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, 2008
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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Commission | Registrants, State of Incorporation, | I.R.S. Employer | ||
001-09120 | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED | 22-2625848 | ||
000-49614 | PSEG POWER LLC | 22-3663480 | ||
001-00973 | PUBLIC SERVICE ELECTRIC AND GAS COMPANY | 22-1212800 |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes S No £
Indicate by check mark whether 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.
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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 and Gas Company | 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 £ No S
As of July 15, 2008, Public Service Enterprise Group Incorporated had outstanding 508,479,889 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, 2008, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
TABLE OF CONTENTS Page ii PART I. FINANCIAL INFORMATION Item 1. 1 5 8 12 13 16 18 19 29 32 33 34 36 37 39 40 43 45 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 47 47 50 53 61 65 65 Item 3. 66 Item 4. 72 Item 1. 73 Item 1A. 73 Item 5. 74 Item 6. 79 80 i
Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 5. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to: • Adverse changes in energy industry policies and regulation, including market rules, that may adversely affect our operating results. • Any inability of our energy transmission and distribution businesses to obtain adequate and timely rate relief and/or regulatory approvals from federal and/or state regulators. • Changes in federal and/or state environmental regulations that could increase our costs or limit operations of our generating units. • Changes in nuclear regulation and/or developments in the nuclear power industry generally that could limit operations of our nuclear generating units. • Actions or activities at one of our nuclear units that might adversely affect our ability to continue to operate that unit or other units at the same site. • Any inability to balance our energy obligations, available supply and trading risks. • Any deterioration in our credit quality. • Any inability to realize anticipated tax benefits or retain tax credits. • Increases in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units. • Delays or cost escalations in our construction and development activities. • Adverse capital market performance of our decommissioning and defined benefit plan trust funds. • Changes in technology and/or increased customer conservation. All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. Except as may be required by the federal securities laws, we expressly disclaim any obligation or undertaking to release publicly any updates or revisions to these forward-looking statements to reflect events or circumstances that occur or arise or are anticipated to occur or arise after the date hereof. The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. ii
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED For The Quarters For The Six Months 2008 2007 2008 2007 (Millions) OPERATING REVENUES $ 2,561 $ 2,707 $ 6,364 $ 6,215 OPERATING EXPENSES Energy Costs 1,540 1,320 3,664 3,297 Operation and Maintenance 623 578 1,254 1,173 Depreciation and Amortization 193 191 387 383 Taxes Other Than Income Taxes 28 30 71 73 Total Operating Expenses 2,384 2,119 5,376 4,926 Income from Equity Method Investments 8 26 20 53 OPERATING INCOME 185 614 1,008 1,342 Other Income 98 58 191 130 Other Deductions (87 ) (37 ) (181 ) (73 ) Interest Expense (147 ) (182 ) (300 ) (364 ) Preferred Stock Dividends (1 ) (1 ) (2 ) (2 ) INCOME FROM CONTINUING OPERATIONS 48 452 716 1,033 Income Tax Expense (214 ) (171 ) (448 ) (431 ) (LOSS) INCOME FROM CONTINUING OPERATIONS (166 ) 281 268 602 Income (Loss) from Discontinued Operations net of tax (expense) benefit of $(5), $(21), $(11) and $(19) for the quarters and six months ended 2008 and 2007, respectively 16 (6 ) 30 2 NET (LOSS) INCOME $ (150 ) $ 275 $ 298 $ 604 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC 508,491 507,261 508,491 506,526 DILUTED 509,487 508,067 509,483 507,393 EARNINGS PER SHARE: BASIC (LOSS) INCOME FROM CONTINUING OPERATIONS $ (0.32 ) $ 0.55 $ 0.53 $ 1.19 NET (LOSS) INCOME $ (0.29 ) $ 0.54 $ 0.59 $ 1.19 DILUTED (LOSS) INCOME FROM CONTINUING OPERATIONS $ (0.32 ) $ 0.55 $ 0.53 $ 1.19 NET (LOSS) INCOME $ (0.29 ) $ 0.54 $ 0.59 $ 1.19 DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.3225 $ 0.2925 $ 0.6450 $ 0.5850 See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
June 30,
Ended
June 30,
(Unaudited)
BEFORE INCOME TAXES
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED June 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 86 $ 381 Accounts Receivable, net of allowances of $48 and $46 in 2008 and 2007, respectively 1,633 1,552 Unbilled Revenues 317 353 Fuel 839 793 Materials and Supplies 303 296 Prepayments 440 91 Restricted Funds 110 114 Derivative Contracts 389 65 Assets of Discontinued Operations 1,115 1,162 Other 64 29 Total Current Assets 5,296 4,836 PROPERTY, PLANT AND EQUIPMENT 19,982 19,310 Less: Accumulated Depreciation and Amortization (6,209 ) (6,035 ) Net Property, Plant and Equipment 13,773 13,275 NONCURRENT ASSETS Regulatory Assets 4,870 5,165 Long-Term Investments 2,741 3,246 Nuclear Decommissioning Trust (NDT) Funds 1,178 1,276 Other Special Funds 144 164 Goodwill and Other Intangibles 62 64 Derivative Contracts 61 52 Other 209 221 Total Noncurrent Assets 9,265 10,188 TOTAL ASSETS $ 28,334 $ 28,299 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED June 30, December 31, (Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 835 $ 1,123 Commercial Paper and Loans 919 65 Accounts Payable 1,342 1,093 Derivative Contracts 662 324 Accrued Interest 101 113 Accrued Taxes 13 204 Deferred Income Taxes 95 106 Clean Energy Program 75 135 Obligation to Return Cash Collateral 257 79 Liabilities of Discontinued Operations 484 520 Other 438 458 Total Current Liabilities 5,221 4,220 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 3,275 4,454 Regulatory Liabilities 545 419 Asset Retirement Obligations 560 542 Other Postretirement Benefit (OPEB) Costs 1,014 1,003 Accrued Pension Costs 216 203 Clean Energy Program — 14 Environmental Costs 658 649 Derivative Contracts 530 198 Long-Term Accrued Taxes 1,228 423 Other 152 133 Total Noncurrent Liabilities 8,178 8,038 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 6,516 6,783 Securitization Debt 1,443 1,530 Project Level, Non-Recourse Debt 322 349 Total Long-Term Debt 8,281 8,662 SUBSIDIARY’S PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares 80 80 COMMON STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued, 2008 and 2007—533,556,660 shares 4,748 4,732 Treasury Stock, at cost, 2008—25,075,762 shares; 2007—25,033,656 shares (487 ) (478 ) Retained Earnings 3,209 3,261 Accumulated Other Comprehensive Loss (896 ) (216 ) Total Common Stockholders’ Equity 6,574 7,299 Total Capitalization 14,935 16,041 TOTAL LIABILITIES AND CAPITALIZATION $ 28,334 $ 28,299 See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED For The Six Months 2008 2007 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 298 $ 604 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 387 392 Amortization of Nuclear Fuel 48 48 Provision for Deferred Income Taxes (Other than Leases) and ITC 90 124 Non-Cash Employee Benefit Plan Costs 84 93 Lease Transaction Reserves, Net of Taxes 490 — Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (23 ) 5 Undistributed Earnings from Affiliates (37 ) 14 Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (68 ) 39 Under Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs (66 ) (74 ) Under Recovery of Societal Benefits Charge (SBC) (12 ) (17 ) Cost of Removal (20 ) (18 ) Net Realized Gains (Losses) and Income (Expense) from NDT Funds 5 (30 ) Net Change in Certain Current Assets and Liabilities (584 ) (282 ) Employee Benefit Plan Funding and Related Payments (30 ) (39 ) Other 62 (75 ) Net Cash Provided By Operating Activities 624 784 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (739 ) (659 ) Proceeds from Sale of Discontinued Operations — 325 Proceeds from Sale of Property, Plant and Equipment 2 40 Proceeds from the Sale of Capital Leases and Investments 41 7 Proceeds from NDT Funds Sales 1,257 883 Investment in NDT Funds (1,271 ) (904 ) Restricted Funds — 22 NDT Funds Interest and Dividends 24 25 Other (16 ) — Net Cash Used In Investing Activities (702 ) (261 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans 854 (36 ) Issuance of Long-Term Debt 700 350 Issuance of Common Stock — 68 Redemptions of Long-Term Debt (1,263 ) (488 ) Repayment of Non-Recourse Debt (22 ) (24 ) Redemption of Securitization Debt (82 ) (78 ) Premium Paid on Early Extinguishment of Debt (80 ) — Cash Dividends Paid on Common Stock (328 ) (296 ) Other 3 14 Net Cash Used In Financing Activities (218 ) (490 ) Effect of Exchange Rate Change 1 — Net (Decrease) Increase in Cash and Cash Equivalents (295 ) 33 Cash and Cash Equivalents at Beginning of Period 381 106 Cash and Cash Equivalents at End of Period $ 86 $ 139 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 454 $ 220 Interest Paid, Net of Amounts Capitalized $ 284 $ 361 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
June 30,
(Unaudited)
PSEG POWER LLC For The Quarters Ended For The Six Months Ended 2008 2007 2008 2007 (Millions) OPERATING REVENUES $ 1,623 $ 1,305 $ 3,998 $ 3,454 OPERATING EXPENSES Energy Costs 867 694 2,456 2,182 Operation and Maintenance 275 241 514 479 Depreciation and Amortization 41 34 79 68 Total Operating Expenses 1,183 969 3,049 2,729 OPERATING INCOME 440 336 949 725 Other Income 93 55 179 106 Other Deductions (87 ) (34 ) (178 ) (63 ) Interest Expense (41 ) (39 ) (83 ) (76 ) INCOME FROM CONTINUING OPERATIONS 405 318 867 692 Income Tax Expense (165 ) (131 ) (352 ) (286 ) INCOME FROM CONTINUING OPERATIONS 240 187 515 406 Loss from Discontinued Operations, net of tax benefit of $1 and $6 for the quarter and six months ended 2007 — (3 ) — (9 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 240 $ 184 $ 515 $ 397 See disclosures regarding PSEG Power LLC included in the 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
June 30,
June 30,
(Unaudited)
BEFORE INCOME TAXES
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC June 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 17 $ 11 Accounts Receivable 643 533 Accounts Receivable—Affiliated Companies, net — 441 Fuel 836 791 Materials and Supplies 218 220 Derivative Contracts 368 46 Restricted Funds 37 50 Prepayments 27 26 Other 62 31 Total Current Assets 2,208 2,149 PROPERTY, PLANT AND EQUIPMENT 6,907 6,565 Less: Accumulated Depreciation and Amortization (1,880 ) (1,814 ) Net Property, Plant and Equipment 5,027 4,751 NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC) 224 — Nuclear Decommissioning Trust (NDT) Funds 1,178 1,276 Goodwill 16 16 Other Intangibles 40 35 Other Special Funds 28 45 Derivative Contracts 30 7 Other 60 57 Total Noncurrent Assets 1,576 1,436 TOTAL ASSETS $ 8,811 $ 8,336 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 250 $ — Accounts Payable 826 648 Accounts Payable—Affiliated Companies, net 57 — Short-Term Loan from Affiliate 400 238 Derivative Contracts 586 300 Accrued Interest 35 34 Other 153 118 Total Current Liabilities 2,307 1,338 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) — 176 Asset Retirement Obligations 321 309 Other Postretirement Benefit (OPEB) Costs 135 129 Derivative Contracts 465 158 Accrued Pension Costs 72 70 Environmental Costs 55 55 Long-Term Accrued Taxes 14 26 Other 23 12 Total Noncurrent Liabilities 1,085 935 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt 2,653 2,902 MEMBER’S EQUITY Contributed Capital 2,000 2,000 Basis Adjustment (986 ) (986 ) Retained Earnings 2,703 2,438 Accumulated Other Comprehensive Loss (951 ) (291 ) Total Member’s Equity 2,766 3,161 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 8,811 $ 8,336 See disclosures regarding PSEG Power LLC included in the 6
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC For The Six Months 2008 2007 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 515 $ 397 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 79 68 Amortization of Nuclear Fuel 48 48 Interest Accretion on Asset Retirement Obligations 12 11 Provision for Deferred Income Taxes and ITC 70 174 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives (68 ) 36 Non-Cash Employee Benefit Plan Costs 12 14 Net Realized Losses (Gains) and Income (Expense) from NDT Funds 5 (30 ) Net Change in Working Capital: Fuel, Materials and Supplies (43 ) 169 Margin Deposit Asset (389 ) (131 ) Margin Deposit Liability 14 (4 ) Accounts Receivable (54 ) (45 ) Accounts Payable 139 (36 ) Accounts Receivable/Payable-Affiliated Companies, net 138 147 Other Current Assets and Liabilities (31 ) (12 ) Employee Benefit Plan Funding and Related Payments (1 ) (4 ) Other 20 (8 ) Net Cash Provided By Operating Activities 466 794 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (384 ) (323 ) Short-Term Loan—Affiliated Company, net — (214 ) Proceeds from Sale of Discontinued Operations — 325 Sales of Property, Plant and Equipment 2 40 Proceeds from NDT Funds Sales 1,257 883 NDT Funds Interest and Dividends 24 25 Investment in NDT Funds (1,271 ) (904 ) Restricted Funds 13 — Other (13 ) (4 ) Net Cash Used In Investing Activities (372 ) (172 ) CASH FLOWS FROM FINANCING ACTIVITIES Cash Dividend Paid (250 ) (575 ) Short-Term Loan—Affiliated Company, net 162 (54 ) Net Cash Used In Financing Activities (88 ) (629 ) Net Increase (Decrease) in Cash and Cash Equivalents 6 (7 ) Cash and Cash Equivalents at Beginning of Period 11 13 Cash and Cash Equivalents at End of Period $ 17 $ 6 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 261 $ 74 Interest Paid, Net of Amounts Capitalized $ 80 $ 85 See disclosures regarding PSEG Power LLC included in the 7
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
June 30,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For The Quarters For The Six Months 2008 2007 2008 2007 (Millions) OPERATING REVENUES $ 1,858 $ 1,748 $ 4,476 $ 4,234 OPERATING EXPENSES Energy Costs 1,213 1,077 3,006 2,742 Operation and Maintenance 320 314 680 639 Depreciation and Amortization 139 143 282 288 Taxes Other Than Income Taxes 27 30 70 73 Total Operating Expenses 1,699 1,564 4,038 3,742 OPERATING INCOME 159 184 438 492 Other Income 2 5 7 10 Other Deductions — (1 ) (1 ) (2 ) Interest Expense (81 ) (84 ) (162 ) (165 ) INCOME BEFORE INCOME TAXES 80 104 282 335 Income Tax Expense (28 ) (41 ) (93 ) (140 ) NET INCOME 52 63 189 195 Preferred Stock Dividends (1 ) (1 ) (2 ) (2 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 51 $ 62 $ 187 $ 193 See disclosures regarding Public Service Electric and Gas Company included in the 8
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
June 30,
Ended
