily with investment grade securities. It is not expected that these securities would settle at less than their amortized cost. Since the Company does not intend to sell these securities nor will they be more likely than not required to sell, the company does not consider these debt securities to be other-than-temporarily impaired as of June 30, 2009. 19
(UNAUDITED)
June 30, 2009
Greater Than
12 Months
June 30, 2009
Less Than
12 Months
December 31, 2008
Less Than
12 Months*
Value
Unrealized
Losses
Value
Unrealized
Losses
Value
Unrealized
Losses
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The proceeds from the sales of and the net realized gains on securities in the NDT Funds were: Three Months Three Months Six Months Six Months Millions Proceeds from Sales $ 917 $ 634 $ 1,475 $ 1,257 Net Realized Gains (Losses): Gross Realized Gains $ 82 $ 78 $ 127 $ 147 Gross Realized Losses (65 ) (51 ) (111 ) (103 ) Net Realized Gains $ 17 $ 27 $ 16 $ 44 Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in Power’s Consolidated Statement of Operations. Net unrealized gains of $40 million (after-tax) were recognized in Accumulated Other Comprehensive Income in Power’s Consolidated Balance Sheet as of June 30, 2009. The available-for-sale debt securities held as of June 30, 2009 had the following maturities: • $5 million less than one year, • $64 million after one through five years, • $96 million after five through 10 years, $58 million after 10 through 15 years, and • $16 million after 15 through 20 years, and $263 million over 20 years. The cost of these securities was determined on the basis of specific identification. Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Other Comprehensive Income (OCI). In 2009, other-than-temporary impairments of $60 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities are recognized in OCI. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities. Rabbi Trusts PSEG maintains certain unfunded nonqualified benefit plans; assets have been set aside in grantor trusts commonly known as “Rabbi Trusts” to provide supplemental retirement and deferred compensation benefits to certain of its and its subsidiaries’ key employees. 20
(UNAUDITED)
Ended
June 30, 2009
Ended
June 30, 2008
Ended
June 30, 2009
Ended
June 30, 2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG classifies investments in the Rabbi Trusts as available for sale under SFAS 115. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts: As of June 30, 2009 Cost Gross Gross Estimated Millions Equity Securities $ 12 $ — $ (1 ) $ 11 Debt Securities 102 13 — 115 Other Securities 14 — — 14 Total PSEG Available-for-Sale Securities $ 128 $ 13 $ (1 ) $ 140 As of December 31, 2008 Cost Gross Gross Estimated Millions Equity Securities $ 11 $ — $ (2 ) $ 9 Debt Securities 102 9 (1 ) 110 Other Securities 14 — — 14 Total PSEG Available-for-Sale Securities $ 127 $ 9 $ (3 ) $ 133 The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. In the first half of 2009, other-than-temporary impairments of $1 million were recognized on the investments of the Rabbi Trusts. Three Months Three Months Six Months Six Months Millions Proceeds from Sales $ 2 $ 23 $ 2 $ 23 Net Realized Gains (Losses): Gross Realized Gains $ — $ 2 $ — $ 2 Gross Realized Losses — — (1 ) — Net Realized Gains (Losses): $ — $ 2 $ (1 ) $ 2 The cost of these securities was determined on the basis of specific identification. 21
(UNAUDITED)
Unrealized
Gains
Unrealized
Losses
Fair Value
Unrealized
Gains
Unrealized
Losses
Fair Value
Ended
June 30, 2009
Ended
June 30, 2008
Ended
June 30, 2009
Ended
June 30, 2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The estimated fair value of the Rabbi Trusts related to PSEG, Power and PSE&G are detailed as follows: As of June 30, As of December 31, Millions Power $ 28 $ 27 PSE&G 48 46 Other 64 60 Total PSEG Available-for-Sale Securities $ 140 $ 133 PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. Pension Benefits OPEB Pension Benefits OPEB 2009 2008 2009 2008 2009 2008 2009 2008 Millions Components of Net Periodic Benefit Cost: Service Cost $ 19 $ 20 $ 3 $ 3 $ 38 $ 39 $ 6 $ 7 Interest Cost 59 57 18 18 118 114 36 36 Expected Return on Plan Assets (54 ) (73 ) (3 ) (3 ) (108 ) (145 ) (6 ) (7 ) Amortization of Net Transition Obligation — — 7 7 — — 14 14 Prior Service Cost 2 3 3 3 4 5 7 6 Actuarial Loss 28 3 (1 ) (1 ) 56 6 (2 ) (1 ) Net Periodic Benefit Cost $ 54 $ 10 $ 27 $ 27 $ 108 $ 19 $ 55 $ 55 Effect of Regulatory Asset — — 5 5 — — 10 10 Total Benefit Expense, Including Effect of Regulatory Asset $ 54 $ 10 $ 32 $ 32 $ 108 $ 19 $ 65 $ 65 22
(UNAUDITED)
2009
2008
Three Months
Ended
June 30,
Three Months
Ended
June 30,
Six Months
Ended
June 30,
Six Months
Ended
June 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Pension and OPEB costs for PSEG, Power and PSE&G are detailed as follows: Pension OPEB Pension OPEB 2009 2008 2009 2008 2009 2008 2009 2008 Millions Power $ 17 $ 3 $ 3 $ 3 $ 33 $ 6 $ 6 $ 6 PSE&G 30 4 29 28 60 8 58 57 Other 7 3 — 1 15 5 1 2 Total Benefit Costs $ 54 $ 10 $ 32 $ 32 $ 108 $ 19 $ 65 $ 65 During the six months ended June 30, 2009, PSEG contributed its planned contributions for the year 2009 of $364 million and $11 million into its pension and postretirement healthcare plans, respectively. Note 6. Commitments and Contingent Liabilities Guaranteed Obligations Power has unconditionally guaranteed payments by its subsidiaries in commodity-related transactions to support current exposure, interest and other costs on sums due and payable in the ordinary course of business. These guarantees are provided to counterparties in order to obtain credit. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. In order for Power to incur liability for the face value of the outstanding guarantees, its subsidiaries would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of this is highly unlikely due to offsetting positions within the portfolio. For this reason, the current 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. 23
(UNAUDITED)
Three Months
Ended
June 30,
Three Months
Ended
June 30,
Six Months
Ended
June 30,
Six Months
Ended
June 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The face value of outstanding guarantees, current exposure and margin positions as of June 30, 2009 and December 31, 2008 are as follows: As of June 30, As of December 31, Millions Face value of outstanding guarantees $ 1,897 $ 1,856 Exposure under current guarantees $ 624 $ 585 Letters of Credit Margin Posted $ 153 $ 201 Letters of Credit Margin Received $ 148 $ 250 Net Cash Received Counterparty Cash Margin Deposited $ 1 $ 3 Counterparty Cash Margin (Received) (194 ) (81 ) Net Broker Balance (Received) Deposited (14 ) (74 ) Total Net Cash Received $ (207 ) $ (152 ) Power nets the fair value of cash collateral receivables and payables with the corresponding net energy contract balances. Of the net cash received, Power has included $227 million and $112 million in its corresponding net derivative contract positions as of June 30, 2009 and December 31, 2008, respectively. The remaining balance of net cash (received) deposited shown above is primarily included in Accounts Payable. In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. As of June 30, 2009, if Power was to lose its investment grade rating, additional collateral of approximately $1 billion could be required. As of June 30, 2009, there was $2.6 billion of available liquidity that could be used to post collateral under the PSEG and Power credit facilities. On July 24, 2009, Power entered into an additional $350 million syndicated credit facility that expires in July 2011. In addition to amounts in the table above, Power had posted $125 million and $101 million in letters of credit as of June 30, 2009 and December 31, 2008, respectively, to support various other contractual and environmental obligations. Environmental Matters Passaic River The U.S. Environmental Protection Agency (EPA) undertook a study of the Passaic River and determined that a six-mile stretch of the river in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). The EPA later expanded the study area to include the entire 17-mile tidal reach of the lower Passaic River. PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the river. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former Manufactured Gas Plant (MGP) sites. 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 the Essex Site was transferred. The costs associated with the MGP Remediation Program have historically been recovered through the Societal Benefits Clause (SBC) charges to PSE&G ratepayers. The EPA believes that hazardous substances had been released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. 73 PRPs, 24
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed-upon formula. The PRP group is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim. In 2007, the EPA released a draft “Focused Feasibility Study” that proposes six options to address the contamination cleanup of the lower eight miles of the Passaic River, with estimated costs from $900 million to $2.3 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study is expected to be released later in 2010. In June, 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G. NJDEP Litigation In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of hazardous substances into the Passaic River. 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 they allegedly discharged into the Passaic River. The third-party complaints seek statutory contribution, and contribution under the New Jersey Spill Compensation and Control Act (Spill Act), to recover past and future removal costs and damages. Natural Resource Damage Claims In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the NJ Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In November 2008, PSEG and a number of other PRPs agreed in an interim cooperative assessment agreement to pay an aggregate of $1 million for past costs incurred by the Federal trustees, and certain costs the trustees will incur going forward, and to work with the trustees for a 12-month period to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. Newark Bay Study Area The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding this study. 25
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be material. MGP Remediation Program PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant sites for cleanup. One of the sites identified was PSE&G’s former Camden Coke facility. During the second quarter of 2009, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $704 million and $804 million from June 30, 2009 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $704 million on the balance sheet as of June 30, 2009. Of this amount, $28 million was recorded in Other Current Liabilities and $676 million was reflected as Environmental Costs in Noncurrent Liabilities. As such, PSE&G has recorded a $704 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 certain of Power’s generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter and mercury. 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 June 30, 2009 of $263 million. All back-end pollution control technology construction is expected to be completed by the end of 2010. 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 and $700 million to $750 million for Hudson, with expenditures as of June 30, 2009 of $560 million for both projects. On January 14, 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were made at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter. 26
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Mercury Regulation In March 2005, the EPA established a New Source Performance Standard limit for nickel emissions from oil-fired electric generating units and a cap-and-trade program for mercury emissions from coal-fired electric generating units. In February 2008, the United States Court of Appeals for the District of Columbia Circuit issued a decision rejecting the EPA’s mercury emissions program and requiring the EPA to develop standards for mercury and nickel emissions that adhere to the Maximum Available Control Technology (MACT) provisions of the Clean Air Act. Although the EPA initially filed a petition with the U.S. Supreme Court to review the lower court’s decision, in February 2009, the EPA withdrew its petition with the U.S. Supreme Court and indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the Court’s ruling. While certain industry litigants also petitioned the U.S. Supreme Court to review the lower court’s decision, in February 2009, the Supreme Court denied the petition. The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements 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. 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, have been 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 through the installation of a baghouse at its Hudson plant by the end of 2010. These 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. In January 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it is inconsistent with the Clean Air Act. The Commonwealth Court’s decision has been appealed to the Supreme Court of Pennsylvania. If the Commonwealth Court’s decision were to be overturned and the above-mentioned requirements are upheld, the Keystone and Conemaugh generating stations would be positioned by 2010 to meet Phase I of the 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 Pennsylvania mercury rule after a full evaluation of the Phase I reductions. If the Commonwealth Court’s ruling is sustained and the EPA undertakes a MACT process, it is uncertain at this time whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions at these stations with currently planned capital projects. 27
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Connecticut Mercury emissions control standards were effective in July 2008 and require coal-fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. The recently installed activated carbon injection and baghouse on Bridgeport Unit 3 has been demonstrated through stack testing to comply with the mercury limits in this rule. 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. In January 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 New Jersey In April 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule 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 units. Power cannot predict the financial impact resulting from compliance with this rulemaking. Connecticut Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities utilize Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. Power’s agreements with the State of Connecticut authorizing the DERC’s expire on May 1, 2010. If not extended, we could potentially be forced to utilize lower NOx-producing fuels, or install NOx emission controls in order to operate the units. Power can not predict the financial impact of such costs, but such costs could be material and could impact the continued viability of these units. New Jersey Industrial Site Recovery Act (ISRA) Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the 28
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS sale of certain assets. Power had a $50 million liability as of June 30, 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 allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the Federal Water Pollution Control Act’s (FWPCA) Section 316(b) and the Phase II 316(b) rules, which govern cooling water intake structures at large electric generating facilities. Under these rules, Power had historically used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer. The Phase II Rule would also have been applicable to Bridgeport, and possibly, Sewaren and New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson, and to 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, Connecticut, and New York, the Utility Water Act Group and several of its members, including Power. In its ruling, the Court: • remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test and • instructed the EPA to reconsider the definition of “best technology available” without comparing the costs of the best performing technology to its benefits. On April 1, 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations. The Supreme Court’s decision became effective on April 27, 2009 and the matter was sent back to the Second Circuit for further proceedings consistent with the Supreme Court’s opinion. 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. 29
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Stormwater In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has now determined that Hudson is no longer eligible to utilize this general permit and must apply for an individual NJPDES permit for stormwater discharges. While the full extent of these requirements remains unclear, to the extent Power may be required to reduce or eliminate the exposure of coal to stormwater, or be required to construct technologies preventing the discharge of stormwater to surface water or groundwater, those costs could be material. New Generation and Development Nuclear Power has approved the expenditure of $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 began in July 2009 and are expected to 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 in June 2011. The project is expected to be in-service by June 2012. Power estimates the cost of these generating units to be $130 million to $140 million. Total capitalized expenditures to date are $12 million, which are included in Other Noncurrent Assets in the Consolidated Balance Sheets of PSEG and Power. PJM Interconnection L.L.C. (PJM) Power plans to construct 178 MW of gas-fired peaking capacity at the Kearny site. This capacity was bid into and has cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to commence in the third quarter of 2011. The project is expected to be in-service by June 2012. Power estimates the cost of these generating units to be $160 million to $200 million. Total capitalized expenditures to date were $7 million which are included in Property, Plant and Equipment in PSEG’s and Power’s Condensed 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 30
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS above. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments. PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows: Auction Year 2006 2007 2008 2009 36-Month Terms Ending May 2009 May 2010 May 2011 May 2012 (a) Load (MW) 2,882 2,758 2,840 2,840 $ per kWh 0.10251 0.09888 0.11150 0.10372 (a) Prices set in the 2009 BGS auction became effective on June 1, 2009 when PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 15. Related-Party Transactions. Minimum Fuel Purchase Requirements Power has various long-term fuel purchase commitments for coal and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas. Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Power’s strategy is to maintain certain levels of uranium concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below include estimated quantities to be purchased that are in excess of contractual minimum quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2011 and a portion for 2012 and 2013 at Salem, Hope Creek and Peach Bottom. As of June 30, 2009, the total minimum purchase requirements included in these commitments are as follows: Fuel Type Commitments Power’s Share Millions Nuclear Fuel Uranium $ 671 $ 420 Enrichment $ 428 $ 242 Fabrication $ 244 $ 151 Natural Gas $ 849 $ 849 Coal/Oil $ 921 $ 921 31
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the 2006 BGS auction agreements expired.