June 30,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY June 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 33 $ 32 Accounts Receivable, net of allowances of $48 in 2008 and $45 in 2007 902 995 Accounts Receivable—Affiliated Companies, net 33 — Unbilled Revenues 317 353 Materials and Supplies 63 53 Prepayments 361 57 Restricted Funds 3 7 Derivative Contracts 1 1 Deferred Income Taxes 42 44 Total Current Assets 1,755 1,542 PROPERTY, PLANT AND EQUIPMENT 11,844 11,531 Less: Accumulated Depreciation and Amortization (4,005 ) (3,920 ) Net Property, Plant and Equipment 7,839 7,611 NONCURRENT ASSETS Regulatory Assets 4,870 5,165 Long-Term Investments 156 153 Other Special Funds 48 57 Other 106 109 Total Noncurrent Assets 5,180 5,484 TOTAL ASSETS $ 14,774 $ 14,637 See disclosures regarding Public Service Electric and Gas Company included in the 9
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY June 30, December 31, (Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 493 $ 429 Commercial Paper and Loans 200 65 Accounts Payable 399 325 Accounts Payable—Affiliated Companies, net — 559 Accrued Interest 58 56 Accrued Taxes 3 29 Clean Energy Program 75 135 Derivative Contracts 31 20 Obligation to Return Cash Collateral 257 79 Other 225 239 Total Current Liabilities 1,741 1,936 NONCURRENT LIABILITIES Deferred Income Taxes and ITC 2,508 2,440 Other Postretirement Benefit (OPEB) Costs 824 821 Accrued Pension Costs 65 63 Regulatory Liabilities 545 419 Clean Energy Program — 14 Environmental Costs 603 594 Asset Retirement Obligations 236 231 Derivative Contracts 64 36 Long-Term Accrued Taxes 72 75 Other 31 9 Total Noncurrent Liabilities 4,948 4,702 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 3,088 3,102 Securitization Debt 1,443 1,530 Total Long-Term Debt 4,531 4,632 PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2008 and 2007—795,234 shares 80 80 COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized; issued and outstanding, 2008 and 2007—132,450,344 shares 892 892 Contributed Capital 170 170 Basis Adjustment 986 986 Retained Earnings 1,424 1,237 Accumulated Other Comprehensive Income 2 2 Total Common Stockholder’s Equity 3,474 3,287 Total Capitalization 8,085 7,999 TOTAL LIABILITIES AND CAPITALIZATION $ 14,774 $ 14,637 See disclosures regarding Public Service Electric and Gas Company included in the 10
CONDENSED CONSOLIDATED BALANCE SHEETS
2008
2007
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For The Six Months Ended 2008 2007 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 189 $ 195 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 282 288 Provision for Deferred Income Taxes and ITC 23 (32 ) Non-Cash Employee Benefit Plan Costs 65 70 Non-Cash Interest Expense 6 4 Cost of Removal (20 ) (18 ) Under Recovery of Electric Energy Costs (BGS and NTC) (12 ) (23 ) Under Recovery of Gas Costs (54 ) (51 ) Under Recovery of SBC (12 ) (17 ) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues 128 12 Materials and Supplies (10 ) (12 ) Prepayments (304 ) (328 ) Accrued Taxes (26 ) — Accounts Payable 74 99 Accounts Receivable/Payable-Affiliated Companies, net (191 ) (172 ) Obligation to Return Cash Collateral 178 8 Other Current Assets and Liabilities (6 ) (35 ) Employee Benefit Plan Funding and Related Payments (28 ) (30 ) Other — (75 ) Net Cash Provided By (Used In) Operating Activities 282 (117 ) CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (345 ) (296 ) Net Cash Used In Investing Activities (345 ) (296 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 135 264 Issuance of Long-Term Debt 700 350 Redemption of Long-Term Debt (651 ) (113 ) Redemption of Securitization Debt (82 ) (78 ) Deferred Issuance Costs (4 ) (3 ) Premium Paid on Early Retirement of Debt (32 ) — Preferred Stock Dividends (2 ) (2 ) Net Cash Provided By Financing Activities 64 418 Net Increase In Cash and Cash Equivalents 1 5 Cash and Cash Equivalents at Beginning of Period 32 28 Cash and Cash Equivalents at End of Period $ 33 $ 33 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 40 $ 203 Interest Paid, Net of Amounts Capitalized $ 155 $ 157 See disclosures regarding Public Service Electric and Gas Company included in the 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
June 30,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations as to any other company. Note 1. Organization and Basis of Presentation Organization PSEG PSEG has four principal direct wholly owned subsidiaries: Power, PSE&G, PSEG Energy Holdings L.L.C. (Energy Holdings) and PSEG Services Corporation (Services). Power Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to regulation by the Federal Energy Regulatory Commission (FERC) and Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC). PSE&G PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition properties from PSE&G and issued transition bonds secured by such properties. The transition properties consist principally of the statutory rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU. Energy Holdings Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which primarily owns and operates domestic projects engaged in generation of energy and PSEG Resources L.L.C. (Resources), which has invested primarily in energy-related leveraged leases. Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. Global has reduced its international risk by monetizing the majority of its international investments. In July 2008, Global closed on the sale of its largest remaining international investment in the SAESA Group. For additional information, see Note 3. Discontinued Operations and Dispositions. Global’s remaining international investments in Italy, Venezuela and India had a total net book value of $122 million as of June 30, 2008. Services Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, financial risk management, law, tax, planning, information technology, 12
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS investor relations and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to intercompany service agreements. Basis of Presentation PSEG, Power and PSE&G The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in, PSEG’s, Power’s and PSE&G’s respective Annual Reports on Form 10-K for the year ended December 31, 2007 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2008. The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2007. Reclassifications PSEG and Power Certain reclassifications have been made to the prior period financial statements to conform to the 2008 presentation. In accordance with a new policy established in the first quarter of 2008, Power has adjusted its Condensed Consolidated Balance Sheet as of December 31, 2007 to net the fair value of cash collateral receivables and payables with the corresponding net derivative balances. See Note 2. Recent Accounting Standards for additional information. In addition, operating results for the SAESA Group were reclassified to Income from Discontinued Operations on the Condensed Consolidated Statements of Operations of PSEG for the quarter and six months ended June 30, 2007. See Note 3. Discontinued Operations and Dispositions. Note 2. Recent Accounting Standards The following accounting standards were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG, Power or PSE&G. Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007), “Business Combinations” (SFAS 141(R)) PSEG, Power and PSE&G In December 2007, the FASB issued SFAS 141(R) which replaces SFAS No. 141 “Business Combinations.” SFAS 141(R) will change financial accounting and reporting of business combination transactions. It is based on the principle that all assets acquired and liabilities assumed in a business combination should be measured at their acquisition date fair values, with limited exceptions. This standard applies to all transactions and events in which an entity obtains control of one or more businesses of an acquiree. The standard also expands the definition of a business. A transaction formerly recorded as an asset acquisition may qualify as a business combination under SFAS 141(R). It also requires that acquisition-related costs and certain restructuring costs be recognized separately from the business combination. SFAS 141(R) is effective for all business combinations with an acquisition date on or after the beginning of fiscal years commencing on or after December 15, 2008. Earlier adoption is prohibited. SFAS 141(R) is required to be adopted concurrently with SFAS 160. PSEG, Power and PSE&G will adopt SFAS 141(R) effective January 1, 2009. Accordingly, any business combinations for which the acquisition date is on or after 13
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS January 1, 2009 will be accounted for under this new guidance. PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements. SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin (ARB) No. 51” (SFAS 160) PSEG, Power and PSE&G In December 2007, the FASB issued SFAS 160 which significantly changes the financial reporting relationship between a parent and non-controlling interests (i.e. minority interests). SFAS 160 requires all entities to report minority interests in subsidiaries as a separate component of equity in the consolidated financial statements. Accordingly, the amount of net income attributable to the noncontrolling interest is required to be included in consolidated net income on the face of the income statement. Further, SFAS 160 requires that transactions between a parent and noncontrolling interests should be treated as equity. However, if a subsidiary is deconsolidated, a parent is required to recognize a gain or loss. SFAS 160 is effective for fiscal years beginning on or after December 15, 2008. Earlier adoption is prohibited. SFAS 160 will be applied prospectively, except for presentation and disclosure requirements which are required to be applied retrospectively. PSEG, Power and PSE&G will adopt SFAS 160 effective January 1, 2009. PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements upon adoption. SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133” (SFAS 161) PSEG, Power and PSE&G In March 2008, the FASB issued SFAS 161 which expands derivative disclosures by requiring an entity to disclose: i) an understanding of how and why an entity uses derivatives, ii) an understanding of how derivatives and related hedged items are accounted for and iii) transparency into the overall impact of derivatives on an entity’s financial statements. SFAS 161 is effective for fiscal years beginning after November 15, 2008. Earlier adoption is encouraged. PSEG, Power and PSE&G are analyzing the requirements of SFAS 161 and will adopt the standard on January 1, 2009. PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements. SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162) In May 2008, the FASB issued SFAS 162 for the purpose of improving financial reporting by providing a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. GAAP hierarchy was previously defined in the American Institute of Certified Public Accountants Statement on Auditing Standards No. 69,“The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” SFAS 162 is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to Auditing Standards: Section 411. PSEG, Power and PSE&G do not anticipate a material impact to their respective financial statements upon adoption of SFAS 162. FASB Staff Position (FSP) FAS 142-3, “Determination of the Useful Life of Intangible Assets” (FSP FAS 142-3) In April 2008, the FASB issued FSP FAS 142-3 to amend the factors an entity should consider in determining the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The FSP would allow an entity to consider its own experience regarding renewals and extensions, as long as entity’s own experience is consistent with the intended use of similar assets. If an entity 14
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS lacks such experience, it would look to market participant information that is consistent with the highest and best use of the asset and make adjustments for other entity-specific factors. FSP FAS 142-3 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. Earlier adoption is not permitted. PSEG, Power and PSE&G will adopt the standard on January 1, 2009 and do not anticipate a material impact to their respective financial statements upon adoption. FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining whether Instruments Granted in Share-Based Payment Transactions are Participating Securities” (FSP EITF 03-6-1) In June 2008, the FASB issued FSP EITF 03-6-1 to address whether instruments granted in share-based payment transactions are participating securities prior to their vesting and therefore need to be included in the earnings per share calculation under the two-class method described in SFAS No. 128, “Earnings per Share.” This FSP requires companies to treat unvested share-based payment awards that have non-forfeitable rights to dividends or dividend equivalents as participating securities and thus, include them in calculation of basic earnings per share. FSP EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008. Earlier adoption is not permitted. PSEG will adopt the standard on January 1, 2009 and does not anticipate a material impact on its financial statements or its computation of basic earnings per share upon adoption. The following new accounting standards were adopted by PSEG, Power and PSE&G during 2008. SFAS No. 157, “Fair Value Measurements” (SFAS 157) PSEG, Power and PSE&G In September 2006, the FASB issued SFAS 157 which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets. PSEG, Power and PSE&G adopted SFAS 157 (except for non-financial assets and liabilities as described in FSP FAS 157-2) effective January 1, 2008. In accordance with the provisions of SFAS 157, PSEG recorded a cumulative effect adjustment of $22 million (after-tax) to January 1, 2008 Retained Earnings associated with the implementation of SFAS 157. In February 2008, the FASB issued FSP FAS 157-2 to partially defer the effective date of SFAS 157 for certain nonfinancial assets and nonfinancial liabilities. In February 2008, the FASB also issued FSP FAS 157-1 to exclude leasing transactions from SFAS 157’s scope. For additional information, see Note 13. Fair Value Measurements. SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) PSEG, Power and PSE&G In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that would not otherwise be required to be measured at fair value. An entity would report unrealized gains and losses in earnings at each subsequent reporting date on items for which the fair value option has been elected. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The decision whether to elect the fair value option is applied instrument by instrument, with a few exceptions. The 15