through 2013
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Included in the $921 million commitment for coal and oil above is $449 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. Power has entered into gas supply option agreements for the anticipated fuel requirements at the PSEG Texas, LP (PSEG Texas) generation facilities to satisfy obligations under the facilities forward energy sales contracts. As of June 30, 2009, Power’s fuel purchase options totaled $40 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. 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. On May 13, 2009 the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision. In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition, which remains pending. BPU Deferral Audit The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit Phase II report relating to the 12-month period ended July 31, 2003 was released by the consultant to the BPU in April 2005. That report, which addresses SBC, Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all material respects with applicable BPU Orders. It also noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The matter was referred to the Office of Administrative Law. The amount in dispute is $114 million, which if required to be refunded to customers with interest through June 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 32
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. On July 23, 2009, we requested oral argument before the BPU. The BPU decision is pending. 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 $610 million as of June 30, 2009. Of this amount, $159 million was recorded as a current liability and $451 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 The Internal Revenue Service (IRS) has issued reports with respect to its audits of PSEG’s federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS. PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, four cases have been decided at the trial court level, three of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fourth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. The IRS has also issued letters to a number of taxpayers with these types of lease transactions containing settlement offers. PSEG has analyzed potential settlements with the IRS and to date has declined to participate. In order to reduce the cash tax exposure related to these leases, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds and where the transactions in total will result in a positive or neutral earnings and cash impact. When a lease is terminated, taxes due associated with that lease are paid out of the termination proceeds. In the last twelve months, PSEG has terminated eight of these leasing transactions and reduced the related cash tax exposure by $350 million. As of June 30, 2009 and December 31, 2008, PSEG’s total gross investment in such transactions was $672 million and $1 billion, respectively. Cash Impact As of June 30, 2009, an aggregate $950 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing its potential cash exposure to $630 million. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. As of June 30, 2009, penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure grow at the rate of $9 million per quarter during 2009. If the IRS is successful in a litigated case consistent with the 33
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS positions it has taken in the generic settlement offer proposed, an additional $130 million to $150 million of tax would be due for tax positions through June 30, 2009. PSEG currently anticipates that it will pay between $120 million and $280 million in tax, interest and penalties for the tax years 1997-2000 during the second half of 2009 and subsequently commence litigation to recover these amounts. Further it is possible that an additional payment of between $220 million and $500 million could be required in late 2009 for tax years 2001-2003 followed by further litigation to recover those taxes. These amounts are in addition to tax deposits already made. Earnings Impact As a result of the changes in the timing of projected cash flows related to these leases, in the second quarter of 2008, PSEG recalculated its lease transactions and recorded an after-tax charge of $355 million. This charge was reflected as a reduction in Operating Revenues of $485 million with a partially offsetting reduction in Income Tax Expense of $130 million. This represents PSEG’s view of most of the earnings impact related to these transactions, although a total loss, consistent with the broad settlement offer proposed by the IRS, would result in an additional earnings charge of $100 million to $120 million. Note 7. Changes in Capitalization The following capital transactions occurred in the first six months of 2009: Power • converted $44 million of 4.00% Pollution Control Bonds to variable rate demand bonds backed by letters of credit, and • established a program for the issuance of up to $500 million of unsecured medium-term notes (MTNs) to retail investors in January. Under this program we ¡ issued $161 million of 6.5% MTNs due January 2014 (issued January, callable in one year) and ¡ issued $48 million of 6% MTNs due January 2013 (issued January, callable in one year). • paid a cash dividend of $600 million to PSEG and • paid $250 million of 3.75% Senior Notes at maturity in April. PSE&G • paid $44 million of 8.10% MTNs, Series A at maturity in May, • paid $16 million of 8.16% MTNs, Series A at maturity in May, • received $250 million equity contribution from PSEG, • paid $82 million of Transition Funding’s securitization debt, and • paid $5 million of Transition Funding II’s securitization debt. Energy Holdings • redeemed $280 million of floating rate non-recourse project debt due in December 2009 associated with PSEG Texas and • repurchased $10 million of its 8.5% Senior Notes due 2011. 34
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 8. Financial Risk Management Activities The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments. Commodity Prices The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power and Energy Holdings use physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Contracts that do not qualify for hedge accounting are marked to market in accordance with SFAS 133, with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. The financial effect of using such modeling techniques is not material to PSEG’s or Power’s financial statements. Cash Flow Hedges Power 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 • the price of fuel for one of the Texas generation facilities. 35
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2009 and December 31, 2008, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows: As of June 30, As of December 31, Millions Power Fair Value of Cash Flow Hedges $ 438 $ 331 * Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ 311 $ 176 Energy Holdings Fair Value of Cash Flow Hedges $ — $ 3 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ 3 $ 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 June 30, 2010 and June 30, 2011 are $185 million and $87 million, respectively. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $14 million at June 30, 2009. The expiration date of the longest-dated cash flow hedge for Energy Holdings is in 2009. Therefore, substantially all of the after-tax unrealized gains on its commodity derivatives are expected to be reclassified to earnings during 2009. There was no ineffectiveness associated with these hedges. Trading Derivatives In general, the main purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Power does engage in some trading of electricity and energy-related products where such transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned generation. Such trading activities represent 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. Prior to June 2009, some of the derivative contracts were also used in Power’s NDT Funds. For Energy Holdings, these are electricity forward and capacity sale contracts entered into to sell a portion of the Texas facilities’ capacity and gas purchase contracts to support the electricity forward sales contracts. 36
(UNAUDITED)
2009
2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of June 30, 2009 and December 31, 2008 was as follows:
(UNAUDITED)
As of June 30,
2009
As of December 31,
2008
Millions
Net Fair Value of Other Derivatives
Power
$
(25
)
$
67
*
Energy Holdings
$
28
$
32
| ||||||||||||||||||||
* |
| The net fair value of other derivatives related to energy contracts for Power of $67 million at December 31, 2008 in the table above was corrected from $(9) million disclosed in our 2008 Form 10-K. | ||||||||||||||||||
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed through the use of fixed and floating rate debt and interest rate derivatives.
Fair Value Hedges
In May and June 2009, we entered into three interest rate swaps to convert Power’s $250 million of 5.00% Senior Notes due April 2014 and $300 million of 5.50% Senior Notes due December 2015 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the fair value changes in the underlying debt. As of June 30, 2009, the fair value of the underlying hedges was $(6) million.
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 June 30, 2009, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was $(1) million and $(7) million as of June 30, 2009 and December 31, 2008, respectively. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated as cash flow hedges was $(3) million and $(6) million as of June 30, 2009 and December 31, 2008, respectively.
37
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:
(UNAUDITED)
Balance Sheet
Location
As of June 30, 2009
Power
PSE&G
Energy
Holdings
Consolidated
Cash Flow Hedges
Non Hedges
Netting (A)
Total Power
Non Hedges
Non Hedges
Total
Derivatives (B)
Energy-
Related
Contracts
Energy-
Related
Contracts
Energy-
Related
Contracts
Energy-
Related
Contracts
Millions
Derivative Contracts
Current Assets
$
575
$
737
$
(1,082
)
$
230
$
—
$
19
$
259
Noncurrent Assets
$
453
$
195
$
(503
)
$
145
$
—
$
9
$
154
Total Mark-to-Market
Derivative Assets
$
1,028
$
932
$
(1,585
)
$
375
$
—
$
28
$
413
Derivative Contracts
Current Liabilities
$
(139
)
$
(968
)
$
807
$
(300
)
$
(10
)
$
—
$
(310
)
Noncurrent Liabilities
$
(59
)
$
(162
)
$
159
$
(62
)
$
(28
)
$
—
$
(106
)
Total Mark-to-Market
Derivative (Liabilities)
$
(198
)
$
(1,130
)
$
966
$
(362
)
$
(38
)
$
—
$
(416
)
Total Net Mark-to-MarketDerivative Assets (Liabilities)
$
830
$
(198
)
$
(619
)
$
13
$
(38
)
$
28
$
(3
)
Other Noncurrent Assets
$
—
$
—
$
—
$
—
$
1
$
—
$
1
| ||||||||||||||||||||
(A) |
| Represents the netting of fair value balances with the same counterparty and the application of collateral in accordance with FSP FIN 39-1. Includes cash collateral of $(221) million and $(150) million netted against current assets and noncurrent assets, respectively. Includes cash collateral of $116 million and $28 million netted against current liabilities and noncurrent liabilities, respectively. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Includes PSEG interest rate swap asset of $10 million and interest rate swap liability of $(16) million recorded in Current Assets-Derivative Contracts and Noncurrent Liability-Derivative Contracts, respectively. | ||||||||||||||||||
The aggregate fair value of derivative contracts in a liability position as of June 30, 2009 that contain triggers for additional collateral was $729 million. This potential additional collateral is included in the $1 billion discussed in Note 6. Commitments and Contingent Liabilities.
38
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended June 30, 2009: Derivatives in SFAS 133 Amount of Pre-Tax Location of Pre-Tax Amount of Pre-Tax Location of Pre-Tax Amount of Pre-Tax Millions PSEG Energy-Related Contracts $ 121 Operating Revenue $ 138 Operating Revenue $ (1 ) Energy-Related Contracts (15 ) Energy Costs (37 ) — Interest Rate Swaps — Interest Expense (1 ) — Total PSEG $ 106 $ 100 $ (1 ) PSEG Power Energy-Related Contracts $ 131 Operating Revenue $ 129 Operating Revenue $ (1 ) Energy-Related Contracts (14 ) Energy Costs (29 ) — Total Power $ 117 $ 100 $ (1 ) PSE&G Interest Rate Swaps $ — Interest Expense $ (1 ) $ — Total PSE&G $ — $ (1 ) $ — Energy Holdings Energy-Related Contracts $ (10 ) Operating Revenue $ 9 $ — Energy-Related Contracts (1 ) Energy Costs (8 ) — Total Energy Holdings $ (11 ) $ 1 $ — 39
(UNAUDITED)
Cash Flow Hedging
Relationships
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective Portion)
Gain (Loss)
Reclassified from
AOCI into
Income
Gain (Loss)
Reclassified from
AOCI into
Income
(Effective Portion)
Gain (Loss)
Recognized
in Income on
Derivatives
(Ineffective
Portion)
Gain (Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the six months ended June 30, 2009: Derivatives in SFAS 133 Amount of Pre-Tax Location of Pre-Tax Amount of Pre-Tax Location of Pre-Tax Amount of Pre-Tax Millions PSEG Energy-Related Contracts $ 503 Operating Revenue $ 294 Operating Revenue $ 7 Energy-Related Contracts (43 ) Energy Costs (63 ) — Interest Rate Swaps — Interest Expense (5 ) — Total PSEG $ 460 $ 226 $ 7 PSEG Power Energy-Related Contracts $ 485 Operating Revenue $ 271 Operating Revenue $ 7 Energy-Related Contracts (35 ) Energy Costs (48 ) — Total Power $ 450 $ 223 $ 7 PSE&G Interest Rate Swaps $ — Interest Expense $ (1 ) $ — Total PSE&G $ — $ (1 ) $ — Energy Holdings Energy-Related Contracts $ 18 Operating Revenue $ 23 $ — Energy-Related Contracts (8 ) Energy Costs (15 ) — Interest Rate Swaps — Interest Expense (4 ) — Total Energy Holdings $ 10 $ 4 $ — The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Income of PSEG on a pre-tax and after-tax basis: Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2008 $ 292 $ 172 Gain Recognized in AOCI (Effective Portion) 354 211 Less: Gain Reclassified into Income (Effective Portion) (126 ) (74 ) Balance as of March 31, 2009 $ 520 $ 309 Gain Recognized in AOCI (Effective Portion) 106 62 Less: Gain Reclassified into Income (Effective Portion) (100 ) (60 ) Balance as of June 30, 2009 $ 526 $ 311 40
(UNAUDITED)
Cash Flow Hedging
Relationships
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective Portion)
Gain (Loss)
Reclassified from
AOCI into
Income
Gain (Loss)
Reclassified from
AOCI into
Income
(Effective Portion)
Gain (Loss)
Recognized
in Income on
Derivatives
(Ineffective
Portion)
Gain (Loss)
Recognized in Income
on Derivatives
(Ineffective Portion)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months and six months ended June 30, 2009: Derivatives Not Designated Location of Pre-Tax Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives Three Months Ended Six Months Ended Millions Millions PSEG Energy-Related Contracts Operating Revenues $ 49 $ 180 Energy-Related Contracts Energy Costs 1 (85 ) Interest Rate Swaps Interest Expense — (1 ) Derivatives in NDT Funds Other Income 6 13 Total PSEG $ 56 $ 107 Power Energy-Related Contracts Operating Revenue $ 29 $ 100 Energy-Related Contracts Energy Costs 6 (68 ) Derivatives in NDT Funds Other Income 6 13 Total Power $ 41 $ 45 Energy Holdings Energy-Related Contracts Operating Revenue $ 20 $ 80 Energy-Related Contracts Energy Costs (5 ) (17 ) Interest Rate Swap Interest Expense — (1 ) Total Energy Holdings $ 15 $ 62 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 June 30, 2009: Type Notional Total PSEG Power PSE&G Energy Holdings Millions Natural Gas Dth 1,273 — 1,028 245 — Electricity MWh 185 — 178 — 7 Capacity MW days 2 — 2 — — FTRs MWh 40 — 40 — — Emissions Allowances Tons 2 — 2 — — Oil Barrels 1 — 1 — — Interest Rate Swaps US Dollars 550 550 — — — 41
(UNAUDITED)
as Hedges
Gain (Loss)
Recognized in
Income on Derivatives
June 30, 2009
June 30, 2009
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 9. 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. 42