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS decision is irrevocable and it is required to be applied only to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities; and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS 159 was effective for financial statements issued for fiscal years beginning after November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. PSEG, Power and PSE&G adopted SFAS 159 effective January 1, 2008; however, to date, PSEG, Power and PSE&G have not elected to measure any of their respective assets or liabilities at fair value under this standard. FSP FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1) PSEG and Power In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, “Offsetting of Amounts Related to Certain Contracts” to permit an entity to offset cash collateral paid or received against fair value amounts recognized for derivative instruments held with the same counterparty under the same master netting arrangement. PSEG and Power adopted the FSP effective January 1, 2008. In accordance with the provisions of FSP FIN 39-1, PSEG and Power established a policy of netting fair value cash collateral receivables and payables with the corresponding net derivative balances. The adoption of FSP FIN 39-1 resulted in PSEG and Power offsetting cash collateral receivables of $418 million against net derivative positions as of June 30, 2008. Amounts in prior period statements have been retroactively adjusted, as required under the FSP. Note 3. Discontinued Operations and Dispositions Discontinued Operations Power Lawrenceburg Energy Center (Lawrenceburg) In May 2007, Power completed the sale of Lawrenceburg, a 1,096-megawatt (MW), gas-fired combined cycle electric generating plant located in Lawrenceburg, Indiana, to AEP Generating Company, a subsidiary of American Electric Power Company, Inc. (AEP) for a sale price of $325 million. Lawrenceburg’s operating results for the quarter and six months ended June 30, 2007, which are included in Discontinued Operations, are summarized below: Quarter Six Months 2007 2007 (Millions) Operating Revenues $ — $ — Loss Before Income Taxes $ (4 ) $ (15 ) Net Loss. $ (3 ) $ (9 ) Energy Holdings SAESA Group In June 2008, Global announced an agreement to sell its investment in the SAESA Group, which consists of four distribution companies, one transmission company and a generation facility located in Chile. The sale was completed in July 2008 for a total purchase price of approximately $1.3 billion, including the assumption of approximately $413 million of the consolidated debt of the group. The sale resulted in an after-tax gain of approximately $180 million, which will be reported as Gain on Disposal of Discontinued 16
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Ended
June 30,
Ended
June 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Operations in the third quarter of 2008. Net cash proceeds, after Chilean and US taxes of approximately $275 million, were approximately $600 million. A tax charge of $82 million was recognized in the fourth quarter of 2007 relating to the discontinuation of applying Accounting Principle Board No. 23, “Accounting for Income Taxes—Special Areas.” SAESA Group’s operating results for the quarters and six months ended June 30, 2008 and 2007, which are included in Discontinued Operations, are summarized below: Quarters Ended Six Months Ended 2008 2007 2008 2007 (Millions) Operating Revenues. $ 156 $ 104 $ 342 $ 198 Income Before Income Taxes $ 21 $ 13 $ 41 $ 29 Net Income $ 16 $ 11 $ 30 $ 25 The carrying amounts of SAESA Group’s assets as of June 30, 2008 and December 31, 2007 are summarized in the following table: As of As of (Millions) Current Assets $ 155 $ 191 Noncurrent Assets 960 971 Total Assets of Discontinued Operations $ 1,115 $ 1,162 Current Liabilities $ 122 $ 130 Noncurrent Liabilities 362 390 Total Liabilities of Discontinued Operations $ 484 $ 520 Electroandes S.A. (Electroandes) On October 17, 2007, Global sold its investment in Electroandes, a hydro-electric generation and transmission company in Peru that owns and operates four hydro-generation plants with total capacity of 180 MW and 437 miles of electric transmission lines, for a total purchase price of $390 million, including the assumption of approximately $108 million of debt. Electroandes’ operating results for the quarter and six months ended June 30, 2007, which are included in Discontinued Operations, are summarized below: Quarter Six Months (Millions) Operating Revenues $ 13 $ 24 Income Before Income Taxes $ 6 $ 7 Net Loss. $ (14 ) $ (14 ) Dispositions Power In December 2006, Power recorded a pre-tax impairment loss of $44 million to write down four turbines to their estimated realizable value and reclassified them to Assets Held for Sale on Power’s Condensed Consolidated Balance Sheet. In April 2007, Power sold the four turbines to a third party and received proceeds of approximately $40 million, which approximated the recorded book value. 17
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June 30,
June 30
June 30,
2008
December 31,
2007
Ended
June 30,
2007
Ended
June 30,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Holdings Chilquinta Energia S.A. (Chilquinta) and Luz del Sur S.A.A. (LDS) In December 2007, Global closed on the sales of its ownership interest in the Chilean electric distributor, Chilquinta and its affiliates, and in the Peruvian electric distributor, LDS and its affiliates, for $685 million. Net cash proceeds after taxes were approximately $480 million, which resulted in an after-tax loss of $23 million. Thermal Energy Development Partnership, L.P. (Tracy Biomass) In January 2007, Global sold its interest in Tracy Biomass for approximately $7 million, resulting in a 2007 pre-tax gain of approximately $7 million ($6 million after-tax). Note 4. Earnings Per Share (EPS) PSEG Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under PSEG’s stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, restricted stock awards, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS: Quarters Ended March 31, Six Months Ended June 30, 2008 2007 2008 2007 Basic Diluted Basic Diluted Basic Diluted Basic Diluted EPS Numerator: Continuing Operations $ (166 ) $ (166 ) $ 281 $ 281 $ 268 $ 268 $ 602 $ 602 Discontinued Operations 16 16 (6 ) (6 ) 30 30 2 2 Net (Loss) Income $ (150 ) $ (150 ) $ 275 $ 275 $ 298 $ 298 $ 604 $ 604 EPS Denominator: Weighted Average Common Shares Outstanding 508,491 508,491 507,261 507,261 508,491 508,491 506,526 506,526 Effect of Stock Options — 457 — 806 — 477 — 793 Effect of Stock Performance Units — 517 — — — 501 — 74 Effect of Restricted Stock — 22 — — — 14 — — Total Shares 508,491 509,487 507,261 508,067 508,491 509,483 506,526 507,393 EPS: Continuing Operations $ (0.32 ) $ (0.32 ) $ 0.55 $ 0.55 $ 0.53 $ 0.53 $ 1.19 $ 1.19 Discontinued Operations 0.03 0.03 (0.01 ) (0.01 ) 0.06 0.06 — — Net (Loss) Income $ (0.29 ) $ (0.29 ) $ 0.54 $ 0.54 $ 0.59 $ 0.59 $ 1.19 $ 1.19 Dividend payments on common stock for the quarters ended June 30, 2008 and 2007 were $0.3225 and $0.2925 per share, respectively, and totaled $164 million and $148 million, respectively. Dividend payments on common stock for the six months ended June 30, 2008 and 2007 were $0.645 and $0.585 per share, respectively, and totaled approximately $328 million and $296 million, respectively. 18
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(Thousands)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 5. Commitments and Contingent Liabilities Guaranteed Obligations Power Power contracts for electricity, natural gas, oil, coal, pipeline capacity, transportation and emission allowances and engages in risk management activities through ER&T. These activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are executed with numerous counterparties and brokers. Counterparties and brokers may require guarantees, cash or cash-related instruments to be deposited on these transactions as described below. Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York), in commodity-related transactions to support current exposure, interest and other costs on sums due and payable in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit. Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the guarantees outstanding as of June 30, 2008 and December 31, 2007 was $1.7 billion and $1.5 billion, respectively. In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee and all of ER&T’s and Power New York’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T and Power New York being simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees if ER&T and/or Power New York were to default. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $670 million and $521 million as of June 30, 2008 and December 31, 2007, respectively. Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts, 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. Generally, such futures contracts require a deposit of cash margin with brokers, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of June 30, 2008 and December 31, 2007, Power had the following margin posted and received to satisfy collateral obligations: As of As of (Millions) Letters of Credit Margin Posted $ 1,515 $ 188 Letters of Credit Margin Received $ 8 $ 42 Net Cash Margin Deposited $ 541 $ 166 Power has established a policy of netting fair value cash collateral receivables and payables with the corresponding net derivative balances. As a result, Power has offset net cash margin deposits of $418 million and $86 million against its corresponding net derivative contract positions as of June 30, 2008 and December 31, 2007, respectively. The remaining balance of net cash margin deposited shown above is primarily included in Accounts Receivable on Power’s Condensed Consolidated Balance Sheets. In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance. Transactions that are margined and monitored 19
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2008
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS separately from physical trading activity may not be subject to change in the event of a downgrade to Power’s rating. As of June 30, 2008, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to $1 billion. Power believes that it could obtain the necessary liquidity to post such collateral. In addition to amounts discussed above, Power had posted $37 million in letters of credit as of June 30, 2008 and December 31, 2007 to support various other contractual and environmental obligations. Environmental Matters PSEG, Power and PSE&G Passaic River The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating electric generating station (Essex Site), one former generating station and four former manufactured gas plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the Societal Benefits Clause (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site. In 2003, the EPA notified 41 potentially responsible parties (PRPs), including Power and PSE&G, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances had been released from the Essex Site and a former MGP located in Harrison, New Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to eight years to complete and would cost $20 million, of which it would seek to recover $10 million from the PRPs, including Power and PSE&G. In 2006, the EPA notified the PRPs that the cost of its study will greatly exceed the $20 million initially estimated and after discussion, 73 PRPs, including Power and PSE&G, have agreed to assume responsibility for the study pursuant to an Administrative Order on Consent and to divide the associated costs among themselves according to a mutually agreed-upon formula. The PRP group is presently executing the study. The percentage allocable to Power and PSE&G varies depending on the number of PRPs who have agreed to divide the costs but it currently approximates 6%, approximately 80% of which is attributable to PSE&G’s former MGPs and approximately 20% to Power’s generating station. Power has provided notice to insurers concerning this potential claim. In June 2007, the EPA announced a draft Focused Feasibility Study (FFS) that proposes six options with estimated costs ranging from $900 million to $2.3 billion to address contamination cleanup in the lower eight miles of the Passaic River in addition to a “No Action” alternative. The work contemplated by the FFS is not subject to the Administrative Order on Consent or the cost sharing agreement. The EPA is reviewing comments received on the draft FFS. CERCLA and the New Jersey Spill Compensation and Control Act (Spill Act) authorize federal and state trustees for natural resources to assess damages against persons who have discharged a hazardous substance, causing an injury to natural resources. Pursuant to the Spill Act, the New Jersey Department of Environmental Protection (NJDEP) requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that 20
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the Spill Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. In August 2007, the National Oceanic and Atmospheric Administration of the United States Department of Commerce sent a letter to PSE&G and other companies identified as PRPs notifying them that it intended to perform an assessment of injuries to natural resources and inviting the PRPs to participate. The PRPs have not agreed to participate in either of these natural resource damage initiatives. In June 2008, an agreement was announced between the EPA and two PRP’s for removal of a portion of the contaminated sediment in the Passaic. The work will cost an estimated $80 million. The two PRP’s have reserved their rights to seek contribution for the removal costs from the other PRPs, including PSEG. PSEG cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River. However, such costs could be material. Newark Bay Study Area The EPA sent PSEG and 11 other entities notices that the EPA considered each of the entities to be a PRP with respect to contamination in the Newark Bay Study Area, which it defined as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. The notice letter requested that the PRPs participate and fund the EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study (RI/FS) that OCC is conducting in the Newark Bay Study Area. The EPA considers the Newark Bay Study Area, along with the Passaic River Study Area, to be part of the Diamond Alkali Superfund Site. The notice states the EPA’s belief that hazardous substances were released from sites owned by PSEG and located on the Hackensack River. The sites included two operating electric generating stations (Hudson and Kearny sites) and one former MGP. PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. The Hudson and Kearny sites were transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Hudson and Kearny sites. Power has provided notice to insurers concerning this potential claim. PSEG cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Newark Bay Study Area. However, such costs could be material. Other In June 2007, the State of New Jersey filed multiple lawsuits in New Jersey Superior Court against parties, including PSE&G, who were alleged to be responsible for injuries to natural resources in New Jersey. Included in these lawsuits was a claim against PSE&G and others arising out of PSE&G’s former Camden Coke facility, and a claim against PSE&G and others arising out of the Global Landfill matter. PSE&G has responded to the complaint in the natural resource damages case arising out of the former Camden Coke site and is in the process of remediating that site under its MGP program, discussed below. In March 2008, Power executed an Amended Consent Decree, which obligates the settling parties (including PSE&G) to implement remediation of the Global Landfill site and resolves the natural resource damages claim. A motion for entry of the Amended Consent Decree by the court in the Global Landfill matter was filed by the State of New Jersey in late June 2008. PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, Newark Bay or other natural resource damages claims; however, such costs could be material. PSE&G MGP Remediation Program PSE&G is working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as 21
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS sites requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant sites for cleanup. One of the sites identified is PSE&G’s former Camden Coke facility located in Camden. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based on regulatory requirements, experience with the program and available remediation technologies. As of December 31, 2007, PSE&G’s estimate to remediate all MGP sites to completion, as well as the anticipated costs to address MGP-related material discovered in three rivers adjacent to two former MGP sites, resulted in a range between $639 million and $812 million through 2021. During the second quarter of 2008, the estimate for one MGP site was revised. Based on that revision, the remaining costs of remediating all sites to completion could range between $648 million and $828 million through 2021, which represents the increased estimated cost of $20 million less $11 million of costs incurred in 2008. Since no amount within the range was considered to be most likely, PSE&G recorded a liability of $648 million as of June 30, 2008. Of this amount, $45 million was recorded in Other Current Liabilities and $603 million was reflected in Environmental Costs in Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, PSE&G has a Regulatory Asset recorded which is equivalent to the accrued liability. Power Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act, require major sources of certain air pollutants to obtain permits, install pollution-control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation. On November 30, 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets consistent with an earlier consent decree that resolved allegations of non- compliance with PSD/NSR programs at Power’s Mercer, Hudson and Bergen generating stations. Under this agreement and the consent decree, Power is required to undertake a number of technology projects, plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter and mercury. Pursuant to this program, Power has installed selective catalytic reduction equipment at Mercer at a cost of $122 million. The cost of implementing the balance of the agreement is estimated at $475 million to $525 million for Mercer, to be completed by May 2010, and $700 million to $750 million for Hudson, to be completed by the end of 2010. Fossil also purchased and retired emissions allowances by July 31, 2007, paid a $6 million civil penalty and has agreed to contribute $3 million for programs to reduce particulate emissions from diesel engines in New Jersey. Two particulate emissions reduction projects are in development to meet the agreement criteria. In May 2007, Mercer Units 1 and 2 commenced construction of the back-end emission control projects. In February 2008, Hudson Unit 2 commenced construction of the back-end emission control projects. Mercury Regulation In March 2005, the EPA established a New Source Performance Standard limit for nickel emissions from oil-fired electric generating units, and a cap-and-trade program for mercury emissions from coal-fired electric generating units, with a first phase cap of 38 tons per year (tpy) in 2010 and a second phase cap of 15 tpy in 2018 (Clean Air Mercury Rule). The United States Court of Appeals for the District of Columbia Circuit issued a decision in February 2008 rejecting the EPA’s mercury emissions program. As a result of this decision, the EPA is required to develop emissions standards for mercury and nickel emissions that do not rely on a cap-and-trade program. The full impact, if any, of this development is uncertain until the EPA 22
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS issues the new emissions standards. Compliance with the new mercury standards, however, is not expected to have a material impact on Power’s operations in New Jersey and Connecticut given the stringent mercury-control requirements applicable in those states, as described below. New Jersey and Connecticut have standards for the reduction of emissions of mercury from coal-fired electric generating units. The regulations in New Jersey required the units to meet certain emissions limits or reduce emissions by approximately 90% by December 15, 2007, unless a one-year extension was granted by NJDEP. Under the New Jersey regulations, companies that are parties to multi-pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. With respect to Power’s New Jersey facilities, half of the reductions that were required by December 15, 2007 are expected to be achieved through the installation of carbon injection technology at both Mercer Units, which was completed in January 2007. Because there is some uncertainty as to whether the system can consistently achieve the required reductions, Power has applied for and received from NJDEP approval of a one-year extension through a facility-specific control plan that includes the installation of baghouses at the Mercer Units in 2008. Installation is scheduled to be completed by the end of 2008. At its Hudson plant, Power anticipates compliance consisting of the installation of a baghouse by the end of 2010. The mercury-control technologies are also part of Power’s multi-pollutant reduction agreement, which resulted from earlier agreements that resolved issues arising out of the PSD/NSR air pollution control programs discussed above. Mercury emissions control standards effective in July 2008 in Connecticut require coal-fired power plants in Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions. Power anticipates compliance at its Bridgeport Harbor Station resulting from the installation of a baghouse which was placed in operation in January 2008. In February 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal-fired electric generating units. The Keystone and Conemaugh generating stations will be positioned by 2010 to meet Phase I of the Pennsylvania mercury rule by benefiting from reductions realized from the installation of controls for compliance with SO2 and NOx reductions. Phase 2 of the mercury rule will be addressed after a full evaluation of Phase 1 reductions. Some uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute. However, the estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired units in Connecticut, New Jersey and Pennsylvania have been incurred or are included in Power’s capital expenditure forecast. Total estimated costs for each project are between $150 million and $200 million. The costs for Mercer and Hudson are included in the cost estimates referred to in the PSD/NSR discussion above. Emission Fees Section 185 of the Clean Air Act requires states (or in the absence of state action, the EPA) in severe and extreme non-attainment areas to adopt a penalty fee for major stationary sources if the area fails to attain the one-hour ozone National Ambient Air Quality Standard (NAAQS) set by the EPA. In June 2007, the U.S. Court of Appeals for the District of Columbia Circuit ruled against the EPA, which had sought to vacate imposition of fees for NOx emissions as part of the one-hour standard for ozone attainment implementation. Power operates electric generation stations, major stationary sources, in the New Jersey-Connecticut severe non-attainment area that failed to meet the required NAAQS. Neither the EPA nor the states in the non-attainment areas in which Power operates have initiated the process for imposing fees in compliance with the court ruling; however, preliminary analysis suggests that penalty fees will be approximately $6 million annually. This analysis could change if the EPA or the states issue additional guidance addressing the imposition of fees, or if Power is able to reduce its emissions of NOx in the future below the statutory threshold through the installation of control technologies at one or more of Power’s generation stations. 23
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Jersey Industrial Site Recovery Act (ISRA) Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability as of each of June 30, 2008 and December 31, 2007 related to these obligations, which is included in Environmental Costs on Power’s and PSEG’s Condensed Consolidated Balance Sheets. Permit Renewals In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. A renewal application prepared in accordance with the Federal Water Pollution Control Act (FWPCA) Section 316(b) and the Phase II 316(b) rule was filed in January 2006 with the NJDEP, which allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power’s application to renew Salem’s NJPDES permit demonstrates that the station satisfies FWPCA Section 316(b) and meets the Phase II 316(b) rule’s performance standards for reduction of impingement and entrainment through the station’s existing cooling water intake technology and operations plus implemented restoration measures. The application further demonstrates that even without the benefits of restoration, the station meets the Phase II 316(b) rule’s site-specific determination standards, both on a comparison of the costs and benefits of new intake technology as well as a comparison of the costs to implement the technology at the facility to the cost estimates prepared by the EPA. In January 2007, the U.S. Court of Appeals for the Second Circuit issued its decision in litigation of the Phase II 316(b) regulations brought by several environmental groups, the Attorneys General of six Northeastern states, including New Jersey, the Utility Water Act Group and several of its members, including Power. The court remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. The court instructed the EPA to reconsider the definition of “best technology available” without comparing the costs of the best performing technology to its benefits. Prior to this decision, Power had used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer. In May 2007, Power and other industry petitioners filed with the Second Circuit Court a request for a rehearing, which was denied. The parties, including Power, requested U.S. Supreme Court review of the matter. In April 2008, the U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the FWPCA allows EPA to compare costs with benefits in determining the “best technology available” for minimizing adverse environmental impact at cooling water intake structures. Oral argument will occur in the Court’s 2008-2009 term, which begins in October 2008. It is anticipated that the Court will render a decision during that term. Although the rule applies to all of Power’s electric generating units that use surface waters for once-through cooling purposes, the impact of the rule and the decision of the Second Circuit Court cannot be determined for all of Power’s facilities. Depending on the final decision of the U.S. Supreme Court, and subsequent actions by the EPA to promulgate a revised rule, the Second Circuit’s decision could have a material impact on Power’s ability to renew its New Jersey and Connecticut permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and, possibly, Sewaren and New Haven, without making significant upgrades to their existing intake structures and cooling systems. If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at these once-through cooled facilities, the related costs and impacts would be material to Power and would require economic review to determine whether to continue operations. For example, Power’s application to renew its Salem permit, filed in February 2006 with the NJDEP, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of which Power’s share would be approximately $575 million. Potential costs associated with any closed-cycle cooling requirements are not included in Power’s forecasted capital expenditures. 24
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Generation and Development Power Power increased its generating capacity at Hope Creek and Salem Unit 2 in 2008. Phase I of the Hope Creek turbine replacement project increased the nominal capacity of the unit by 10 MW in 2005. Initial testing indicates that Phase II added approximately 125 MW of nominal capacity in the second quarter of 2008. Final performance testing will be conducted later this year. Phase I of the Salem Unit 2 turbine upgrade increased Power’s share of the nominal capacity by 14 MW in 2003. Phase II was completed and put in operation in the second quarter of 2008, concurrent with steam generator replacement and increased Power’s share of the nominal capacity by approximately 11 MW. Final performance testing will be conducted later this year. Power’s total expenditures for these projects were $212 million (including Interest Capitalized During Construction of $24 million). Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) Power and PSE&G PSE&G obtains its electric supply requirements through the annual New Jersey BGS auctions for customers who do not purchase electric supply from third-party suppliers. PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days following the BPU’s approval. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Interconnection L.L.C. (PJM) Load Serving Entity including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any customer migration risk and must satisfy New Jersey’s renewable portfolio standards. Power seeks to mitigate volatility in its results by contracting in advance for most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power enters into firm supply contracts with EDCs, as well as other firm sales and commitments. PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows: Auction Year 2005 2006 2007 2008 36 Month Terms Ending May 2008 May 2009 May 2010 May 2011(a ) Load (MW) 2,840 2,882 2,758 2,840 $ per kWh $ 0.06541 $ 0.10251 $ 0.09888 $ 0.1115
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| Prices set in the February 2008 BGS Auction became effective on June 1, 2008 when the 2005 Auction Year agreements expired. | ||||||||||||||||||
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G’s residential gas supply annually through the BGSS tariff. For additional information, see Note 14. Related-Party Transactions.