(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 as of June 30, 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. Description Recurring Fair Value Measurements as of June 30, 2009 Total Cash Quoted Market Prices Significant Other Significant Millions PSEG Assets: Derivative Contracts: Energy-Related Contracts (A) $ 404 $ (371 ) $ — $ 549 $ 226 Interest Rate Swaps (B) $ 10 $ — $ — $ 10 $ — NDT Funds (C) Equity Securities $ 527 $ — $ 527 $ — $ — Debt Securities-Government Obligations $ 296 $ — $ — $ 296 $ — Debt Securities-Other $ 206 $ — $ — $ 206 $ — Other Securities $ 30 $ — $ — $ — $ 30 Rabbi Trusts (C) $ 140 $ — $ 11 $ 115 $ 14 Other Long-Term Investments (D) $ 1 $ — $ 1 $ — $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (400 ) $ 144 $ — $ (468 ) $ (76 ) Interest Rate Swaps (B) $ (16 ) $ — $ — $ (16 ) $ — Power Assets: Derivative Contracts: Energy-Related Contracts (A) $ 375 $ (371 ) $ — $ 549 $ 197 NDT Funds (C) Equity Securities $ 527 $ — $ 527 $ — $ — Debt Securities-Government Obligations $ 296 $ — $ — $ 296 $ — Debt Securities-Other $ 206 $ — $ — $ 206 $ — Other Securities $ 30 $ — $ — $ — $ 30 Rabbi Trusts (C) $ 28 $ — $ 2 $ 23 $ 3 Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (362 ) $ 144 $ — $ (468 ) $ (38 ) PSE&G Assets: Derivative Contracts: Energy-Related Contracts (A) $ 1 $ — $ — $ — $ 1 Rabbi Trusts (C) $ 48 $ — $ 4 $ 39 $ 5 Liabilities: Energy-Related Contracts (A) $ (38 ) $ — $ — $ — $ (38 ) 43
(UNAUDITED)
Collateral
Netting (E)
of Identical Assets
(Level 1)
Observable Inputs
(Level 2)
Unobservable
Inputs
(Level 3)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Description Recurring Fair Value Measurements as of December 31, 2008 Total Cash Quoted Market Prices Significant Other Significant Millions PSEG Assets: Derivative Contracts: Energy-Related Contracts (A) $ 399 $ (154 ) $ — $ 439* $ 114 * NDT Funds (C) Equity Securities $ 413 $ — $ 412 $ 1 $ — Debt Securities-Government Obligations $ 195 $ — $ — $ 195 $ — Debt Securities-Other $ 290 $ — $ — $ 285 $ 5 Other Securities $ 72 $ — $ 1 $ 35 $ 36 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) Equity Securities $ 413 $ — $ 412 $ 1 $ — Debt Securities-Government Obligations $ 195 $ — $ — $ 195 $ — Debt Securities-Other $ 290 $ — $ — $ 285 $ 5 Other Securities $ 72 $ — $ 1 $ 35 $ 36 Rabbi Trusts - Mutual Funds (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 a 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 44
(UNAUDITED)
Collateral
Netting (E)
of Identical Assets
(Level 1)
Observable Inputs
(Level 2)
Unobservable Inputs
(Level 3)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 maintain investments in various equity and fixed income securities classified as “available for sale.” These securities are valued using quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued based upon internal matrices using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The Rabbi Trust mutual funds are mainly invested in a US Bond Index fund, an S&P 500 Index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2). (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 as of Included in Included in Millions PSEG Net Derivative Assets $ 144 $ (44 ) $ 17 $ 33 $ 150 NDT Funds $ 22 $ (2 ) $ — $ 10 $ 30 Rabbi Trust Funds $ 15 $ — $ — $ (1 ) $ 14 Power Net Derivative Assets $ 158 $ (32 ) $ — $ 33 $ 159 NDT Funds $ 22 $ (2 ) $ — $ 10 $ 30 Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Net Derivative $ (54 ) $ — $ 17 $ — $ (37 ) Rabbi Trust Funds $ 5 $ — $ — $ — $ 5 45
(UNAUDITED)
for the Three Months Ended June 30, 2009
April 1,
2009
Realized/Unrealized
(Sales) and
Settlements
June 30, 2009
Income (A)
Regulatory Assets/
Liabilities (B)
Liabilities
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 as of Included in Included in Millions PSEG Net Derivative Assets $ 32 $ 84 $ 27 $ 7 $ 150 NDT Funds $ 41 $ (2 ) $ — $ (9 ) $ 30 Rabbi Trust Funds $ 14 $ — $ — $ — $ 14 Power Net Derivative Assets $ 61 $ 91 $ — $ 7 $ 159 NDT Funds $ 41 $ (2 ) $ — $ (9 ) $ 30 Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Net Derivative Liabilities $ (64 ) $ — $ 27 $ — $ (37 ) Rabbi Trust Funds $ 5 $ — $ — $ — $ 5 (A) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $(35) million is included in Operating Revenues and $(9) million is included in OCI. Of the $(35) million in Operating Revenues, $(12) million unrealized is at PSEG Texas and $(23) million unrealized is at Power. The $(9) million included in OCI is at Power. (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset and are expected to be recovered from PSE&G’s customers. (C) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $65 million is included in Operating Revenues and $19 million is included in OCI. Of the $65 million in Operating Revenues, $(7) million unrealized is at PSEG Texas and $72 million, including $58 million unrealized, is at Power. The $19 million included in Other Comprehensive Income is at Power. As of June 30, 2009, PSEG carried approximately $1.2 billion of net assets that are measured at fair value on a recurring basis, of which approximately $200 million were 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. 46
(UNAUDITED)
for the Six Months Ended June 30, 2009
January 1,
2009
(Sales) and
Settlements
June 30,
2009
Income (C)
Regulatory Assets/
Liabilities (B)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 as of Included in Included in Millions PSEG Net Derivative Assets $ (34 ) $ 44 $ (18 ) $ 9 $ 1 NDT Funds $ 27 $ — $ — $ 5 $ 32 Rabbi Trust Funds $ 14 $ — $ — $ — $ 14 Power Net Derivative Assets $ 4 $ 42 $ — $ 33 $ 79 NDT Funds $ 27 $ — $ — $ 5 $ 32 Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Net Derivative $ (71 ) $ — $ (18 ) $ — $ (89 ) Rabbi Trust Funds $ 5 $ — $ — $ — $ 5 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 as of Included in Included in Millions PSEG Net Derivative Assets $ (9 ) $ 37 $ (40 ) $ 13 $ 1 NDT Funds $ 27 $ (1 ) $ — $ 6 $ 32 Rabbi Trust Funds $ 16 $ — $ — $ (2 ) $ 14 Power Net Derivative Assets $ 10 $ 27 $ — $ 42 $ 79 NDT Funds $ 27 $ (1 ) $ — $ 6 $ 32 Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Net Derivative $ (49 ) $ — $ (40 ) $ — $ (89 ) Rabbi Trust Funds $ 6 $ — $ — $ (1 ) $ 5 (A) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $32 million is included in Operating Revenues and $12 million is included in OCI. Of the $32 million in Operating Revenues, $2 million unrealized is at PSEG Texas and $30 million unrealized is at Power. The $12 million included in OCI is at Power. 47
(UNAUDITED)
for the Three MonthsEnded June 30, 2008
April 1,
2008
Realized/Unrealized
(Sales) and
Settlements
June 30,
2008
Income (A)
Regulatory Assets/
Liabilities (B)
Liabilities
for the Six MonthsEnded June 30, 2008
January 1,
2008
Realized/Unrealized
(Sales) and
Settlements
June 30,
2008
Income (C)
Regulatory Assets/
Liabilities (B)
Liabilities
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset and are expected to be recovered from PSE&G’s customers. (C) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $29 million is included in Operating Revenues and $8 million is included in OCI. Of the $29 million in Operating Revenues, $10 million unrealized is at PSEG Texas and $19 million unrealized is at Power. The $8 million included in OCI is at Power. As of June 30, 2008, PSEG carried approximately $653 million of net assets that are measured at fair value on a recurring basis, of which approximately $47 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers in or out of Level 3 during the six months ended June 30, 2008. As discussed in Note 3, Energy Holdings sold a 10.1% interest in its GWF Energy investment and recorded an after-tax impairment charge of $3 million on the entire investment prior to the sale. The remaining investment of $63 million is carried as a nonrecurring fair value measurement as of June 30, 2009. In accordance with SFAS 157, the investment is considered a Level 3 within the fair value hierarchy based on the use of unobservable inputs. Fair Value of Debt The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of June 30, 2009 and December 31, 2008.
(UNAUDITED)
June 30, 2009
December 31, 2008
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Millions
Long-Term Debt:
PSEG (Parent)
$
243
$
245
$
249
$
250
Power
2,862
3,019
2,903
2,800
PSE&G
3,463
3,645
3,523
3,569
Transition Funding (PSE&G)
1,372
1,565
1,454
1,658
Transition Funding II (PSE&G)
71
76
76
80
Energy Holdings:
Senior Notes
495
503
505
474
Project Level, Non-Recourse Debt
45
45
328
328
$
8,551
$
9,098
$
9,038
$
9,159
48
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 10. Other Income and Deductions Other Income Power PSE&G Other (A) Consolidated Millions Three Months Ended June 30, 2009 NDT Fund Gains $ 73 $ — $ — $ 73 NDT Interest, Dividend and Other Income 12 — — 12 Other Interest and Dividend Income 1 1 1 3 Other — 3 — 3 Total Other Income $ 86 $ 4 $ 1 $ 91 Three Months Ended June 30, 2008 NDT Fund Gains $ 76 $ — $ — $ 76 NDT Interest, Dividend and Other Income 14 — — 14 Other Interest and Dividend Income 2 2 1 5 Other 1 — 1 2 Total Other Income $ 93 $ 2 $ 2 $ 97 Six Months Ended June 30, 2009 NDT Fund Gains $ 127 $ — $ — $ 127 NDT Interest, Dividend and Other Income 25 — — 25 Other Interest and Dividend Income 4 1 — 5 Other — 4 1 5 Total Other Income $ 156 $ 5 $ 1 $ 162 Six Months Ended June 30, 2008 NDT Fund Gains $ 147 $ — $ — $ 147 NDT Interest, Dividend and Other Income 26 — — 26 Other Interest and Dividend Income 4 4 2 10 Other 2 3 2 7 Total Other Income $ 179 $ 7 $ 4 $ 190 49
(UNAUDITED)
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Other Deductions Power PSE&G Other (A) Consolidated Millions Three Months Ended June 30, 2009 NDT Fund Losses and Expenses $ 43 $ — $ — $ 43 Other 1 1 (1 ) 1 Total Other Deductions $ 44 $ 1 $ (1 ) $ 44 Three Months Ended June 30, 2008 NDT Fund Losses and Expenses $ 54 $ — $ — $ 54 Other 1 — 1 2 Total Other Deductions $ 55 $ — $ 1 $ 56 Six Months Ended June 30, 2009 NDT Fund Losses and Expenses $ 89 $ — $ — $ 89 Other 5 2 3 10 Total Other Deductions $ 94 $ 2 $ 3 $ 99 Six Months Ended June 30, 2008 NDT Fund Losses and Expenses $ 108 $ — $ — $ 108 Other — 1 4 5 Total Other Deductions $ 108 $ 1 $ 4 $ 113 (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 June 30, 2009 was 43.6% as compared to 41.0% for the quarter ended June 30, 2008, excluding the tax effect of a $490 million, after tax, charge taken in the second quarter of 2008 related to leveraged lease transactions. The increase in the effective tax rate was due primarily to the sale of leveraged lease assets in 2009. This was offset by tax benefits from reductions of reserves for uncertain tax positions in 2009. PSEG’s effective tax rate for the six months ended June 30, 2009 was 41.9% as compared to 37.6% for the six months ended June 30, 2008, excluding the tax effect of a $490 million, after tax, charge taken in the second quarter of 2008 related to leveraged lease transactions. The increase in the effective tax rate was due primarily to the sale of leveraged lease assets in 2009 and the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim. This was offset by tax benefits from reductions of reserves for uncertain tax positions in 2009 and benefits of a manufacturing deduction under the American Jobs Creation Act of 2004. Power’s effective tax rate for the quarter ended June 30, 2009 was 39.1% as compared to 40.7% for the quarter ended June 30, 2008. The decrease in the effective tax rate was due primarily to tax benefits from reductions of reserves for uncertain tax positions and increased benefits of a manufacturing deduction under the American Jobs Creation Act of 2004 offset by higher earnings in the NDT Fund. 50
(UNAUDITED)
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power’s effective tax rate for the six months ended June 30, 2009 was 39.2% as compared to 40.6% for the six months ended June 30, 2008. The decrease in the effective tax rate was due primarily to tax benefits from reductions of reserves for uncertain tax positions and increased benefits of a manufacturing deduction under the American Jobs Creation Act of 2004. PSE&G’s effective tax rate for the quarter ended June 30, 2009 was 39.7% as compared to 35.0% for the quarter ended June 30, 2008. The increase in the effective tax rate was due primarily to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim. PSE&G’s effective tax rate for the six months ended June 30, 2009 was 40.4% as compared to 33.0% for the six months ended June 30, 2008. The increase in the effective tax rate was due primarily to the absence of tax benefits, accrued in 2008, applicable to an IRS refund claim. PSEG and PSE&G have $1.155 billion and $28 million, respectively of unrecognized tax benefits as of June 30, 2009. On December 17, 2007, September 15, 2008 and June 26, 2009 PSEG made tax deposits with the IRS in the amount of $100 million, $80 million and $140 million, respectively, to defray interest costs associated with disputed tax assessments associated with certain lease investments (see Note 6. Commitments and Contingent Liabilities). The $320 million of deposits are fully refundable and are recorded as a reduction to the Long-Term Accrued Taxes in PSEG’s Consolidated Balance Sheets, but are not reflected in the $1.155 billion amount shown above. PSEG and PSE&G are no longer subject to examination for New Jersey Corporate Business Tax for years 2000 to 2004. During 2009, PSEG materially reduced its unrecognized tax benefits by terminating several leases involved in the IRS lease issue. (see Note 6. Commitments and Contingent Liabilities) It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 6. Commitments and Contingent Liabilities will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $350 million or decrease by as much as $946 million. It is not possible to predict the magnitude, timing or direction of any such change. It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease by approximately $73 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 $5 million increase for Power, a $32 million increase for PSE&G, a $25 million decrease for Services, a $90 million decrease for Energy Holdings and a $5 million increase for PSEG. 51
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 12. Comprehensive Income (Loss), Net of Tax
(UNAUDITED)
Power (A)
PSE&G
Other (B)
Consolidated
Total
Millions
Three Months Ended June 30, 2009:
Net Income
$
257
$
44
$
9
$
310
Other Comprehensive Income (Loss)
36
1
(6
)
31
Comprehensive Income
$
293
$
45
$
3
$
341
Three Months Ended June 30, 2008:
Net Income
$
240
$
52
$
(442
)
$
(150
)
Other Comprehensive Income (Loss)
(388
)
—
(72
)
(460
)
Comprehensive Income
$
(148
)
$
52
$
(514
)
$
(610
)
Six Months Ended June 30, 2009:
Net Income
$
575
$
168
$
11
$
754
Other Comprehensive Income (Loss)
168
1
8
177
Comprehensive Income
$
743
$
169
$
19
$
931
Six Months Ended June 30, 2008:
Net Income
$
515
$
189
$
(406
)
$
298
Other Comprehensive Income (Loss)
(660
)
—
(20
)
(680
)
Comprehensive Income
$
(145
)
$
189
$
(426
)
$
(382
)
| ||||||||||||||||||||
(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 | ||||||||||||||||||||||||||||||||||
Six Months Ended June 30, 2009: |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Derivative Contracts | $ | 172 | $ | 134 | $ | — | $ | 5 | $ | 311 | |||||||||||||||||||||||||
Pension and OPEB Plans |
| (371 | ) |
|
| 10 |
| — |
| 2 |
| (359 | ) |
| |||||||||||||||||||||
NDT Funds (A) | 18 | 22 | — | — | 40 | ||||||||||||||||||||||||||||||
Other |
| 4 |
| 2 |
| 1 |
| 1 |
| 8 | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| $ | (177 | ) | $ | 168 | $ | 1 | $ | 8 | $ | — | ||||||||||||||||||||||||
|
|
|
|
|
| ||||||||||||||||||||||||||||||
| ||||||||||||||||||||
(A) |
| Includes reclassification of $12 million of non-credit losses, net-of-tax, from Retained Earnings to Accumulated Other Comprehensive Income (Loss) recorded upon adoption of FSP FAS 115-2 and FAS 124-2 effective April 1, 2009. See Note 2. Recent Accounting Standards for additional information. | ||||||||||||||||||
52
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Balance as of
December 31, 2007
Power
PSE&G
Other
Balance as of
June 30, 2008
Millions
Six Months Ended June 30, 2008:
Derivative Contracts
$
(259
)
$
(619
)
$
—
—
$
(878
)
Pension and OPEB Plans
(167
)
1
—
—
(166
)
Currency Translation Adjustment
107
—
—
(19
)
88
NDT Funds
97
(42
)
—
—
55
Other
6
—
—
(1
)
5
$
(216
)
$
(660
)
$
—
$
(20
)
$
(896
)
Note 13. Earnings Per Share (EPS)
PSEG
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, restricted stock awards, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Basic | Diluted | Basic | Diluted | Basic | Diluted | Basic | Diluted | |||||||||||||||||||||||||||||||||||||||||||||||||
EPS Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Earnings (Millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Continuing Operations | $ | 311 | $ | 311 | $ | (166 | ) | $ | (166 | ) | $ | 755 | $ | 755 | $ | 269 | $ | 269 | ||||||||||||||||||||||||||||||||||||||
Discontinued Operations |
| — |
| — |
| 16 |
| 16 |
| — |
| — |
| 29 |
| 29 | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) | $ | 311 | $ | 311 | $ | (150 | ) | $ | (150 | ) | $ | 755 | $ | 755 | $ | 298 | $ | 298 | ||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||
EPS Denominator (Thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Weighted Average Common Shares Outstanding |
| 505,990 |
| 505,990 |
| 508,491 |
| 508,491 |
| 505,988 |
| 505,988 |
| 508,491 |
| 508,491 | ||||||||||||||||||||||||||||||||||||||||
Effect of Stock Options | — | 186 | — | 457 | — | 189 | — | 477 | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of Stock Performance Share Units |
| — |
| 677 |
| — |
| 517 |
| — |
| 575 |
| — |
| 501 | ||||||||||||||||||||||||||||||||||||||||
Effect of Restricted Stock | — | 44 | — | 22 | — | 40 | — | 14 | ||||||||||||||||||||||||||||||||||||||||||||||||
Effect of Restricted Stock Units |
| — |
| 39 |
| — |
| — |
| — |
| 20 |
| — |
| — | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Total Shares | 505,990 | 506,936 | 508,491 | 509,487 | 505,988 | 506,812 | 508,491 | 509,483 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||
EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Continuing Operations |
| $ |
| 0.61 |
| $ |
| 0.61 |
| $ |
| (0.32 | ) |
|
| $ |
| (0.32 | ) |
|
| $ |
| 1.49 |
| $ |
| 1.49 |
| $ |
| 0.53 |
| $ |
| 0.53 | ||||||||||||||||||||
Discontinued Operations | — | — | 0.03 | 0.03 | — | — | 0.06 | 0.06 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) |
| $ |
| 0.61 |
| $ |
| 0.61 |
| $ |
| (0.29 | ) |
|
| $ |
| (0.29 | ) |
|
| $ |
| 1.49 |
| $ |
| 1.49 |
| $ |
| 0.59 |
| $ |
| 0.59 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Dividend payments on common stock for the quarters ended June 30, 2009 and 2008 were $0.3325 and $0.3225 per share, respectively, and totaled $168 million and $164 million respectively. Dividend payments on common stock for the six months ended June 30, 2009 and 2008 were $0.665 and $0.645 per share, respectively, and totaled approximately $336 million and $328 million, respectively.
53
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 14. Financial Information by Business Segments Power PSE&G Energy Other (A) Consolidated Millions Three Months Ended June 30, 2009: Total Operating Revenues $ 1,301 $ 1,643 $ 158 $ (541 ) $ 2,561 Net Income (Loss) 257 44 10 — 311 Preferred Securities Dividends — (1 ) — 1 — Segment Earnings (Loss) 257 43 10 1 311 Gross Additions to Long-Lived Assets 218 185 10 1 414 Three Months Ended June 30, 2008: Total Operating Revenues $ 1,623 $ 1,858 $ (240 ) $ (691 ) $ 2,550 Income (Loss) From Continuing Operations 240 52 (453 ) (5 ) (166 ) Income from Discontinued Operations, net of tax — — 16 — 16 Net Income (Loss) 240 52 (437 ) (5 ) (150 ) Preferred Securities Dividends — (1 ) — 1 — Segment Earnings (Loss) 240 51 (437 ) (4 ) (150 ) Gross Additions to Long-Lived Assets 210 200 2 4 416 Six Months Ended June 30, 2009: Total Operating Revenues $ 3,675 $ 4,378 $ 293 $ (1,864 ) $ 6,482 Net Income (Loss) 575 168 17 (5 ) 755 Preferred Securities Dividends — (2 ) — 2 — Segment Earnings (Loss) 575 166 17 (3 ) 755 Gross Additions to Long-Lived Assets 425 379 13 (1 ) 816 Six Months Ended June 30, 2008: Total Operating Revenues $ 3,998 $ 4,476 $ (109 ) $ (2,023 ) $ 6,342 Income (Loss) From Continuing Operations 515 189 (424 ) (11 ) 269 Income from Discontinued Operations, net of tax — — 29 — 29 Net Income (Loss) 515 189 (395 ) (11 ) 298 Preferred Securities Dividends — (2 ) — 2 — Segment Earnings (Loss) 515 187 (395 ) (9 ) 298 Gross Additions to Long-Lived Assets 384 345 4 6 739 As of June 30, 2009: Total Assets $ 9,406 $ 16,441 $ 3,729 $ (816 ) $ 28,760 Investments in Equity Method Subsidiaries $ 42 $ — $ 173 $ — $ 215 As of December 31, 2008: Total Assets $ 9,459 $ 16,406 $ 4,256 $ (1,072 ) $ 29,049 Investments in Equity Method Subsidiaries $ 35 $ — $ 180 $ — $ 215 (A) Other activities include amounts applicable to PSEG (as parent company), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or at cost or, in the case 54
(UNAUDITED)
Holdings
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 15. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs. Note 15. Related-Party Transactions The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP. Power The financials statements for Power include transactions with related parties presented as follows:
(UNAUDITED)
Related Party Transactions
Three Months Ended
June 30,
Six Months Ended
June 30,
2009
2008
2009
2008
Millions
Revenue from Affiliates:
Billings to PSE&G through BGSS (A)
$
213
$
345
$
1,183
$
1,396
Billings to PSE&G through BGS (A)
319
335
663
607
Total Revenue from Affiliates
$
532
$
680
$
1,846
$
2,003
Expense Billings from Affiliates:
Administrative Billings from Services (B)
$
(37
)
$
(42
)
$
(77
)
$
(82
)
Total Expense Billings from Affiliates
$
(37
)
$
(42
)
$
(77
)
$
(82
)
|
|
|
|
| ||||||||||
Related Party Balances | As of | As of | ||||||||||||
| Millions | |||||||||||||
Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A) | $ | 294 | $ | 319 | ||||||||||
Receivables from PSE&G through BGS and BGSS Contracts (A) |
| 164 |
| 475 | ||||||||||
Administrative Billings Payable to Services (B) | (21 | ) | (26 | ) | ||||||||||
Tax Sharing Receivable from (Payable to) PSEG (C) |
| 42 |
| (36 | ) |
| ||||||||
Current Unrecognized Tax Receivable from PSEG (C) | 4 | — | ||||||||||||
Amounts Receivable from Energy Holdings |
| 17 |
| — | ||||||||||
Amounts PSEG Paid on Power’s Behalf | (1 | ) | — | |||||||||||
|
|
| ||||||||||||
Accounts Receivable—Affiliated Companies, net |
| $ |
| 499 |
| $ |
| 732 | ||||||
|
|
|
|
| ||||||||||
Short-Term Loan to Affiliate (Demand Note Receivable from PSEG) (D) | $ | 142 | $ | — | ||||||||||
|
|
| ||||||||||||
Short-Term Loan from Affiliate (Demand Note Payable to PSEG) (D) |
| $ |
| — |
| $ |
| (3 | ) |
| ||||
|
|
|
|
| ||||||||||
Working Capital Advances to Services (E) | $ | 17 | $ | 17 | ||||||||||
|
|
| ||||||||||||
Long-Term Accrued Taxes Payable (C) |
| $ |
| (4 | ) |
|
| $ |
| (16 | ) |
| ||
|
|
|
|
| ||||||||||
55
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSE&G The financials statements for PSE&G include transactions with related parties presented as follows: Related Party Transactions Three Months Ended Six Months Ended 2009 2008 2009 2008 Millions Expense Billings from Affiliates: Billings from Power through BGSS (A) $ (213 ) $ (345 ) $ (1,183 ) $ (1,396 ) Billings from Power through BGS (A) (319 ) (335 ) (663 ) (607 ) Administrative Billings from Services (B) (63 ) (71 ) (129 ) (133 ) Total Expense Billings from Affiliates $ (595 ) $ (751 ) $ (1,975 ) $ (2,136 ) Related Party Balances As of As of Millions Payable to Power Related to Gas Supply Hedges for BGSS (A) $ (294 ) $ (319 ) Payable to Power through BGS and BGSS Contracts (A) (164 ) (475 ) Administrative Billings Payable to Services (B) (36 ) (54 ) Tax Sharing Receivable from (Payable to) PSEG (C) 15 21 Current Unrecognized Tax Receivable from PSEG (C) 60 55 Amounts Collected by PSEG on behalf of PSE&G 4 9 Accounts Payable—Affiliated Companies, net $ (415 ) $ (763 ) Working Capital Advances to Services (E) $ 33 $ 33 Long-Term Accrued Taxes Payable (C) $ (88 ) $ (82 ) (A) PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. (B) Services provides and bills administrative services to Power and PSE&G. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. Power and PSE&G believe that the costs of services provided by Services approximate market value for such services. (C) PSEG and its subsidiaries adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. (D) Short-term loans are for short-term needs. Interest Income and Interest Expense relating to these short term funding activities were immaterial. (E) Power and PSE&G have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on Power’s and PSE&G’s Consolidated Balance Sheets. 56
(UNAUDITED)
June 30,
June 30,
June 30, 2009
December 31, 2008
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries. Power Guarantor Other Consolidating Consolidated Millions Three Months Ended June 30, 2009 Operating Revenues $ — $ 1,596 $ 32 $ (327 ) $ 1,301 Operating Expenses 3 1,174 32 (327 ) 882 Operating Income (3 ) 422 — — 419 Equity Earnings (Losses) of Subsidiaries 257 (5 ) — (252 ) — Other Income 14 91 — (19 ) 86 Other Deductions — (44 ) — — (44 ) Interest Expense (36 ) (15 ) (7 ) 19 (39 ) Income Tax Benefit (Expense) 25 (192 ) 2 — (165 ) Net Income (Loss) $ 257 $ 257 $ (5 ) $ (252 ) $ 257 Three Months Ended June 30, 2008 Operating Revenues $ — $ 1,905 $ 32 $ (314 ) $ 1,623 Operating Expenses 3 1,461 32 (313 ) 1,183 Operating Income (Loss) (3 ) 444 — (1 ) 440 Equity Earnings (Losses) of Subsidiaries 249 (10 ) — (239 ) — Other Income 34 106 — (47 ) 93 Other Deductions — (55 ) — — (55 ) Other Than Temporary Impairments — (32 ) — — (32 ) Interest Expense (53 ) (21 ) (13 ) 46 (41 ) Income Tax Benefit (Expense) 13 (183 ) 3 2 (165 ) Net Income (Loss) $ 240 $ 249 $ (10 ) $ (239 ) $ 240 57
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power Guarantor Other Consolidating Consolidated Millions Six Months Ended June 30, 2009 Operating Revenues $ — $ 4,256 $ 62 $ (643 ) $ 3,675 Operating Expenses 6 3,224 62 (643 ) 2,649 Operating Income (Loss) (6 ) 1,032 — — 1,026 Equity Earnings (Losses) of Subsidiaries 589 (11 ) — (578 ) — Other Income 37 173 — (54 ) 156 Other Deductions — (94 ) — — (94 ) Other Than Temporary Impairments — (60 ) — — (60 ) Interest Expense (89 ) (32 ) (15 ) 54 (82 ) Income Tax Benefit (Expense) 44 (419 ) 4 — (371 ) Net Income (Loss) $ 575 $ 589 $ (11 ) $ (578 ) $ 575 Six Months Ended June 30, 2009 Net Cash Provided By (Used In) Operating Activities $ 104 $ 1,806 $ (34 ) $ (676 ) $ 1,200 Net Cash Provided By (Used In) Investing Activities $ (263 ) $ (1,438 ) $ (1 ) $ 1,146 $ (556 ) Net Cash Provided By (Used In) Financing Activities $ 159 $ (369 ) $ 35 $ (469 ) $ (644 ) Six Months Ended June 30, 2008 Operating Revenues $ — $ 4,532 $ 59 $ (593 ) $ 3,998 Operating Expenses 5 3,578 59 (593 ) 3,049 Operating Income (Loss) (5 ) 954 — — 949 Equity Earnings (Losses) of Subsidiaries 530 (20 ) — (510 ) — Other Income 73 207 — (101 ) 179 Other Deductions — (108 ) — — (108 ) Other Than Temporary Impairments — (70 ) — — (70 ) Interest Expense (106 ) (49 ) (28 ) 100 (83 ) Income Tax Benefit (Expense) 23 (384 ) 8 1 (352 ) Net Income (Loss) $ 515 $ 530 $ (20 ) $ (510 ) $ 515 Six Months Ended June 30, 2008 Net Cash Provided By (Used In) Operating Activities $ (1,349 ) $ 835 $ (31 ) $ 1,011 $ 466 Net Cash Provided By (Used In) Investing Activities $ 1,599 $ (928 ) $ (3 ) $ (1,040 ) $ (372 ) Net Cash Provided By (Used In) Financing Activities $ (250 ) $ 99 $ 34 $ 29 $ (88 ) 58
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power Guarantor Other Consolidating Consolidated Millions As of June 30, 2009: Current Assets $ 2,474 $ 6,041 $ 447 $ (6,680 ) $ 2,282 Property, Plant and 54 4,740 908 — 5,702 Investment in Subsidiaries 5,013 521 — (5,534 ) — Noncurrent Assets 226 1,307 57 (168 ) 1,422 Total Assets $ 7,767 $ 12,609 $ 1,412 $ (12,382 ) $ 9,406 Current Liabilities $ 438 $ 6,478 $ 776 $ (6,682 ) $ 1,010 Noncurrent Liabilities 427 1,119 114 (166 ) 1,494 Long-Term Debt 2,862 — — — 2,862 Member’s Equity 4,040 5,012 522 (5,534 ) 4,040 Total Liabilities and $ 7,767 $ 12,609 $ 1,412 $ (12,382 ) $ 9,406 As of December 31, 2008: Current Assets $ 2,395 $ 5,507 $ 439 $ (5,636 ) $ 2,705 Property, Plant and 44 4,513 924 — 5,481 Investment in Subsidiaries 4,758 384 — (5,142 ) — Noncurrent Assets 244 1,166 50 (187 ) 1,273 Total Assets $ 7,441 $ 11,570 $ 1,413 $ (10,965 ) $ 9,459 Current Liabilities $ 371 $ 5,880 $ 919 $ (5,637 ) $ 1,533 Noncurrent Liabilities 532 935 109 (187 ) 1,389 Long-Term Debt 2,653 — — — 2,653 Member’s Equity 3,885 4,755 385 (5,141 ) 3,884 Total Liabilities and $ 7,441 $ 11,570 $ 1,413 $ (10,965 ) $ 9,459 59
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
Equipment, net
Member’s Equity
Equipment, net
Member’s Equity
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) This combined MD&A is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company. PSEG’s business consists of three reportable segments, which are: • Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid Atlantic U.S., • PSE&G, which provides transmission and distribution of electricity and gas in New Jersey, and • Energy Holdings, which owns our other generation assets and holds other energy-related investments. OVERVIEW OF 2009 AND FUTURE OUTLOOK Our business discussion in Part I Item 1 Business of our 2008 Annual Report on Form 10-K provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. The following discussion supplements that discussion and the discussion included in the Overview of 2008 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2009 and any changes to the key factors that we expect will drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2008 Annual Report on Form 10-K. Operational Excellence Our generating assets continued to perform with strong operations in the first half of 2009. Our nuclear generation output for the first six months of 2009 was higher than in the comparable period in 2008. While our fossil fleet also continued to perform well, fossil generation volumes were approximately 25% lower than in the comparable period in 2008. The volumes were negatively impacted by reduced demand due to cooler weather and the general economic slowdown. The largest reduction in volume was at our coal units due to higher-priced coal in 2009 than in 2008. For the first half of 2009, our hedging strategy has resulted in higher average realized electric prices than a year ago, which helped to mitigate the effect of our reduced generation resulting from recent mild weather and recessionary conditions. The increase in realized prices was due to comparably higher-priced contracts entered into in prior years that replaced older, lower-priced contracts, such as the 2005 and 2006 Basic Generation Service (BGS) auction contracts which expired in May 2008 and May 2009. Looking forward, the lower market prices being experienced currently could create a less attractive environment for Power to contract for the future sale of its anticipated generation output. We continue to receive strong pricing for our capacity. As a result of the most recent Reliability Pricing Model (RPM) auction for the 2012-2013 period, the prices set for our generation assets in PJM were $185.00 per MW-day in PSEG-North, $139.73 per MW-day in Eastern Mid-Atlantic Area Corridor (MAAC) and $133.37 per MW-day in MAAC. These prices compared favorably with the $110.00 per MW-day set for each of these regions for the 2011-2012 period. PJM has accepted our proposal for 178 MW of new capacity to be added for the 2012-2013 period. Our distribution operations experienced a 5.6% increase in total gas delivery volumes and 3.7% decline in total electric delivery volumes in the first half of 2009 as compared to the same period in 2008 as a result of weather impacts and the current economic conditions. In the first half of 2009, winter weather, as 60