The BPU is conducting an audit of the gas procurement practices of all four New Jersey gas utilities, including PSE&G. The outcome of this proceeding cannot be predicted.
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Minimum Fuel Purchase Requirements Power Coal Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. As of June 30, 2008, the total minimum purchase requirements included in these commitments amounted to approximately $1 billion through 2012. Uranium Power has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations. Power has inventory and commitments to purchase sufficient quantities of uranium concentrates to meet 100% of its total estimated requirements through 2011 and approximately 60% of its estimated requirements for 2012. Additionally, Power has commitments for uranium hexafluoride to meet 100% of its estimated requirements for 2011 and 92% for 2012. These commitments, based on current market prices, which have increased substantially over the past two to three years, total $562 million ($395 million Power’s estimated share). Power’s policy is to maintain certain levels of concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to above include estimated quantities to be purchased that are in excess of contractual minimum quantities. Power also has commitments that provide 100% of its uranium enrichment requirements through 2011 and 35% for 2012, totaling $273 million ($184 million Power’s estimated share). Power has commitments that provide 100% of the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek that total $114 million ($84 million Power’s estimated share). Exelon Generation has informed Power that the Peach Bottom plant has inventory and commitments to purchase sufficient quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of its total estimated requirements through 2010. Additionally, Power has been informed that Exelon Generation has commitments covering approximately 100% of its estimated requirements for 2011 and 47% for 2012. Natural Gas Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. As of June 30, 2008, the total minimum requirements under these contracts were approximately $900 million through 2012. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. The generation facilities of PSEG Texas, LP (PSEG Texas), a wholly owned subsidiary of Global, have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of June 30, 2008, the plants had fuel purchase commitments totaling $105 million to support all of their contracted energy sales. Regulatory Proceedings PSEG and PSE&G Electric Discount and Energy Competition Act (Competition Act) In April 2007, PSE&G and Transition Funding were served with a copy of a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain provisions of 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. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional. 26
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In July 2007, the same plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. 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. Briefing of the appeal has been completed. 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 charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. PSE&G’s motion to dismiss the BPU petition is pending. Investment Tax Credits (ITC) The Internal Revenue Service (IRS) has issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which for PSE&G, was terminated upon New Jersey’s electric industry deregulation in 1999. Based on this fact, in 1999, PSE&G reversed the deferred tax and ITC liability relating to the generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge due to such restructuring of the industry in New Jersey. In May 2006, the IRS issued a PLR to PSE&G, which concluded that none of the generation ITC could be passed to utility customers without violating its normalization rules. In March 2008, the Treasury issued final regulations that confirmed that none of the generation-related ITC could be passed to utility customers without violating the normalization rules. PSE&G has advised the BPU of these regulations and awaits the BPU’s determination on this matter. While the issuance of the regulations is a favorable development for PSE&G, no assurance can be given as to final outcome of this issue. BPU Deferral Audit The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit—Phase II report relating to the 12-month period ended July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addresses the SBC, Market Transition Charge (MTC) and Non-Utility Generation deferred balances. The BPU released the report in May 2005. While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The amount in dispute is $114 million, which if required to be refunded to customers with interest through June 2008, would be $129 million. At PSE&G’s request, the matter was transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request in February 2007. In May 2007, PSE&G filed a motion for Summary Judgment requesting dismissal of the matter. In September 2007, the Administrative Law Judge issued an initial decision denying PSE&G’s motion to dismiss the matter and ordering the filing of testimony and evidentiary hearings. Hearings were held in July 2008 with briefs scheduled to be filed in the fall of 2008. The BPU Staff and New Jersey Division of Rate Counsel have both asserted in briefs that the disputed amount should be refunded to customers. While PSE&G believes the MTC methodology it used was fully litigated and resolved by the prior BPU Orders in its previous electric base rate case, deferral audit and deferral proceedings, PSE&G cannot predict the outcome of this proceeding. New Jersey Clean Energy Program The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The sum of PSE&G’s electric and gas funding requirement was $72 million and $62 million for the six months ended June 30, 2008 and 2007, respectively. The remaining liability has been recorded with an offsetting Regulatory Asset, since the costs 27
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS associated with this program are expected to be recovered from PSE&G ratepayers through the SBC. The liability for the funding requirement as of June 30, 2008 and December 31, 2007 was $75 million and $149 million, respectively. Energy Holdings Leveraged Lease Investments In November 2006, the IRS issued its Revenue Agent’s Report with respect to its audit of PSEG’s Federal corporate income tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain lease transactions that are similar to a type that the IRS publicly announced its intention to challenge. In addition, the IRS Report proposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest of these findings with the Office of Appeals of the IRS. In April 2008, the IRS issued its Revenue Agent’s Report for tax years 2001 through 2003, which disallowed all deductions associated with lease transactions similar to those disallowed in its 1997 through 2000 Report. As in its prior report, the IRS proposed a 20% penalty. PSEG prepared a protest to this report which was filed with the Office of Appeals of the IRS. As of June 30, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1 billion and $1.5 billion, respectively. PSEG has been in discussions with the Office of Appeals of the IRS concerning the deductions that have been disallowed. PSEG believes that 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 tax cases involving other taxpayers with similar leverage lease investments that are pending. To date, three cases have been decided at the trial court level, two of which were decided in favor of the government. An appeal of one of these decisions was recently affirmed. The third case involves a jury verdict that is currently being challenged by both parties on inconsistency grounds. PSEG believes that its leasing transactions are fully consistent with Resources’ long-standing business model and its focus on energy-related assets of the type which PSEG has traditionally owned and operated. Based on the status of discussions with the IRS, and considering developments in other cases,PSEG currently anticipates that it will pay $300 million to $350 million in taxes, interest and penalties claimed by the IRS for the 1997–2000 audit cycle later in 2008, and subsequently commence litigation to recover a refund. Earnings Impact As a result of the recent court decisions regarding these types of leveraged lease transactions, PSEG evaluated its unrecognized tax benefits under FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), and recorded an after-tax increase to the interest reserve of $135 million in the second quarter of 2008. This charge is recorded in Income Tax Expense in PSEG’s Condensed Consolidated Statements of Operations. Assuming all rental payments are made pursuant to the original lease agreement, and there are no changes in tax legislation and rates, the total cash and income included in a leveraged lease transaction will not change over the lease term. However, the timing of the cash flow can change due to changes in the timing of tax deductions. Changes in the timing of cash flows affect the overall return, or yield, that is recorded as income at a constant rate throughout the lease term. If there is a change in cash flow timing, pursuant to FSP 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction”, the lease must be recalculated from inception assuming the new lease yield. Differences between the current gross lease investment and the gross lease investment per the recalculated lease must be recognized immediately in income. PSEG has recalculated its lease transactions, incorporating potential cash payments (discussed below) consistent with the FIN 48 reserve position, and recorded an after-tax charge of $355 million in the second quarter of 2008. This charge is reflected as a reduction in Operating Revenues of $485 million with a partially 28
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS offsetting reduction in Income Tax Expense of $130 million in PSEG’s Condensed Consolidated Statements of Operation. The $355 million will be recognized as income over the remaining term of the affected leases. The aggregate reserves recorded as of June 30, 2008 represents PSEG’s view of most of the financial statement exposure related to these lease transactions. Cash Impact If the IRS’ disallowance of tax benefits associated with all of these lease transactions was sustained, approximately $1,166 million would become currently payable as of June 30, 2008. This is composed of $957 million of deferred tax liabilities that have been recorded under leveraged lease accounting through June 30, 2008 and cumulative interest on this deficiency of $209 million, after-tax. In addition, as of June 30, 2008, penalties of $147 million have been proposed by the IRS. Interest and penalties grow at the rate of $15 million per quarter. In December 2007, PSEG deposited $100 million with the IRS to defray potential interest costs associated with this disputed tax liability. In the event PSEG is successful in its defense of its position, the deposit is fully refundable with interest. A resolution of this matter, consistent with the reserves established under FIN 48, could result in additional tax and interest payments approximating $900 million to $950 million, including the amounts for the 1997–2000 audit cycle discussed above. The actions described above concerning the leveraged lease investments are not expected to violate any covenant or result in a default under either Energy Holdings’ credit facility or Senior Notes indenture. Note 6. Financial Risk Management The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, Power and PSE&G manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, Power and PSE&G use the term ‘hedge’ to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, Power and PSE&G uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices. Derivative Instruments and Hedging Activities Energy Contracts Power Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward and futures markets, primarily in PJM, New York and New Jersey and natural gas in the producing region. Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures. There have been significant increases in commodity prices over the last year. The resultant changes in market values for energy and related contracts that qualify for hedge accounting have resulted in significant increases to Accumulated Other Comprehensive Loss. For additional information, see Note 5. Commitments and Contingent Liabilities. For contracts not qualifying for hedge accounting, Power marks its derivative energy contracts to market in accordance with SFAS 133 “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) with changes in fair value charged to the Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current 29
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results. The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs. Cash Flow Hedges Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2008, the fair value of these hedges was $(1.5) billion. These hedges resulted in an $(870) million after-tax impact on Accumulated Other Comprehensive Loss. As of December 31, 2007, the fair value of these hedges was $(427) million. These hedges, along with realized losses on hedges of $(4) million retained in Accumulated Other Comprehensive Loss, resulted in a $(250) million after-tax impact on Accumulated Other Comprehensive Loss. During the 12 months ending June 30, 2009, $(478) million of after-tax unrealized losses on these commodity derivatives is expected to be reclassified to earnings with another $(282) million of after-tax unrealized losses to be reclassified to earnings for the 12 months ending June 30, 2010. Ineffectiveness associated with these hedges, as defined in SFAS 133, was a loss of $4 million at June 30, 2008. The expiration date of the longest dated cash flow hedge is in 2011. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for cash flow hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations and a portion is used in Power’s Nuclear Decommissioning Trust Funds (NDT). Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs, Operating Revenues, Other Income or Other Deductions, as appropriate, on the Consolidated Statements of Operations. The net fair value of these instruments was $39 million and $(10) million as of June 30, 2008 and December 31, 2007, respectively. Energy Holdings Cash Flow Hedges Energy Holdings uses forward sale and purchase contracts and swaps to hedge forecasted energy sales from one of its generation stations. Energy Holdings also enters into swap transactions to hedge the price of fuel. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of June 30, 2008, the fair value of these hedges was $(1) million. During the 12 months ending June 30, 2009, substantially all of the after-tax unrealized losses on these commodity derivatives are expected to be reclassified to earnings. There was no ineffectiveness associated with these hedges, as defined in SFAS 133. These hedges resulted in an after-tax impact of less than $(1) million on Accumulated Other Comprehensive Loss. The expiration date of the longest dated cash flow hedge is in 2009. Other Derivatives The generation facilities of PSEG Texas enter into electricity forward and capacity sales contracts to sell a portion of their 2,000 MW capacity with the balance sold into the daily spot market. They also enter into gas purchase contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby provide financial stability to PSEG Texas, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales 30
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value through the Consolidated Statements of Operations. The net fair value of the open positions was $12 million and $63 million as of June 30, 2008 and December 31, 2007, respectively. During March and April of 2008, in connection with the sale of SAESA, Energy Holdings purchased six four-month options to sell Chilean Pesos and receive U.S. Dollars at strike prices between 470 and 480 Chilean Pesos to one U.S. Dollar for a combined notional amount of $300 million. These options were purchased to protect the expected sales proceeds of SAESA from a devaluation of the Chilean Peso prior to the anticipated sale. After the announcement in June 2008 that an agreement was signed to sell SAESA, Energy Holdings sold all six options, resulting in a $5 million after-tax gain which is included in Income from Discontinued Operations on the Condensed Consolidated Statement of Operations of PSEG for the quarter and six months ended June 30, 2008. See Note 3. Discontinued Operations and Dispositions. Interest Rates PSEG, Power and PSE&G PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives. Fair Value Hedges PSEG and Power PSEG uses an interest rate swap to convert Power’s fixed-rate debt of $250 million of 3.75% Senior Notes due April 2009 into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of June 30, 2008 and December 31, 2007, the fair value of the hedge was $1 million and $(2) million, respectively. Cash Flow Hedges PSEG and PSE&G PSEG and PSE&G use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in Accumulated Other Comprehensive Loss. As of June 30, 2008, the fair value of these cash flow hedges was $(3) million and $(7) million at PSE&G and Energy Holdings, respectively. As of December 31, 2007, the fair value of these cash flow hedges was $(4) million and $(7) million at PSE&G and Energy Holdings, respectively. The $(3) million and $(4) million at PSE&G as of June 30, 2008 and December 31, 2007, are not included in Accumulated Other Comprehensive Loss, as they are deferred as Regulatory Assets and are expected to be recovered from PSE&G’s customers. During the next 12 months, $(4) million of unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Loss is expected to be reclassified at PSEG. As of June 30, 2008, there was no hedge ineffectiveness associated with these hedges. 31
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 7. Comprehensive Income (Loss), Net of Tax
(UNAUDITED)
Power (A)
PSE&G
Other (B)
Consolidated
Total
(Millions)
For the Quarter Ended June 30, 2008:
Net Income (Loss)
$
240
$
52
$
(442
)
$
(150
)
Other Comprehensive Loss
(388
)
—
(72
)
(460
)
Comprehensive (Loss) Income
$
(148
)
$
52
$
(514
)
$
(610
)
For the Quarter Ended June 30, 2007:
Net Income
$
184
$
63
$
28
$
275
Other Comprehensive Income
30
—
29
59
Comprehensive Income
$
214
$
63
$
57
$
334
For the Six Months Ended June 30, 2008:
Net Income (Loss)
$
515
$
189
$
(406
)
$
298
Other Comprehensive Loss.
(660
)
—
(20
)
(680
)
Comprehensive (Loss) Income
$
(145
)
$
189
$
(426
)
$
(382
)
For the Six Months Ended June 30, 2007:
Net Income
$
397
$
195
$
12
$
604
Other Comprehensive (Loss) Income
(125
)
—
20
(105
)
Comprehensive Income
$
272
$
195
$
32
$
499
| ||||||||||||||||||||
(A) |
| Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2008 and 2007, as detailed below. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. Changes for 2008 and 2007 primarily relate to foreign currency translation adjustments at Global, as detailed below. | ||||||||||||||||||
Accumulated Other Comprehensive Income (Loss)
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| Balance as of | Power | PSE&G | Other | Balance as of | ||||||||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||||
For the 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 | ) |
| ||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| Balance as of | Power | PSE&G | Other | Balance as of | ||||||||||||||||||||||||||||||
| (Millions) | ||||||||||||||||||||||||||||||||||
For the Six Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
Derivative Contracts |
| $ |
| (114 | ) |
|
| $ |
| (145 | ) |
|
| $ |
| — |
| $ |
| 1 |
| $ |
| (258 | ) |
| |||||||||
Pension and OPEB Plans |
| (214 | ) |
|
| 6 |
| — |
| 1 |
| (207 | ) |
| |||||||||||||||||||||
Currency Translation Adjustment |
| 110 |
| — |
| — |
| 17 |
| 127 | |||||||||||||||||||||||||
NDT Funds |
| 108 |
| 14 |
| — |
| — |
| 122 | |||||||||||||||||||||||||
Other |
| 2 |
| — |
| — |
| 1 |
| 3 | |||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
| $ |
| (108 | ) |
|
| $ |
| (125 | ) |
|
| $ |
| — |
| $ |
| 20 |
| $ |
| (213 | ) |
| ||||||||||
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||
32
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 8. Changes in Capitalization Power In each of June 2008 and March 2008, Power paid a cash dividend to PSEG of $125 million. PSE&G In May 2008, PSE&G redeemed its outstanding $157 million of 6.375% First and Refunding Mortgage Bonds Remarketable Series YY Due 2023 Mandatorily Tendered 2008. PSE&G paid approximately $32 million in cash to settle the remarketing option held by the remarketing dealer. In April 2008, PSE&G issued $400 million of 5.30% Medium-Term Notes, Series E due May 1, 2018. In March 2008, PSE&G issued $300 million of Floating Rate (3-month Libor + 0.875%) Bonds due 2010. As of December 31, 2007, PSE&G had $494 million of variable rate pollution control bonds outstanding which serviced and secured a like amount of insured tax-exempt variable rate bonds of the Pollution Control Authority of Salem County (Salem County Authority). Through April 2008, PSE&G purchased $494 million of the Salem County Authority bonds which were either being held by the broker/dealer or tendered by bondholders upon conversion of the bonds to a weekly interest rate mode. These purchases were recorded as a reduction to PSE&G’s Long-Term Debt included in its Condensed Consolidated Balance Sheets. PSE&G intends to hold these bonds until they can be remarketed or refinanced. In June 2008 and March 2008, Transition Funding repaid $37 million and $40 million, respectively, of its transition bonds. In June 2008, PSE&G Transition Funding II LLC repaid $5 million of its transition bonds. Energy Holdings In March 2008, Energy Holdings repurchased $5 million of the $530 million then outstanding 8.50% Senior Notes due 2011. In February 2008, Energy Holdings repaid at maturity $207 million of its 8.625% Senior Notes. In January 2008, Energy Holdings redeemed its outstanding $400 million of 10% Senior Notes due 2009. During the first six months of 2008, Energy Holdings paid $48 million in premiums related to the early redemption of its outstanding debt. During the first six months of 2008, Energy Holdings’ subsidiaries repaid $22 million of non-recourse debt, primarily related to the PSEG Texas generation facilities. 33
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 9. Other Income and Deductions Power PSE&G Other (A) Consolidated (Millions) Other Income: For the Quarter Ended June 30, 2008: Interest and Dividend Income $ 2 $ 1 $ 3 $ 6 NDT Fund Realized Gains 78 — — 78 NDT Interest and Dividend Income 13 — — 13 Other — 1 — 1 Total Other Income $ 93 $ 2 $ 3 $ 98 For the Quarter Ended June 30, 2007: Interest and Dividend Income $ 10 $ 3 $ (5 ) $ 8 NDT Fund Realized Gains 31 — — 31 NDT Interest and Dividend Income 13 — — 13 Minority Interest — — 2 2 Other 1 2 1 4 Total Other Income $ 55 $ 5 $ (2 ) $ 58 For the Six Months Ended June 30, 2008: Interest and Dividend Income $ 5 $ 4 $ 4 $ 13 NDT Fund Realized Gains 147 — — 147 NDT Interest and Dividend Income 24 — — 24 Other 3 3 1 7 Total Other Income $ 179 $ 7 $ 5 $ 191 For the Six Months Ended June 30, 2007: Interest and Dividend Income $ 15 $ 6 $ (2 ) $ 19 NDT Fund Realized Gains 65 — — 65 NDT Interest and Dividend Income 25 — — 25 Change in Derivative Fair Value — — 1 1 Arbitration Award (Konya-Ilgin) — — 9 9 Minority Interest — — 2 2 Other 1 4 4 9 Total Other Income $ 106 $ 10 $ 14 $ 130
(UNAUDITED)
Total
| ||||||||||||||||||||
(A) |
| Other primarily consists of activity at PSEG (parent company), Energy Holdings, Services and intercompany eliminations. | ||||||||||||||||||
34
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Power
PSE&G
Other (A)
Consolidated Total
(Millions)
Other Deductions:
For the Quarter Ended June 30, 2008:
NDT Fund Realized Losses and Expenses
$
53
$
—
$
—
$
53
NDT Fund Unrealized Losses
1
—
—
1
Other-Than-Temporary Impairment of Investments
33
—
—
33
Total Other Deductions
$
87
$
—
$
—
$
87
For the Quarter Ended June 30, 2007:
NDT Fund Realized Losses and Expenses
$
19
$
—
$
—
$
19
Foreign Currency Losses
—
—
2
2
Other-Than-Temporary Impairment of Investments
14
—
—
14
Other
1
1
—
2
Total Other Deductions
$
34
$
1
$
2
$
37
For the Six Months Ended June 30, 2008:
Donations
$
—
$
1
$
—
$
1
NDT Fund Realized Losses and Expenses
107
—
—
107
NDT Fund Unrealized Losses
1
—
—
1
Loss on Early Extinguishment of Debt
—
—
1
1
Other-Than-Temporary Impairment of Investments
70
—
—
70
Other
—
—
1
1
Total Other Deductions
$
178
$
1
$
2
$
181
For the Six Months Ended June 30, 2007:
Donations
$
—
$
1
$
5
$
6
NDT Fund Realized Losses and Expenses
36
—
—
36
Foreign Currency Losses
—
—
3
3
Loss on Disposition of Assets
2
—
—
2
Other-Than-Temporary Impairment of Investments
24
—
—
24
Other
1
1
—
2
Total Other Deductions
$
63
$
2
$
8
$
73
| ||||||||||||||||||||
(A) |
| Other primarily consists of activity at PSEG (parent company), Energy Holdings, Services and intercompany eliminations. | ||||||||||||||||||
35
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 10. Pension and Other Postretirement Benefits (OPEB) PSEG PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003.