measured by heating degree days was 7% higher resulting in higher gas space heating demand and sales. Summer weather, as measured by the temperature-humidity index, however, was 41% cooler than normal, reducing cooling loads and, as a result, electric demand. Excluding the impact of weather, residential electric and gas volumes were down 1.1% and 0.4%, respectively. These declines were in line with our expectations for the impact of the economy on sales to this sector. Residential sales contribute approximately 45% of our electric margin and 75% of our gas margin. In the Commercial and Industrial segments, billings to electric customers are not based on total energy consumption as measured by kilowatt-hours. They are based on fixed, monthly demand charges that are set by the highest electric demand for an hour period during the previous 12-month period or, in the case of some electric rates, by the peak demand during the current month. Commercial and Industrial gas customers also have a significant fixed component to billings. Therefore, any changes in energy usage over comparative periods may not have an equivalent impact on sales margin. On May 29, 2009, we filed a Petition with the BPU for an increase in electric and gas distribution base rates. The amounts requested were $134 million and $97 million for electric and gas respectively. We expect this matter to be resolved during the first half of 2010. During 2008 and the first quarter of 2009, we undertook a project to update our customer service system. In April 2009, our customer service system was fully integrated into our utility operations. During the first six months there were also two significant regulatory developments that we believe have the potential to positively impact future operations. • In March 2009, the Federal Energy Regulatory Commission (FERC) issued an order regarding PJM’s RPM. The effect of this order includes an increase in the cost of new entry value to more accurately reflect construction and equipment costs. This should incent both new build and continued operation of existing facilities. For additional information, see Part II, Item 1. Legal Proceedings. • On April 1, 2009, the U.S. Supreme Court concluded that the U.S. Environmental Protection Agency (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 Section 316(b) regulations of the Federal Water Pollution Control Act. This is important to us in that it allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. For additional information, see Note 6. Commitments and Contingent Liabilities. There continue to be significant developments addressing the need to promote clean and renewable energy, energy efficiency and the reduction of greenhouse gases which may impact our operations in the future as new rules and regulations are adopted. • In April 2009 the EPA released a proposed finding under the Clean Air Act concluding that CO2 is one type of six specific greenhouse gases which cause or contribute to the climate change problem and constitute air pollution which endangers both public health and welfare. If applied to fossil fuel generation facilities, additional regulation of CO2 emissions could impact our operations, our ability to renew permits and licenses and could result in additional material compliance costs. • In June 2009, the U.S. House of Representatives passed a bill that promotes renewable energy and requires a reduction in the emission of greenhouse gases from the majority of emission sources, including the generation sector. The bill sets forth major initiatives which include: 1) establishing a national renewable energy standard, and 2) creating a market mechanism for the sale and purchase of greenhouse gas emission allowances (cap-and-trade program). The bill could reduce or eliminate existing regional inconsistencies in greenhouse gas regulations. The Senate is expected to consider these issues as well as transmission planning, siting and cost allocation issues in the fourth quarter, but ultimate enactment into law of a bill with comparable provisions and rules is not certain. 61
Financial Strength In 2009, we have continued to focus on managing costs while maintaining our safety and reliability standards and believe that our financial position remains strong. Our businesses continued to generate strong cash from operations in the first six months of 2009. In addition, Power established a program for the issuance of up to $500 million of unsecured medium-term notes (MTNs) to retail investors in January and, to date, has issued $209 million under this program. We used these funds, cash from operations, and cash on hand to: • contribute $364 million into our pension plans in 2009, • pay $250 million of Power’s 3.75% Senior Notes at maturity, • pay $60 million of PSE&G’s 8.10% and 8.16% MTNs at maturity, • make an additional $140 million deposit with the IRS to defray potential interest costs associated with the disputed tax liability for the leveraged lease investments, • redeem $280 million of non-recourse debt at our Texas plants at the end of February, and • repurchase $10 million of Energy Holdings’ remaining Senior Notes. The Board of Directors has also approved an increase in the quarterly dividends from $0.3225 per share to $0.3325 per share of Common Stock for each of the first three quarters of 2009 resulting in an indicated annual dividend of $1.33 per share. This increase is consistent with maintaining our target payout ratio of 40% to 50% of Operating Earnings. In addition, in order to reduce the cash tax exposure related to certain lease transactions, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds and where the transactions in total will result in a positive or neutral earnings and cash impact. Proceeds from these terminations are being used to reduce Energy Holdings’ tax exposure related to these investments. See Note 6. Commitments and Contingent Liabilities for additional information. Disciplined Investment During 2009, we expect to continue to pursue investments focusing on areas that complement our existing businesses and provide prudent growth opportunities. These areas include responding to climate change and continuing to improve environmental performance, upgrading critical energy infrastructure and providing new energy supplies. During 2009: • We were assigned construction and operating responsibility for an additional 500 kV transmission project in New Jersey. The project would run from Branchburg to Hudson. The project is still in the design phase. • We are continuing to pursue obtaining all necessary regulatory approvals for the $750 million Susquehanna-Roseland transmission project. The New Jersey Highlands Council has provided a favorable applicability determination. A decision by the New Jersey Department of Environmental Protection is now pending. A decision from the BPU is expected by the end of 2009. • We requested approval from the BPU for a new solar loan program, called “Solar Loan II”. Under Solar Loan II, we would help finance the installation of an additional 40 MW of solar-powered generating systems in our electric service territory. Any remaining financing capacity from our current solar loan program would be rolled into this new program. • The BPU approved our Solar 4 All Program. Under this program, we anticipate investing approximately $515 million of capital, and $22 million for operations and maintenance, to develop 80 MW of utility-owned solar photovoltaic systems over a four-year horizon. • The BPU approved our Capital Economic Stimulus Program. Under this program, we anticipate accelerating $694 million of capital infrastructure investments and 62
maintenance, through our distribution and transmission business for electric and gas programs in New Jersey over a 24-month period. The goal of the program is to help improve New Jersey’s economy through the creation of new jobs, while enhancing distribution and transmission business infrastructure. • The BPU issued an Order approving our Energy Efficiency Economic Stimulus Program. Under this program, we anticipate investing approximately $166 million of capital, and $24 million in operations and maintenance, in energy efficiency expenditures through PSE&G for electric and gas programs in New Jersey over an 18 month period. Goals of the program are to help New Jersey meet its Energy Master Plan goal of reducing energy consumption by 20% by 2020 and to help improve New Jersey’s economy through the creation of new jobs. • We have 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 began in July 2009 and are expected to continue through 2012. We anticipate expenditures in pursuit of additional output through an extended power up-rate of our co-owned Peach Bottom nuclear plants. The up-rate is expected to be in service in 2015 for unit 2 and 2016 for unit 3. Power’s share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million. • We plan to construct 178 MW of gas-fired peaking capacity at Power’s Kearny site. This capacity was bid into and has cleared the PJM RPM base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to commence in the third quarter of 2011. The project is expected to be in-service by June 2012. We estimate the cost of these generating units to be $160 million to $200 million. Total capitalized expenditures to date were $7 million which are included in Other Noncurrent Assets in Power’s and PSEG’s Condensed Consolidated Balance Sheets. There is no guarantee that these or future initiatives will be achieved since many issues need to be favorably resolved, such as system conditions, regulatory approvals and funding of construction or development costs. We receive immediate recovery of our transmission investments and costs through our FERC approved formula transmission rate. The formula rate mechanism provides for an annual setting of our transmission rates as well an annual true up to ensure that there is no over-recovery or under- recovery of the actual costs of providing transmission service or in PSE&G’s approved return on equity. We have similar recovery mechanisms in place, which have been approved by the BPU, for certain utility programs including our Capital Economic Stimulus Program, Solar 4 All Program, Solar Loan Programs and the energy efficiency and demand response programs. 63
The results for PSEG, PSE&G, Power and Energy Holdings for the quarters and six months ended June 30, 2009 and 2008 are presented below: Earnings (Losses) Three Months Six Months 2009 2008 2009 2008 Millions Power $ 257 $ 240 $ 575 $ 515 PSE&G 44 52 168 189 Energy Holdings 10 (453 ) 17 (424 ) Other — (5 ) (5 ) (11 ) PSEG Income (Loss) from Continuing Operations $ 311 $ (166 ) $ 755 $ 269 Income from Discontinued Operations — 16 — 29 Net Income (Loss) $ 311 $ (150 ) $ 755 $ 298 Earnings Per Share (Diluted) Three Months Ended Six Months Ended 2009 2008 2009 2008 PSEG Income (Loss) from Continuing Operations $ 0.61 $ (0.32 ) $ 1.49 $ 0.53 Income from Discontinued Operations — 0.03 — 0.06 PSEG Net Income (Loss) $ 0.61 $ (0.29 ) $ 1.49 $ 0.59 Our results include the following after-tax impacts of mark-to-market (MTM) activity: Non-Trading Mark-to-Market (MTM) After Tax Three Months Ended Six Months Ended 2009 2008 2009 2008 Millions Power $ 2 $ 27 $ (16 ) $ 30 Energy Holdings (26 ) (13 ) (23 ) (11 ) Total $ (24 ) $ 14 $ (39 ) $ 19 Both the quarter-over-quarter and six-month over six month increases in our Income from Continuing Operations reflect the following large drivers: • the absence of a charge taken in June 2008 related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and • improved earnings at Power due to lower generation costs and higher contract pricing, • offset partially by lower sales volumes due to milder weather in the second quarter and economic conditions, and • the absence of tax benefits taken in 2008 at PSE&G and Energy Holdings related to an IRS refund claim and other tax items. 64
Ended
June 30,
Ended
June 30,
June 30,
June 30,
June 30,
June 30,
PSEG Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, and charitable contributions along with general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 15. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below. Three Months Ended Increase/ Six Months Ended Increase/ 2009 2008 2009 2008 Millions % Millions % Operating Revenues $ 2,561 $ 2,550 $ 11 — $ 6,482 $ 6,342 $ 140 2 Energy Costs 1,067 1,535 (468 ) (30 ) 3,135 3,654 (519 ) (14 ) Operation and Maintenance 628 620 8 1 1,303 1,247 56 4 Depreciation and Amortization 203 191 12 6 410 383 27 7 Income from Equity Method Investments 9 7 2 29 19 19 — — Impairment on Equity Method Investments 8 — 8 N/A 8 — 8 N/A Other Income and (Deductions) 47 41 6 15 63 77 (14 ) (18 ) Other Than Temporary Impairments 1 32 (31 ) (97 ) 61 70 (9 ) (13 ) Interest Expense 133 146 (13 ) (9 ) 278 299 (21 ) (7 ) Income Tax Expense 240 213 27 13 544 446 98 22 Income from Discontinued — 16 (16 ) (100 ) — 29 (29 ) (100 ) Power Three Months Ended Increase/ Six Months Ended Increase/ 2009 2008 2009 2008 Millions Income from Continuing Operations $ 257 $ 240 $ 17 $ 575 $ 515 $ 60 Net Income $ 257 $ 240 $ 17 $ 575 $ 515 $ 60 For the three months ended June 30, 2009, the primary reasons for the $17 million increase in Income from Continuing Operations were: • lower net losses on investments in the Nuclear Decommissioning Trust (NDT) Funds and lower maintenance costs, • offset partially by lower sales volumes on generation and BGS contracts mitigated by lower generation costs, and • reduced sales volumes under the Basic Gas Supply Service (BGSS) contract mitigated by lower gas costs, and lower trading gains. Included is the recognition of non-trading MTM gains of $2 million, after-tax, in 2009 as compared to $27 million in 2008. 65
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
Operations, net of tax
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
For the six months ended June 30, 2009, the primary reasons for the $60 million increase in Income from Continuing Operations were: • lower generation costs offset lower sales volumes and prices on generation, and • slightly improved margins on higher sales volumes at lower inventory costs under the BGSS contract, • offset partially by higher maintenance costs for planned outage work and higher depreciation due to additional assets having been placed in service. Included is the recognition of non-trading MTM losses of $16 million, after-tax, in 2009 as compared to $30 million of after-tax MTM gains in 2008. The quarter and year-to-date details for these variances are discussed below: Three Months Ended Increase/ Six Months Ende Increase/ 2009 2008 2009 2008 Millions % Millions % Operating Revenues $ 1,301 $ 1,623 $ (322 ) (20 ) $ 3,675 $ 3,998 $ (323 ) (8 ) Energy Costs 563 867 (304 ) (35 ) 2,025 2,456 (431 ) (18 ) Operation and Maintenance 271 275 (4 ) (1 ) 529 514 15 3 Depreciation and Amortization 48 41 7 17 95 79 16 20 Other Income and (Deductions) 42 38 4 11 62 71 (9 ) (13 ) Other Than Temporary Impairments — 32 (32 ) (100 ) 60 70 (10 ) (14 ) Interest Expense 39 41 (2 ) (5 ) 82 83 (1 ) (1 ) Income Tax Expense 165 165 — — 371 352 19 5 For the three months ended June 30, 2009 as compared to 2008 Operating Revenues decreased $322 million due to: • Generation revenues decreased $167 million due to ¡ lower revenues of $148 million resulting from lower volumes of generation being sold at lower prices, and ¡ a net decrease of $26 million due to a lower volume of BGS contracts mitigated slightly by higher prices, ¡ offset partially by higher revenues of $14 million due to several new wholesale contracts that were entered into in late 2008 and early 2009. • Gas Supply revenues decreased $138 million
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008 ¡
including a net decrease of $110 million resulting from sales under the BGSS contract, comprised of $132 million from lower average gas prices in 2009, offset partially by $18 million of gains on financial hedging transactions, and by higher sales volumes of $4 million, and
¡
a net decrease of $28 million due to lower prices offset partially by increased sales volume to third party customers.
| ||||||||||||||||||||
• |
| Trading revenues decreased $17 million due primarily to losses on gas contracts, partly offset by gains on electric-related contracts. | ||||||||||||||||||
66
Operating Expenses •
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased by $304 million due to:
|
| ¡ |
Generation costs decreased by $167 million due to $315 million of lower fuel costs, primarily reflecting lower average natural gas prices and lower volumes of natural gas and coal purchases, partly offset by net losses of $101 million from financial hedging transactions, $23 million of increased congestion charges, and $23 million for increased power purchases.
¡
Gas costsdecreased $137 million, reflecting net decreases of $109 million and $28 million related to Power’s obligations under the BGSS contract and sales to third party customers, respectively, reflecting lower inventory costs offset partially by higher volumes.
| ||||||||||||||||||||
• |
| Operation and Maintenance decreased $4 million due primarily to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| a net decrease of $37 million due to 2008 planned maintenance costs at our fossil stations, primarily Hudson, and Mercer and Linden, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by an increase of $33 million related primarily to Peach Bottom and Hope Creek planned outage costs. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Depreciation and Amortization increased $7 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $4 million due to pollution control equipment being placed into service in December 2008 at our Mercer 1 and 2 generating facilities and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $3 million resulting from larger depreciable asset bases in 2009 at both Fossil and Nuclear. | ||||||||||||||||||
Other Income and Deductions increased $4 million due to
| ||||||||||||||||||||
• |
| a net decrease in losses of $11 million on the NDT Fund securities, | ||||||||||||||||||
| ||||||||||||||||||||
• |
| offset partially by a decrease of $7 million in interest, dividends and gains on NDT Fund derivative instruments. | ||||||||||||||||||
Other Than Temporary Impairmentsdecreased $32 million due to the absence of charges related to the NDT Fund securities in 2009 as compared to $32 million recorded in 2008 (See Note 2. Recent Accounting Standards, for additional information).
Interest Expense experienced no material change.
Income Tax Expense experienced no material change.
For the six months ended June 30, 2009 as compared to 2008
Operating Revenues decreased $323 million due to:
| ||||||||||||||||||||
• |
| Generation revenues decreased $109 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| lower revenues of $186 million resulting from lower volumes of generation being sold at lower prices, and lower capacity payments of $19 million, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by a net increase of $62 million from higher prices on a higher volume of BGS contracts modestly offset by the expiration of several contracts in May 2008, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| also offset by higher revenues of $35 million due to several new wholesale contracts that were entered into in late 2008 and early 2009. | ||||||||||||||||||
67
• Gas Supply revenues decreased $213 million ¡
including a net decrease of $118 million resulting from sales under the BGSS contract, comprised of $158 million from lower average gas prices in 2009 net of gains on financial hedging transactions, partly offset by higher sales volumes of $40 million due to colder winter temperatures in 2009, and
¡
a net decrease of $95 million due to lower prices on a reduced sales volume to third party customers.
| ||||||||||||||||||||
• |
| Trading revenues decreased $1 million due primarily to losses on gas contracts, partly offset by gains on electric-related contracts. | ||||||||||||||||||
Operating Expenses
|
| • |
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased by $431 million due to:
|
| ¡ |
Generation costsdecreased by $206 million due to $417 million of lower fuel costs, primarily reflecting lower average natural gas prices and lower volumes of natural gas and coal purchases, partly offset by net losses of $154 million from financial hedging transactions, $17 million for CO2 allowances, $15 million for increased power purchases and $12 million for congestion charges.
¡
Gas costsdecreased $225 million, reflecting net decreases of $122 million and $103 million related to Power’s obligations under the BGSS contract and sales to third party customers, respectively, reflecting lower inventory costs offset partially by higher volumes.
| ||||||||||||||||||||
• |
| Operation and Maintenance increased $15 million due primarily to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $41 million related primarily to a planned outage at Hope Creek, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $12 million related to planned maintenance at Keystone, Bergen and BEC, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by a net decrease of $39 million due to 2008 planned maintenance costs at our fossil stations, primarily Hudson and Mercer. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Depreciation and Amortization increased $16 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $9 million due to pollution control equipment being placed into service in December 2008 at our Mercer 1 and 2 generating facilities, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| an increase of $7 million resulting from larger depreciable asset bases in 2009 at both Fossil and Nuclear. | ||||||||||||||||||
Other Income and Deductions decreased $9 million due to
| ||||||||||||||||||||
¡ |
| a decrease of $22 million in interest, dividends and gains on NDT Fund derivative instruments, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| a $5 million write-off of obsolete pollution-control equipment, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by a net decrease in losses of $18 million on the NDT Fund securities. | ||||||||||||||||||
Other Than Temporary Impairmentsdecreased $10 million due to the lower charges in 2009 related to the NDT Fund securities (See Note 2. Recent Accounting Standards, for additional information)
Interest Expense experienced no material change.
Income Tax Expense increased $19 million in 2009 due primarily to
| ||||||||||||||||||||
• |
| an increase of $30 million due to higher pre-tax income and $1 million due to higher earnings from the NDT Funds, | ||||||||||||||||||
| ||||||||||||||||||||
• |
| offset partially by $8 million from the reduction of the reserve for uncertain tax positions, and | ||||||||||||||||||
| ||||||||||||||||||||
• |
| also offset by $4 million due to increased benefits from a manufacturing deduction under the American Jobs Creation Act of 2004. | ||||||||||||||||||
68
PSE&G Three Months Ended Increase/ Six months Ended Increase/ 2009 2008 2009 2008 Millions Income from Continuing Operations $ 44 $ 52 $ (8 ) $ 168 $ 189 $ (21 ) Net Income $ 44 $ 52 $ (8 ) $ 168 $ 189 $ (21 ) For the quarter and six months ended June 30, 2009, the primary reasons for the decreases in Income from Continuing Operations were: • higher taxes as a result of tax benefits recorded in 2008 related to an IRS refund claim and other tax items, • lower electric margins due to unfavorable weather in the second quarter, and • increased Operation and Maintenance expense and depreciation, offset by • higher gas margin revenues due to favorable weather in the first quarter, and • a Transmission formula rate increase. The quarter and year-to-date details for these variances are discussed below. Three Months Ended Increase/ Six Months Ended Increase/ 2009 2008 2009 2008 Millions % Millions % Operating Revenues $ 1,643 $ 1,858 $ (215 ) (12 ) $ 4,378 $ 4,476 $ (98 ) (2 ) Energy Costs 979 1,213 (234 ) (19 ) 2,838 3,006 (168 ) (6 ) Operation and Maintenance 344 320 24 8 739 680 59 9 Depreciation and Amortization 144 139 5 4 293 282 11 4 Other Income and (Deductions) 3 2 1 N/A 3 6 (3 ) N/A Interest Expense 80 81 (1 ) (1 ) 159 162 (3 ) (2 ) Income Tax Expense 29 28 1 4 114 93 21 23 For the three months ended June 30, 2009 as compared to 2008 Operating Revenues decreased $215 million due primarily to • Commodity related revenues decreased $234 million due to ¡ decreased electric revenues of $136 million due primarily to ¡ $78 million in lower BGS and Non-utility Generation Charges (NGC) revenues for decreased sales of $111 million offset by higher prices of $33 million and ¡ $58 million in lower non-utility generation (NUG) revenues due primarily to lower prices. ¡ decreased gas revenues of $98 million due to $91 million in decreased BGSS prices and $7 million in lower sales due to economic conditions. • Delivery revenues increased $20 million due to ¡ increased gas revenues of $9 million due to $6 million of higher sales due to favorable weather and $3 million due to higher Societal Benefits Clause (SBC) revenues and ¡ increased electric revenues of $11 million due to 69
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
¡ $11 million for SBC revenues, $11 million for net transmission rate increases, $3 million in higher demand revenues, $3 million for a securitization transition charge rate increase and $1 million in stimulus rate increases, ¡ offset partially by $20 million in decreased distribution sales and demands due to weather and economic conditions. ¡ PSE&G retains no margins from SBC or Securitization Transition Charges collections as the revenues are offset in operating expenses below. Operating Expenses • Energy Costs decreased $234 million due to ¡
decreased electric costs of $136 million due to $22 million or 2 % in lower prices for BGS and NUG purchases and $114 million or 13 % in lower BGS and NUG volumes due to economic conditions, and
¡
decreased gas costs of $97 million due to $91 million or 28 % lower prices offset by $6 million or 2% in lower sales volumes due to economic conditions.
| ||||||||||||||||||||
• |
| Operation and Maintenance increased $24 million due primarily to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| $16 million of higher labor and benefits, primarily increased pension expense, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| increases in SBC expenses of $14 million, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by lower materials usage of $4 million, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| lower overhead and administrative expenses of $2 million. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Depreciation and Amortization increased $5 million due primarily to additional plant in service. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Other Income and Deductions experienced no material change. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Interest Expense experienced no material change. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Income Tax Expense experienced no material change. | ||||||||||||||||||
For the six months ended June 30, 2009 as compared to 2008
Operating Revenues decreased $98 million due primarily to
| ||||||||||||||||||||
• |
| Commodity related revenues decreased $170 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| decreased electric revenues of $61 million due primarily to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| $80 million in lower NUG revenues, due primarily to lower prices, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset by $19 million in higher BGS and NGC revenues due to higher prices of $159 million offset by decreased sales of $140 million. | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| decreased gas revenues of $109 million due to $139 million in decreased BGSS prices offset by $30 million in higher sales due to weather. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Delivery revenues increased $72 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| increased gas revenues of $39 million due to $24 million of higher sales due to favorable weather and $15 million due to higher SBC revenues and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| increased electric revenues of $33 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| $24 million for SBC revenues, $19 million for net transmission rate increases, $3 million in higher demand revenues, $7 million for a securitization transition charge rate increase. and $1 million in stimulus rate increases, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by $24 million in decreased distribution sales and demands due to weather and economic conditions. | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| PSE&G retains no margins from SBC or STC collections as the revenues are offset in operating expenses below. | ||||||||||||||||||
70
Operating Expenses •
Energy Costs decreased $168 million due to
|
| ¡ |
decreased electric costs of $62 million due to $151 million or 9 % in lower BGS and NUG volumes due to unfavorable weather and economic conditions offset by $89 million or 5 % in higher prices for BGS and NUG purchases and
¡
decreased gas costs of $108 million due to $138 million or 10 % lower prices offset by $30 million or 2 % in higher sales volumes due to favorable weather.