(UNAUDITED)
Pension Benefits
OPEB
Pension Benefits
OPEB
Quarters Ended
June 30,
Quarters Ended
June 30,
Six Months Ended
June 30,
Six Months Ended
June 30,
2008
2007
2008
2007
2008
2007
2008
2007
(Millions)
Components of Net Periodic Benefit
Costs:
Service Cost.
$
20
$
21
$
3
$
4
$
39
$
42
$
7
$
8
Interest Cost
57
54
18
18
114
108
36
36
Expected Return on Plan Assets
(73
)
(72
)
(3
)
(3
)
(145
)
(144
)
(7
)
(7
)
Amortization of Net
Transition Obligation
—
—
7
7
—
—
14
14
Prior Service Cost
3
3
3
3
5
6
6
6
Loss
3
5
(1
)
2
6
10
(1
)
4
Net Periodic Benefit Costs
10
11
27
31
19
22
55
61
Effect of Regulatory Asset
—
—
5
5
—
—
10
10
Total Benefit Costs
$
10
$
11
$
32
$
36
$
19
$
22
$
65
$
71
PSEG, Power and PSE&G
Pension costs and OPEB costs for PSEG and its subsidiaries are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
| Pension Benefits | OPEB | Pension Benefits | OPEB | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Quarters Ended | Quarters Ended | Six Months Ended | Six Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||
2008 | 2007 | 2008 | 2007 | 2008 | 2007 | 2008 | 2007 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Power |
| $ |
| 3 |
| $ |
| 3 |
| $ |
| 3 |
| $ |
| 4 |
| $ |
| 6 |
| $ |
| 6 |
| $ |
| 6 |
| $ |
| 8 | ||||||||||||||||||||||||
PSE&G |
| 4 |
| 5 |
| 28 |
| 30 |
| 8 |
| 10 |
| 57 |
| 60 | ||||||||||||||||||||||||||||||||||||||||
Energy Holdings |
| 1 |
| 1 |
| — |
| — |
| 1 |
| 1 |
| — |
| — | ||||||||||||||||||||||||||||||||||||||||
Services |
| 2 |
| 2 |
| 1 |
| 2 |
| 4 |
| 5 |
| 2 |
| 3 | ||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
Total PSEG Consolidated Benefit Costs |
| $ |
| 10 |
| $ |
| 11 |
| $ |
| 32 |
| $ |
| 36 |
| $ |
| 19 |
| $ |
| 22 |
| $ |
| 65 |
| $ |
| 71 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||||||||||
PSEG may contribute up to $75 million into its qualified pension plans and postretirement healthcare plan during the remaining calendar year 2008.
36
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS An analysis of the tax provision expense is as follows: Power PSE&G Other (A) Consolidated (Millions) For the Quarter Ended June 30, 2008: Income (Loss) Before Income Taxes $ 405 $ 80 $ (437 ) $ 48 Tax Computed at the Statutory Rate 142 28 (153 ) 17 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 26 6 37 69 Uncertain Tax Positions 1 (2 ) 118 117 Other (4 ) (4 ) 19 11 Total Income Tax Expense $ 165 $ 28 $ 21 $ 214 Effective Income Tax Rate 40.7 % 35.0 % N/A N/A For the Quarter Ended June 30, 2007: Income Before Income Taxes $ 318 $ 104 $ 30 $ 452 Tax Computed at the Statutory Rate 111 36 10 157 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 18 8 (1 ) 25 Foreign Operations — — (11 ) (11 ) Uncertain Tax Positions 2 — 1 3 Other — (3 ) — (3 ) Total Income Tax Expense (Benefit) $ 131 $ 41 $ (1 ) $ 171 Effective Income Tax Rate 41.2 % 39.4 % N/A 37.8 % For the Six Months Ended June 30, 2008: Income (Loss) Before Income Taxes $ 867 $ 282 $ (433 ) $ 716 Tax Computed at the Statutory Rate 303 99 (152 ) 250 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 55 21 35 111 Uncertain Tax Positions 1 (22 ) 101 80 Other (7 ) (5 ) 19 7 Total Income Tax Expense $ 352 $ 93 $ 3 $ 448 Effective Income Tax Rate 40.6 % 33.0 % N/A 62.6 % For the Six Months Ended June 30, 2007: Income Before Income Taxes $ 692 $ 335 $ 6 $ 1,033 Tax Computed at the Statutory Rate 242 117 2 361 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 41 24 (4 ) 61 Foreign Operations — — 2 2 Uncertain Tax Positions 3 — 6 9 Other — (1 ) (1 ) (2 ) Total Income Tax Expense $ 286 $ 140 $ 5 $ 431 Effective Income Tax Rate 41.3 % 41.8 % 83.3 % 41.7 %
(UNAUDITED)
Total
| ||||||||||||||||||||
(A) |
| PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs and amounts applicable to Energy Holdings (as parent company) that reflect interim period distortion due to asset sales and other one-time adjustments. | ||||||||||||||||||
37
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Each of PSEG, Power and PSE&G provide deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from PSE&G’s customers in the future. Accordingly, an offsetting Regulatory Asset was established. As of June 30, 2008, PSE&G had a Regulatory Asset of $421 million representing the tax costs expected to be recovered through rates based upon established regulatory practices, which permit recovery of current taxes payable. This amount was determined using the enacted federal income tax rate of 35% and state income tax rate of 9%. PSEG and its subsidiaries adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. On December 17, 2007, PSEG made a tax deposit with the IRS in the amount of $100 million to defray interest costs associated with disputed tax assessments associated with certain lease investments (see Note 5. Commitments and Contingent Liabilities). The $100 million deposit is fully refundable and is recorded as a reduction to the Unrecognized Tax Benefit liability on PSEG’s Condensed Consolidated Balance Sheets. As a result of the recent activity regarding certain types of lease transactions as described in Note 5. Commitments and Contingent Liabilities, PSEG evaluated its unrecognized tax benefits under FIN 48, and recorded a gross increase to the unrecognized tax benefits of $856 million in the second quarter of 2008. As $229 million of this amount relates to an increase to the interest reserve, the after-tax amount of $135 million is recorded in Income Tax Expense. It is reasonably possible that total unrecognized tax benefits at PSEG will decrease by $23 million within the next 12 months due to agreement with the IRS’s position relative to various items included in Federal income tax returns for years 2001-2003. This amount includes a $4 million liability for Power, a $3 million benefit for PSE&G, a $27 million liability for Energy Holdings and a $5 million benefit for PSEG parent. As a result of a change in accounting method for the capitalization of indirect costs, during the first six months of 2008, PSEG reduced the net amount of its unrecognized tax benefits by $83 million, approximately $45 million of which related to PSE&G. Because the IRS agreed with PSEG’s change in accounting method, it is reasonably possible that PSEG’s claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the unrecognized tax benefits. 38
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 12. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below:
(UNAUDITED)
Power
PSE&G
Resources
Global
Other (A)
Consolidated
(Millions)
For the Quarter Ended June 30, 2008:
Total Operating Revenues
$
1,623
$
1,858
$
(457
)
$
226
$
(689
)
$
2,561
Income (Loss) From Continuing Operations
240
52
(470
)
18
(6
)
(166
)
Income from Discontinued Operations, net of tax
—
—
—
16
—
16
Net Income (Loss)
240
52
(470
)
34
(6
)
(150
)
Preferred Securities Dividends
—
(1
)
—
—
1
—
Segment Earnings (Loss)
240
51
(470
)
34
(5
)
(150
)
Gross Additions to Long-Lived Assets
210
200
1
1
4
416
For the Quarter Ended June 30, 2007:
Total Operating Revenues
$
1,305
$
1,748
$
35
$
199
$
(580
)
$
2,707
Income (Loss) From Continuing Operations
187
63
15
33
(17
)
281
Loss from Discontinued Operations, net of tax
(3
)
—
—
(3
)
—
(6
)
Net Income (Loss)
184
63
15
30
(17
)
275
Preferred Securities Dividends
—
(1
)
—
—
1
—
Segment Earnings (Loss)
184
62
15
30
(16
)
275
Gross Additions to Long-Lived Assets
197
166
1
12
8
384
For the Six Months Ended June 30, 2008:
Total Operating Revenues
$
3,998
$
4,476
$
(426
)
$
334
$
(2,018
)
$
6,364
Income (Loss) From Continuing Operations
515
189
(456
)
33
(13
)
268
Income from Discontinued Operations, net of tax
—
—
—
30
—
30
Net Income (Loss)
515
189
(456
)
63
(13
)
298
Preferred Securities Dividends
—
(2
)
—
—
2
—
Segment Earnings (Loss)
515
187
(456
)
63
(11
)
298
Gross Additions to Long-Lived Assets
384
345
1
3
6
739
For the Six Months Ended June 30, 2007:
Total Operating Revenues
$
3,454
$
4,234
$
79
$
301
$
(1,853
)
$
6,215
Income (Loss) From Continuing Operations
406
195
31
6
(36
)
602
(Loss) Income from Discontinued Operations, net of tax
(9
)
—
—
11
—
2
Net Income (Loss)
397
195
31
17
(36
)
604
Preferred Securities Dividends
—
(2
)
—
—
2
—
Segment Earnings (Loss)
397
193
31
17
(34
)
604
Gross Additions to Long-Lived Assets
323
296
1
28
11
659
As of June 30, 2008:
Total Assets
$
8,811
$
14,774
$
2,468
$
2,309
$
(28
)
$
28,334
Investments in Equity Method Subsidiaries
$
16
$
—
$
—
$
213
$
—
$
229
As of December 31, 2007:
Total Assets
$
8,336
$
14,637
$
2,992
$
2,334
$
—
$
28,299
Investments in Equity Method Subsidiaries
$
14
$
—
$
—
$
208
$
—
$
222
| ||||||||||||||||||||
(A) |
| PSEG’s other activities include amounts applicable to PSEG (as parent corporation) and Energy Holdings (as parent company) and EGDC and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 14. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation. | ||||||||||||||||||
39
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 13. Fair Value Measurements PSEG, Power and PSE&G Effective January 1, 2008, PSEG, Power and PSE&G adopted SFAS 157 except for non-financial assets and liabilities as described in FSP FAS 157-2 and discussed in Note 2. Recent Accounting Standards. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels: Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities, exchange traded derivatives and certain U.S. government treasury securities. Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities. Level 3—measurements use unobservable inputs for assets or liabilities, are based on the best information available and might include an entity’s own data. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various FTRs, other longer term capacity and transportation contracts and certain commingled securities. In addition to establishing a measurement framework, SFAS 157 nullifies the guidance of EITF 02-3, “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. Under EITF 02-3, PSEG Texas had a deferred inception loss of $34 million, pre-tax, as of December 31, 2007 related to a five-year capacity contract at its generation facilities, which was being amortized at $11 million per year through 2010. In accordance with the provisions of SFAS 157, PSEG Texas recorded a cumulative effect adjustment of $22 million after-tax to January 1, 2008 Retained Earnings in its Condensed Consolidated Balance Sheet associated with the implementation of SFAS 157. 40
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table presents information about PSEG’s, Power’s, and PSE&G’s respective assets and liabilities measured at fair value on a recurring basis at June 30, 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.