| ||||||||||||||||||||
• |
| Operation and Maintenance increased $59 million due primarily to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| increases in SBC expenses of $44 million, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| $27 million of higher labor and benefits, primarily increased pension expense, | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| offset partially by lower materials usage of $9 million, and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| lower overhead and administrative expenses of $5 million. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Depreciation and Amortization increased $11 million due primarily to additional plant in service. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Other Income and Deductions experienced no material change. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Interest Expenseexperienced no material change. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Income Tax Expense increased $21 million due primarily to tax benefits taken in 2008 related to an IRS refund claim. | ||||||||||||||||||
Energy Holdings
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||
Three Months Ended | Increase/ | Six Months Ended | Increase/ | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||||
| Millions | |||||||||||||||||||||||||||||||||||||||||
Income (Loss) from Continuing Operations | $ | 10 | $ | (453 | ) | $ | 463 | $ | 17 | $ | (424 | ) | $ | 441 | ||||||||||||||||||||||||||||
Income from Discontinued Operations, net of tax |
| — |
| 16 |
| (16 | ) |
|
| — |
| 29 |
| (29 | ) |
| ||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||
Net Income (Loss) | $ | 10 | $ | (437 | ) | $ | 447 | $ | 17 | $ | (395 | ) | $ | 412 | ||||||||||||||||||||||||||||
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||
For the quarter and six months ended June 30, 2009, the primary reasons for the increase in Income from Continuing Operations were:
| ||||||||||||||||||||
• |
| the absence of a charge taken in June 2008, related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and | ||||||||||||||||||
| ||||||||||||||||||||
• |
| higher gains on sales and terminations of leveraged lease assets and other investments, | ||||||||||||||||||
| ||||||||||||||||||||
• |
| offset partially by lower leveraged lease revenues due primarily to the sale of leveraged lease assets and the tax reserve taken in mid-2008, | ||||||||||||||||||
| ||||||||||||||||||||
• |
| lower tax benefits as a result of the absence of benefits recorded in 2008 related to an IRS refund claim, and | ||||||||||||||||||
| ||||||||||||||||||||
• |
| lower generation revenues. | ||||||||||||||||||
The quarter and year-to date details for these variances are discussed below:
71
Three Months Ended Increase/ Six Months Ended Increase/ 2009 2008 2009 2008 Millions % Millions % Operating Revenues $ 158 $ (240 ) $ 398 N/A $ 293 $ (109 ) $ 402 N/A Energy Costs 65 145 (80 ) (55 ) 134 213 (79 ) (37 ) Operation and Maintenance 21 32 (11 ) (34 ) 51 67 (16 ) (24 ) Depreciation and Amortization 7 8 (1 ) (13 ) 14 15 (1 ) (7 ) Income from Equity Method Investments 9 7 2 29 19 19 — — Impairment on Equity Method Investments 8 — 8 N/A 8 — 8 N/A Other Income and (Deductions) 2 3 (1 ) (33 ) 5 6 (1 ) (17 ) Interest Expense 11 19 (8 ) (42 ) 30 42 (12 ) (29 ) Income Tax Expense 47 19 28 N/A 63 3 60 N/A Income from Discontinued Operations, net of Tax — 16 (16 ) (100 ) — 29 (29 ) (100 ) For the three months ended June 30, 2009 as compared to 2008 Operating Revenues increased $398 million due to • the absence of a $485 million charge taken in June 2008, related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and • a gain of $76 million on the sales and terminations of leveraged lease assets and other investments in 2009, • offset partially by a decrease of $152 million in generation revenues at PSEG Texas due to a decrease in electricity prices and sales offset partially by lower unrealized MTM losses in 2009, and • lower leveraged lease revenues of $13 million, due primarily to the impact of the tax charge taken in 2008, and the sale of leveraged lease assets. Operating Expenses • Energy Costs decreased $80 million due primarily to lower fuel prices and lower fuel consumption, offset partially by lower unrealized MTM gains. • Operation and Maintenance decreased $11 million due primarily to ¡ a decrease of $7 million in outside service costs, wages, salaries and benefits and ¡ a decrease of $4 million in administrative costs due to the closure of our administrative office in Texas. • Depreciation and Amortization experienced no material change. Income from Equity Method Investments experienced no material change. Impairment on Equity Method Investments increased by $8 million due to a pre-tax write-down of GWF Energy in 2009 and reserves against GWF earnings. Other Income and Deductions experienced no material change Interest Expense decreased $8 million due primarily to lower debt balances. Income Tax Expense increased $28 million primarily due to the sale of leverage lease assets in 2009, partially offset by a lower effective tax rate on operations in 2009. 72
June 30,
(Decrease)
2009 vs 2008
June 30,
(Decrease)
2009 vs 2008
Income from Discontinued Operations, net of tax During 2008, we sold our investments in SAESA Group and Bioenergie. Income from Discontinued Operations relating to these investments for the quarter ended June 30, 2008 totaled $16 million. See Note 3. Discontinued Operations and Dispositions for additional information. For the six months ended June 30, 2009 as compared to 2008 Operating Revenues increased $402 million due to •
the absence of $485 million charge taken in June 2008, related to IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions, and
•
a gain of $99 million on the sales and terminations of leveraged lease assets and other investments in 2009,
•
offset partially by lower leveraged lease revenues of $25 million, due primarily to the impact of the tax charge taken in 2008, the sale of leveraged lease assets, and
•
a decrease of $158 million in generation revenues due to lower electricity prices and sales and lower unrealized MTM gains in 2009.
Operating Expenses
| ||||||||||||||||||||
• |
| Energy Costs decreased $79 million, due primarily to lower fuel prices and lower fuel consumption, offset partially by higher unrealized MTM losses. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Operation and Maintenance decreased $16 million due to | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| a decrease of $8 million in outside service costs, wages, salaries and benefits and | ||||||||||||||||||
| ||||||||||||||||||||
¡ |
| a decrease of $8 million in administrative costs due to the closure of our administrative office in Texas. | ||||||||||||||||||
| ||||||||||||||||||||
• |
| Depreciation and Amortization experienced no material change. | ||||||||||||||||||
Impairment on Equity Method Investments increased by $8 million due to a pre-tax write-down of GWF Energy in 2009, which includes reserves against GWF earnings.
Other Income and Deductions experienced no material change.
Interest Expense decreased $12 million due primarily to lower debt balances.
Income Tax Expense increased $60 million primarily due to the sale of leverage lease assets in 2009.
Income from Discontinued Operations, net of tax
During 2008, we sold our investments in SAESA Group and Bioenergie. Income from Discontinued Operations relating to these investments for the six months ended June 30, 2008 totaled $29 million. See Note 3. Discontinued Operations and Dispositions for additional information.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.
Operating Cash Flows
Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund capital expenditures and shareholder dividend payments.
For the six months ended June 30, 2009, our operating cash flow increased by $166 million as compared to the same period in 2008. The net change was due primarily to net changes from our subsidiaries as discussed below.
Power
Power’s operating cash flow increased $734 million from $466 million to $1.2 billion for the six months ended June 30, 2009, as compared to the same period in 2008, primarily resulting from
|
| ¡ |
an increase of $429 million in net cash collateral receipts, and
73
¡ an increase of $350 million from net collections of counterparty receivables, ¡ offset partially by $110 million in increased pension fund contributions in 2009. PSE&G PSE&G’s operating cash flow decreased $377 million from $282 million to $(95) million for the six months ended June 30, 2009, as compared to the same period in 2008, due primarily to ¡
$227 million in increased pension fund contributions,
¡
$184 million in lower cash collateral held by PSE&G, primarily under BGS contracts due to a decline in forward prices, and
¡
$44 million in higher prepaid state sales taxes,
¡
offset by $74 million in higher recovery of deferred energy costs.
Energy Holdings
Energy Holdings’ operating cash flow decreased $166 million from $(119) million to $(285) for the six months ended June 30, 2009, as compared to the same period in 2008. The decrease was mainly attributable to a $140 million tax deposit made with the IRS in the second quarter of 2009, and other tax payments related to the termination of leveraged lease investments, offset partially by tax payments in 2008 related to the sales of certain equity method investments.
Short-Term Liquidity
We have been managing our liquidity to assure that we continue to have sufficient access to cash to operate our businesses in the event the capital markets do not allow for near-term financing at reasonable terms. We are also closely monitoring the financial condition and concentration of lenders in our bank facilities. There is no provision in any of the credit facilities that would require other lenders in the facility to assume loan commitments of any financial institution that fails to meet its loan commitments. As of June 30, 2009, no single institution represents more than 11% of the commitments in our credit facilities.
74
We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of June 30, 2009 were as follows: Company/Facility As of June 30, 2009 Primary Purpose Total Usage Available Expiration Millions PSEG: 5-year Credit Facility (A) CP Support/Funding/ $ 1,000 $ 17 $ 983 Dec 2012 Letters of Credit Uncommited Bilateral Agreement N/A $ — $ — N/A Funding Total PSEG $ 1,000 $ 17 $ 983 Power: 5-year Credit Facility (A) 1,600 236 1,364 Dec 2012 Funding/Letters of Credit Bilateral Credit Facility 100 29 71 March 2010 Funding/Letters of Credit Bilateral Credit Facility 150 — 150 Sept 2009 Funding/Letters of Credit Bilateral Credit Facility 50 — 50 Sept 2009 Funding Total Power $ 1,900 $ 265 $ 1,635 PSE&G: 5-year Credit Facility (A) CP Support/Funding/ $ 600 $ 331 $ 269 June 2012 Letters of Credit Uncommitted Bilateral Agreement N/A 2 N/A N/A Funding Total PSE&G $ 600 $ 333 $ 269 Energy Holdings 5-year Credit Facility $ 136 $ — $ 136 June 2010 Funding/Letters of Credit Total $ 136 $ — $ 136 (A) In December 2011, these facilities reduce by $47 million, $75 million, and $28 million for PSEG, Power and PSE&G, respectively. On July 24, 2009, Power entered into a new $350 million syndicated credit facility that expires in July 2011. This new facility is available for funding the obligations of Power and its subsidiaries. Also as of July 24, 2009, Energy Holdings terminated its $136 million syndicated credit facility. As noted above, the PSEG credit facilities can be used to support our subsidiaries liquidity needs, including those of Energy Holdings. In September 2009, a $50 million bilateral credit facility and a $150 million bilateral credit facility at Power are scheduled to expire. We are currently reviewing the liquidity requirements for Power. If it is determined that additional capacity is required to support Power’s needs, we will seek to add this capacity at the appropriate time. Long-Term Debt Financing We have $249 million of debt maturities upcoming in the third and fourth quarters of 2009. We believe that we will be able to refinance or retire these obligations assuming continued access to the capital markets. For a discussion of our long-term debt transactions during 2009, see Note 6. Changes in Capitalization. Common Stock Dividends and Repurchases Dividend payments on common stock for the quarter ended June 30, 2009 were $0.3325 per share and totaled $168 million. Dividend payments on common stock for the quarter ended June 30, 2008 were $0.3225 per share and totaled $164 million. 75
Facility
Liquidity
Date
Dividend payments on common stock for the six months ended June 30, 2009 were $0.6650 per share and totaled $336 million. Dividend payments on common stock for the six months ended June 30, 2008 were $0.6450 per share and totaled $328 million. In July 2008, our Board of Directors authorized the repurchase of up to $750 million of our common stock to be executed over 18 months beginning August 1, 2008. We are not obligated to acquire any specific number of shares and may suspend or terminate share repurchases at any time. We repurchased 2,382,200 shares of our common stock for $92 million under this authorization through September 30, 2008. No repurchases have been made since that date. On July 21, 2009, our Board of Directors approved a common stock dividend of $0.3325 per share for the third quarter of 2009. This reflects an indicated annual dividend rate of $1.33 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. Credit Ratings If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In March 2009, S&P affirmed the ratings and outlooks of PSEG, Power and PSE&G. In June 2009, Fitch affirmed the ratings and outlooks of PSEG, Power and PSE&G.
Moody’s(A)
S&P(B)
Fitch(C)
PSEG:
Outlook
Stable
Stable
Stable
Commercial Paper
P2
A2
F2
Power:
Outlook
Stable
Stable
Stable
Senior Notes
Baa1
BBB
BBB+
PSE&G:
Outlook
Stable
Stable
Stable
Mortgage Bonds
A3
A–
A
Preferred Securities
Baa3
BB+
BBB+
Commercial Paper
P2
A2
F2
| ||||||||||||||||||||
(A) |
| Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. | ||||||||||||||||||
| ||||||||||||||||||||
(C) |
| Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities. | ||||||||||||||||||
We expect that the majority of funding for our capital requirements over the next three years will come from internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and by equity contributions from us to our subsidiaries.
76
PSE&G’s projected construction and investment expenditures through 2011 are expected to increase by $1.3 billion as compared to amounts reported in our Annual Report on Form 10-K for the year ended December 31, 2008. The increase is due primarily to: • $694 million of spending accelerated from later years under the Capital Economic Stimulus Program approved by the BPU in April 2009, • $166 million for the Energy Efficiency Economic Stimulus program approved by the BPU on July 1, 2009, and • $418 million for Solar 4 All and $31 million for Demand Response, both of which were approved by the BPU on July 29, 2009. These expenditures will be financed by a combination of external capital and internally generated funds and earn concurrent return on investment. Other than this increase at PSE&G, our projected construction and investment expenditures through 2011 are consistent with the amounts disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. Power During the six months ended June 30, 2009, Power made $309 million of capital expenditures (excluding $116 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 6. Commitments and Contingent Liabilities. PSE&G During the six months ended June 30, 2009, PSE&G made $379 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $379 million does not include expenditures for cost of removal, net of salvage, of $24 million, which are included in operating cash flows. For information related to recent accounting matters, see Note 2. Recent Accounting Standards. ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices. Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows. Commodity Contracts The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity. 77
Value-at-Risk (VaR) Models We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses. We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR. The VaR models used are variance/covariance models adjusted for the change of positions with a 95% confidence level and a one-day holding period for the MTM trading and non-trading activities, and a 95% confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio. As of each of June 30, 2009 and December 31, 2008, trading VaR was approximately $1 million. For the Three Months Ended June 30, 2009 Trading VaR Non-Trading Millions 95% confidence level, Loss could exceed VaR one day in 20 days: Period End $ 1 31 Average for the Period $ 1 31 High $ 2 37 Low $ — * 23 99.5% confidence level, Loss could exceed VaR one day in 200 days: Period End $ 2 49 Average for the Period $ 2 48 High $ 4 58 Low $ — * 37 * less than $1 million Credit Risk Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s financial condition, results of operations or net cash flows. As of June 30, 2009, 99% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s operations was with investment grade counterparties. 78
MTM VaR
The following table provides information on Power’s credit exposure, net of collateral, as of June 30, 2009. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of the company’s credit risk by credit rating of the counterparties. Schedule of Credit Risk Exposure on Energy Contracts
Net Assets as of June 30, 2009
Rating
Current
Exposure
Securities
held as
Collateral
Net
Exposure
Number of
Counterparties
>10%
Net Exposure of
Counterparties
>10%
Millions
Millions
Investment Grade—External Rating
$
1,479
$
252
$
1,318
2
(A)
$
813
Non-Investment Grade—External Rating
6
5
1
—
—
Investment Grade—No External Rating
17
1
16
—
—
Non-Investment Grade—No External Rating
13
22
8
—
—
Total
$
1,515
$
280
$
1,343
2
$
813
| ||||||||||||||||||||
(A) |
| Includes net exposure of $600 million with PSE&G. The remaining net exposure of $213 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty. | ||||||||||||||||||
The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more cash collateral than the outstanding exposure, in which case there would not be exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of June 30, 2009, Power had 177 active counterparties.
79
ITEM 4. CONTROLS AND PROCEDURES Disclosure Controls and Procedures We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report. Internal Controls Effective April 1, 2009, PSE&G replaced a stand alone legacy customer information system (CIS) with the SAP customer care system module (CCS). CCS is integrated with the existing series of SAP enterprise resource planning modules, including financial reporting, general ledger, property accounting, treasury, supply chain, payroll, human resources, and work management. CCS is used for customer bill production and integrates revenue, accounts receivable and cash management transactions with the general ledger module. The implementation of the CCS module and the related workflow capabilities resulted in material changes to PSE&G’s internal controls over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f) under the Exchange Act). Therefore, PSE&G has modified and continues to modify internal controls relating to the new system to replace and supplement existing internal controls over financial reporting, as appropriate. The system changes were undertaken to integrate the computer environment and were not undertaken in response to any actual or perceived deficiencies in PSE&G’s internal control over financial reporting. We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. Other than the implementation of the CCS module and the related workflow capabilities at PSE&G, there have been no changes in internal control over financial reporting that occurred during the second quarter of 2009 that have materially affected, or are reasonably likely to materially affect, any registrant’s internal control over financial reporting. 80
We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2008 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 6. Commitments and Contingent Liabilities and Item 5. Other Information, Federal Regulation. RPM Model PJM FERC Filing to Prospectively Change Elements of RPM and FERC Order on PJM Filing 2008 Form 10-K, Page 43. PJM submitted a filing at FERC seeking to implement certain prospective changes to the RPM model. Issues in this proceeding included: • the cost of new entry (CONE), • integration of transmission upgrades into RPM modeling, • recognition of locational capacity value, • participation in RPM by demand-side and energy efficiency resources, penalties for deficiencies and unavailability of capacity resources, and • the calculation of avoided cost and long-term contracting to encourage new entry. In March 2009, the FERC issued an order accepting various parts of the filing and rejecting others, including retaining CONE values and reducing RPM auction requirements to encourage participation. While we believe that the order is generally positive, we sought rehearing of this order for further adjustments to PJM’s filing. A stakeholder process is currently ongoing to address a number of significant RPM design issues, including a revised mechanism to automatically set CONE values based on market information. PJM is expected to make a filing incorporating certain RPM revisions by September 2009. The risk factors discussed below should be read in conjunction with, and update and supplement the risk factors discussed in PSEG’s, Power’s and PSE&G’s respective Annual Reports on Form 10-K for the year ended December 31, 2008 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2009. 2008 Form 10-K, Page 32. We are subject to numerous federal and state environmental laws and regulations that may significantly limit or affect our business, adversely impact our business plans or expose us to significant environmental fines and liabilities. • Dry Flue Gas Desulfurization (FGD) Waste Management—Pursuant to our November 2006 agreement with EPA and the NJDEP to meet targeted reductions in emissions of sulfur dioxide (SO2), we are installing dry FGD equipment at our Mercer and Hudson stations, with completion scheduled for December 2010. A by-product of operation of this equipment is dry FGD waste. We are currently evaluating options for beneficial use and for disposal. Dry FGD waste is currently regulated as a solid waste under federal and state law, but is being evaluated by EPA for regulation as a hazardous waste, or may be regulated in a way in which it may become more difficult to be beneficially reused. There could be additional material costs for us to manage FGD waste if the EPA adopts new regulations which impede upon the viability of beneficially reusing FGD waste, including but not limited to the regulation of FGD waste as a hazardous waste. • Coal Ash Management—A by-product of the combustion of coal is coal ash. Three types of coal ash are produced at our Hudson, Mercer and Bridgeport stations: bottom ash, fly ash, and slag. Two types of coal ash are produced at our Keystone and Conemaugh stations: bottom ash and fly ash. We currently have a program in which we beneficially re-use ash in other processes to avoid 81
disposal. Coal ash is currently regulated as a solid waste under federal and state law, but not as a hazardous waste. The EPA is currently evaluating whether coal ash should be regulated more stringently, including but not limited to regulating coal ash as a hazardous waste. Proposed EPA regulations which more stringently regulate coal ash, including reclassifying coal ash as a hazardous waste, could result in additional costs to our Hudson, Mercer, Bridgeport, Keystone, and Conemaugh stations. Any future regulation of coal ash could result in additional costs which could be material. ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS In July 2008, our Board of Directors authorized the repurchase of up to $750 million of our Common Stock to be executed over 18 months beginning August 1, 2008. We are not obligated to acquire any specific number of shares and may suspend or terminate the share repurchases at any time. As of June 30, 2009, 2,382,200 shares were repurchased at a total price of $92 million.
Three Months Ended
June 30, 2009
Total Number of Shares
Purchased (A)
Average Price
Per Share
Total Number of
Shares Purchased
as Part of Publicly
Announced Plan
Approximate Dollar Value
of Shares that May Yet be
Purchased Under the Plan
Millions
April 1–April 30
101,000
$
29.41
N/A
$
658
May 1–May 31
190,000
$
31.13
N/A
$
658
June 1–June 30
60,000
$
33.72
N/A
$
658
| ||||||||||||||||||||
(A) |
| Represents repurchase of shares in the open market to satisfy obligations under various equity compensation award programs. | ||||||||||||||||||
Certain information reported under the 2008 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2008 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed.
FEDERAL REGULATION
Transmission Expansion
2008 Form 10-K, Page 22 and First Quarter 2009 Form 10-Q, page 64.PJM previously approved the construction of a 500 kV transmission line running from Virginia through Maryland and Delaware (the Mid-Atlantic Pathway Project or MAPP). PJM has determined that the portion of the project running from Delaware to Lower Alloways Creek Township, New Jersey, for which PSE&G would have construction and operating responsibility, is not required at this time. As a result, the New Jersey portion of the project was removed from the list of approved RTEP projects. PJM will continue to evaluate the need for this portion of the project. In March 2009, we obtained from FERC approval of a 150 basis point ROE adder for this project (yielding a ROE of 13.18%), 100% recovery of abandonment costs and the ability to transfer the project to an affiliate. Receipt of incentive rates is contingent upon our portion of the MAPP project being approved by PJM as a RTEP project in the future.
U.S. Department of Energy (DOE) Congestion Study—National Interest Electric Transmission Corridors and FERC Back-Stop Siting Authority
2008 Form 10-K, Page 20 and First Quarter 2009 Form 10-Q, page 64. In October 2007, the DOE acted to designate transmission corridors within these critical congestion areas. One of the designated corridors is the Mid-Atlantic Area National Corridor. Thus, entities seeking to build transmission within the Mid-Atlantic Area Corridor, which includes New Jersey, most of Pennsylvania and New York, may be able to use the FERC’s back-stop siting authority in the future under certain circumstances, if necessary, to site transmission, including with respect to the Susquehanna- Roseland line. In February 2009, the United States Court of Appeals for the Fourth Circuit narrowed the scope of the FERC’s back-stop siting authority. FERC
82
sought reconsideration of this Court of Appeals decision, which was subsequently denied. Parties have until August 18, 2009 to seek review of this decision by the Supreme Court. In August 2009, the DOE is expected to issue a new Congestion Study, as required by law, which may designate additional corridors and/or revise the existing corridors. STATE REGULATION Rates Rate Adjustment Clause (RAC) 2008 Form 10-K, Page 22 and First Quarter 2009 Form 10-Q, page 65.In December 2008, we filed a RAC 16 petition with the BPU requesting an increase in electric and gas RAC rates of approximately $16 million annually. On June 25, 2009, a settlement was signed by the parties and filed with the Administrative Law Judge (ALJ) for the requested amounts. The ALJ’s Initial Decision was approved by the BPU at its July 29, 2009 Agenda Meeting. Electric and Gas Base Rate Case On May 29, 2009, we filed a Petition with the BPU for an increase in electric and gas distribution base rates. The amounts requested are $134 million and $97 million for electric and gas respectively, to be effective March 1, 2010. The matter is pending with a decision expected in early 2010. Energy Supply BGSS 2008 Form 10-K, Page 23 and First Quarter 2009 Form 10-Q, page 65. In May 2008, PSE&G requested an increase in annual BGSS revenue of $376 million, excluding Sales and Use Tax, to be effective October 1, 2008. Since that time, due to the significant downward trend in wholesale natural gas prices, we filed three revisions to the BGSS increase, a revised Stipulation (increase of 14% or $267 million), a BGSS self-implementing decrease (5% or approximately $108 million) and a second BGSS self-implementing decrease (7% or approximately $145 million). The increase in the BGSS-Residential Service Gas (RSG) rate became effective on October 3, 2008 and the decreases became effective on January 1, 2009 and March 1, 2009, respectively. On May 15, 2009, the BPU approved the Stipulation of the Parties which made the current BGSS rate final and resolved all issues in the proceeding. In May 2009, PSE&G made its Annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $133 million, excluding Sales and Use Tax, to be effective October 1, 2009. This represents a reduction of approximately 7.0% for a typical residential gas heating customer. This matter is pending. Energy Policy Solar Initiatives 2008 Form 10-K, Page 23 and First Quarter 2009 Form 10-Q, page 65. We are investing approximately $105 million over two years in a pilot program to help finance the installation of 30 MW of solar systems throughout our electric service area by providing loans to customers for the installation of solar photovoltaic (PV) systems on their premises. As of July 3, 2009, we have provided approximately $13 million in loans for approximately 3.5 MW of solar systems. On March 31, 2009, we also filed a new solar loan program, called “Solar Loan II”, with the BPU. This program is modeled similarly to the original solar loan pilot program discussed above. Under Solar Loan II, we would help finance the installation of an additional 40 MW of solar systems in our electric service territory. Any remaining financing and capacity from the original solar loan program would be rolled into the new program. A procedural schedule has been established under which the BPU is required to act on our filing by October 2009. 83
In July 2009, the BPU approved our Solar 4 All Program. Under this program, we will invest approximately $515 million of capital, and $22 million for operations and maintenance to develop 80MW of utility-owned solar PV systems over a four-year horizon. The program consists of solar systems installed on PSE&G-owned sites (25MW), solar systems installed on distribution system poles (40MW) and solar systems installed on third-party sites in our electric service territory (15MW). The program provides for a charge for recovery of a return on the program expenditures. Energy Efficiency Economic Stimulus Program 2008 Form 10-K, Page 24.On July 16, 2009, the BPU issued an Order approving our Energy Efficiency Economic Stimulus Program. Under this program, we anticipate approximately $166 million of capital, and $24 million for operations and maintenance, and technology costs, in energy effeciency expenditures, through PSE&G for electric and gas programs in New Jersey over an 18 month period. Goals of the program are to help New Jersey meet its Energy Master Plan goal of reducing energy consumption by 20% by 2020 and to help improve New Jersey’s economy through the creation of new jobs. The program provides for a charge for recovery of a return on the program expenditures. Capital Economic Stimulus Infrastructure Program 2008 Form 10-K, Page 25 and First Quarter 2009 Form 10-Q, page 65.On January 21, 2009, we filed for approval of a capital economic stimulus infrastructure investment program. Under this initiative, we proposed to undertake $698 million of capital infrastructure investments for electric and gas programs through PSE&G, over a 24 month period. The goal of these accelerated capital investments is to help improve the State’s economy through the creation of new jobs. This filing was made in response to the Governor of New Jersey’s proposal to help revive the economy through job growth and capital spending. The BPU approved a settlement agreement on April 16, 2009 which identified 38 qualifying projects totaling $694 million. These projects are expected to create more than 900 new jobs. On April 28, 2009, we received the BPU’s written order which was effective May 1, 2009. Under the program, new Capital Adjustment Charges (CAC) will provide for immediate recovery of a return on program expenditures plus depreciation of the assets. The CAC will be adjusted each January based on forecasted program expenditures and will be subject to deferred accounting. The rates are subject to annual adjustments based on actual expenditures and actual general and economic market conditions. Susquehanna-Roseland BPU Petition 2008 Form 10-K, Page 25 and First Quarter 2009 Form 10-Q, page 65. In January 2009, we filed a Petition with the BPU seeking authorization from the BPU to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition seeks a finding from the BPU that municipal land use and zoning ordinances do not apply to this line. A procedural schedule has been established, and both the discovery phase and the public hearing phase of the process have been completed. Under the procedural schedule, the BPU expects to issue a decision in December 2009. In June 2009, the New Jersey Highlands Council provided a favorable applicability determination with respect to the portion of the project crossing the Highlands region. Approval by the New Jersey Department of Environmental Protection of the Highlands council determination is now pending. We are also in the process of seeking to obtain all other necessary environmental permits for the project, including from the National Park Service, to support the start of construction in summer 2010, which can not be assured. 84
A listing of exhibits being filed with this document is as follows:
a.
PSEG:
Exhibit 12:
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:
Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act)
Exhibit 31.1:
Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act
Exhibit 32:
Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32.1:
Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 101.INS:
XBRL Instance Document*
Exhibit 101.SCH:
XBRL Taxonomy Extension Schema*
Exhibit 101.CAL:
XBRL Taxonomy Extension Calculation Linkbase*
Exhibit 101.LAB:
XBRL Taxonomy Extension Labels Linkbase*
Exhibit 101.PRE:
XBRL Taxonomy Extension Presentation Linkbase*
Exhibit 101.DEF:
XBRL Taxonomy Extension Definition Document*
* XBRL information is furnished, not filed.
|
|
|
|
|
b. | Power: |
| ||
| Exhibit 12.1: | Computation of Ratios of Earnings to Fixed Charges | ||
| Exhibit 31.2: | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act | ||
| Exhibit 31.3: | Certification Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act | ||
| Exhibit 32.2: | Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | ||
| Exhibit 32.3: | Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | ||
c. | PSE&G: |
| ||
| Exhibit 12.2: | Computation of Ratios of Earnings to Fixed Charges | ||
| Exhibit 12.3: | Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements | ||
| Exhibit 31.4: | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act | ||
| Exhibit 31.5: | Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act | ||
| Exhibit 32.4: | Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code | ||
| Exhibit 32.5: | Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
85
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: July 31, 2009 86
(Registrant)
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. PSEG POWER LLC By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: July 31, 2009 87
(Registrant)
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof. PUBLIC SERVICE ELECTRIC AND GAS COMPANY By: /s/ DEREK M. DIRISIO Derek M. DiRisio Date: July 31, 2009 88
(Registrant)
Vice President and Controller
(Principal Accounting Officer)