(UNAUDITED)
Description
Recurring Fair Value Measurements as of June 30, 2008
Total as
of June 30,
2008
Cash
Collateral
Netting (F)
Quoted Market Prices
for Identical Assets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable Inputs
(Level 3)
(Millions)
PSEG
Assets:
Derivative Contracts:
Energy Contracts (A)
$
393
$
—
$
—
$
310
$
83
Other Commodity Contracts (B)
$
58
$
—
$
—
$
8
$
50
Interest Rate Swaps (C)
$
2
$
—
$
—
$
2
$
—
NDT Funds (D)
$
1,254
$
—
$
568
$
654
$
32
Rabbi Trusts (D)
$
137
$
—
$
13
$
110
$
14
Other Long-Term Investments (E)
$
3
$
—
$
3
$
—
$
—
Liabilities:
Derivative Contracts:
Energy Contracts (A)
$
1,047
$
(418
)
$
—
$
1,488
$
(23
)
Other Commodity Contracts (B)
$
136
$
—
$
—
$
44
$
92
Interest Rate Swaps (C)
$
11
$
—
$
—
$
11
$
—
Power
Assets:
Derivative Contracts:
Energy Contracts (A)
$
398
$
—
$
—
$
315
$
83
NDT Funds (D)
$
1,254
$
—
$
568
$
654
$
32
Rabbi Trusts (D)
$
28
$
—
$
3
$
22
$
3
Liabilities:
Derivative Contracts:
Energy Contracts (A)
$
1,051
$
(418
)
$
—
$
1,492
$
(23
)
PSE&G
Assets:
Derivative Contracts:
Other Commodity Contracts (B)
$
3
$
—
$
—
$
—
$
3
Rabbi Trusts (D)
$
48
$
—
$
4
$
39
$
5
Liabilities:
Other Commodity Contracts (B)
$
92
$
—
$
—
$
—
$
92
Interest Rate Swaps (C)
$
3
$
—
$
—
$
3
$
—
| ||||||||||||||||||||
(A) |
| Whenever possible, fair values for energy contracts are obtained from quoted market sources in active markets. When this pricing is unavailable, contracts are valued using broker or dealer quotes or auction prices. For contracts where no observable market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Other commodity contracts primarily include more complex agreements for which limited pricing information is available. These contracts are valued using modeling techniques and assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. | ||||||||||||||||||
| ||||||||||||||||||||
(C) |
| 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. | ||||||||||||||||||
| ||||||||||||||||||||
(D) |
| The NDT Funds and the Rabbi Trusts maintain investments in various equity and fixed income securities classified as “available for sale” under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” These securities are valued using quoted market prices, broker or dealer | ||||||||||||||||||
41
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS quotations, or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1). Fixed income securities are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2). Short-term investments are valued based upon internal matrices using observable market prices or market parameters such as time-to- maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The NDT Funds exclude net receivables/payables of $76 million related to pending security sales/purchases. (E) Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices. (F) Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under FIN 39-1. For further discussion, see Note 2. Recent Accounting Standards. A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities follows: Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis Balance as Total Gains or (Losses) Purchases Balance as Included in Included in PSEG Derivative Assets $ 77 $ 15 $ 1 40 $ 133 PSEG Derivative Liabilities $ (77 ) $ 27 $ (19 ) $ — $ (69 ) PSEG NDT Funds $ 27 $ — $ — $ 5 $ 32 PSEG Rabbi Trust Funds $ 14 $ — $ — $ — $ 14 Power Derivative Assets $ 14 $ 29 $ — $ 40 $ 83 Power Derivative Liabilities $ (4 ) $ 27 $ — $ — $ 23 Power NDT Funds $ 27 $ — $ — $ 5 $ 32 Power Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Derivative Assets $ 2 $ — $ 1 $ — $ 3 PSE&G Derivative Liabilities $ (73 ) $ — $ (19 ) $ — $ (92 ) PSE&G Rabbi Trust Funds $ 5 $ — $ — $ — $ 5 Balance as Total Gains or (Losses) Purchases Balance as Included in Included in PSEG Derivative Assets $ 44 $ 38 $ — $ 51 $ 133 PSEG Derivative Liabilities $ (49 ) $ 20 $ (40 ) $ — $ (69 ) PSEG NDT Funds $ 27 $ (1 ) $ — $ 6 $ 32 PSEG Rabbi Trust Funds $ 16 $ — $ — $ (2 ) $ 14 Power Derivative Assets $ 13 $ 19 $ — $ 51 $ 83 Power Derivative Liabilities $ 3 $ 20 $ — $ — $ 23 Power NDT Funds $ 27 $ (1 ) $ — $ 6 $ 32 Power Rabbi Trust Funds $ 3 $ — $ — $ — $ 3 PSE&G Derivative Assets $ 3 $ — $ — $ — $ 3 PSE&G Derivative Liabilities $ (52 ) $ — $ (40 ) $ — $ (92 ) PSE&G Rabbi Trust Funds $ 6 $ — $ — $ (1 ) $ 5 42
(UNAUDITED)
for the Quarter Ending June 30, 2008
of April 1,
2008
Realized/Unrealized
and (Sales)
of June 30,
2008
Income (A)
Regulatory Assets
/Liabilities (B)
of January 1,
2008
Realized/Unrealized
and (Sales)
of June 30,
2008
Income (C)
Regulatory Assets
/Liabilities (B)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (A) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $27 million is included in Operating Revenues and $15 million is included in Other Comprehensive Income. Of the $27 million in Operating Revenues, $(14) million (unrealized) is at PSEG Texas and $41 million (unrealized) is at Power. The $15 million included in Other Comprehensive Income is at Power. (B) Mainly includes losses on PSE&G’s derivative contracts that are not included in either earnings or Other Comprehensive Income, as they are deferred as a Regulatory Asset and are expected to be recovered from PSE&G’s customers. (C) PSEG’s gains and losses are mainly attributable to changes in derivative assets and liabilities of which $50 million is included in Operating Revenues and $8 million is included in Other Comprehensive Income. Of the $50 million in Operating Revenues, $19 million (unrealized) is at PSEG Texas and $31 million (unrealized) is at Power. The $8 million included in Other Comprehensive Income 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 $110 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. Note 14. Related-Party Transactions The majority of the following discussion relates to intercompany transactions. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated during the consolidation process in accordance with GAAP when preparing PSEG’s Condensed Consolidated Financial Statements. BGS and BGSS Contracts Power and PSE&G PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 2012 and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The amounts which Power charged to PSE&G for BGS and BGSS are presented below: Power’s Billings for the Quarters Ended Six Months Ended 2008 2007 2008 2007 (Millions) BGS $ 335 $ 263 $ 607 $ 480 BGSS $ 345 $ 315 $ 1,396 $ 1,364 As of June 30, 2008 and December 31, 2007, Power had net receivables from PSE&G of $262 million and $451 million, respectively, primarily related to the BGS and BGSS contracts. In addition, as of June 30, 2008, PSE&G had a receivable from Power of $292 million and as of December 31, 2007, PSE&G had a payable to Power of $55 million related to gas supply hedges Power entered into for BGSS. Services Power and PSE&G Services provides and bills administrative services to Power and PSE&G. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension 43
(UNAUDITED)
June 30,
June 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below: Services’ Billings for the Payable to Services as of Quarters Ended Six Months Ended 2008 2007 2008 2007 June 30, December 31, (Millions) Power $ 42 $ 34 $ 82 $ 67 $ 22 $ 24 PSE&G $ 71 $ 58 $ 133 $ 107 $ 40 $ 57 These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Condensed Consolidated Financial Statements. PSEG, Power and PSE&G believe that the costs of services provided by Services approximate market value for such services. Tax Sharing Agreements PSEG, Power and PSE&G Power and PSE&G had payables to PSEG related to taxes as follows: Payable to PSEG as of June 30, December 31, (Millions) Power $ 2 $ 43 PSE&G $ 7 $ 5 In addition to these tax payable amounts, as of June 30, 2008 Power had a $4 million current payable to PSEG and as of December 31, 2007 Power had an $8 million current receivable from PSEG related to unrecognized tax positions. As of June 30, 2008, PSE&G had a $48 million current receivable from PSEG and as of December 31, 2007 PSE&G had a $3 million current tax payable to PSEG for unrecognized tax positions. Affiliate Loans and Advances PSEG and Power As of June 30, 2008 and December 31, 2007, Power had a demand note payable of $400 million and $238 million, respectively, to PSEG for short-term funding needs. PSE&G and Services As of each of June 30, 2008 and December 31, 2007, PSE&G had advanced working capital to Services of $33 million. This amount is included in Other Noncurrent Assets on PSE&G’s Condensed Consolidated Balance Sheets. Power and Services As of each of June 30, 2008 and December 31, 2007, Power had advanced working capital to Services of $17 million. This amount is included in Other Noncurrent Assets on Power’s Condensed Consolidated Balance Sheets. 44
(UNAUDITED)
June 30,
June 30,
2008
2007
2008
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Other PSEG and Power As of June 30, 2008, Power had a net payable to PSEG of less than $1 million. As of December 31, 2007, Power had a net payable to PSEG of $5 million related to amounts that PSEG had paid to suppliers on Power’s behalf. PSEG and PSE&G As of June 30, 2008 and December 31, 2007, PSE&G had net receivables from PSEG of $3 million and $11 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf. Power Each series of Power’s Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries. Power Guarantor Other Consolidating Consolidated (Millions) For the Quarter Ended June 30, 2008: Operating Revenues $ — $ 1,905 $ 32 $ (314 ) $ 1,623 Operating Expenses 3 1,461 32 (313 ) 1,183 Operating Income (3 ) 444 — (1 ) 440 Equity Earnings (Losses) of Subsidiaries 249 (10 ) — (239 ) — Other Income 34 106 — (47 ) 93 Other Deductions — (87 ) — — (87 ) Interest Expense (53 ) (21 ) (13 ) 46 (41 ) Income Tax Benefit (Expense) 13 (183 ) 3 2 (165 ) Net Income (Loss) $ 240 $ 249 $ (10 ) $ (239 ) $ 240 For the Quarter Ended June 30, 2007: Operating Revenues $ — $ 1,558 $ 27 $ (280 ) $ 1,305 Operating Expenses — 1,223 28 (282 ) 969 Operating Income (Loss). — 335 (1 ) 2 336 Equity Earnings (Losses) of Subsidiaries 188 (10 ) — (178 ) — Other Income 52 65 — (62 ) 55 Other Deductions (1 ) (34 ) — 1 (34 ) Interest Expense (55 ) (33 ) (12 ) 61 (39 ) Income Tax Expense (Benefit) — (135 ) 6 (2 ) (131 ) Loss from Discontinued Operations, net of tax — — (3 ) — (3 ) Net Income (Loss) $ 184 $ 188 $ (10 ) $ (178 ) $ 184 For the Six Months Ended June 30, 2008: Operating Revenues $ — $ 4,532 $ 59 $ (593 ) $ 3,998 Operating Expenses 5 3,578 59 (593 ) 3,049 Operating (Loss) Income (5 ) 954 — — 949 Equity Earnings (Losses) of Subsidiaries 530 (20 ) — (510 ) — Other Income 73 207 — (101 ) 179 Other Deductions — (178 ) — — (178 ) Interest Expense (106 ) (49 ) (28 ) 100 (83 ) Income Tax Benefit (Expense) 23 (384 ) 8 1 (352 ) Net Income (Loss) $ 515 $ 530 $ (20 ) $ (510 ) $ 515 45
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power Guarantor Other Consolidating Consolidated (Millions) For the Six Months Ended June 30, 2007: Operating Revenues $ — $ 3,959 $ 54 $ (559 ) $ 3,454 Operating Expenses — 3,237 52 (560 ) 2,729 Operating Income — 722 2 1 725 Equity Earnings (Losses) of Subsidiaries 405 (22 ) — (383 ) — Other Income 101 131 — (126 ) 106 Other Deductions (1 ) (63 ) — 1 (63 ) Interest Expense (109 ) (68 ) (23 ) 124 (76 ) Income Tax Benefit (Expense) 1 (295 ) 9 (1 ) (286 ) Loss from Discontinued Operations, net of tax — — (9 ) — (9 ) Net Income (Loss) $ 397 $ 405 $ (21 ) $ (384 ) $ 397 For the Six Months Ended June 30, 2008: Net Cash (Used In) Provided By 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 (Used In) Provided By Financing Activities $ (250 ) $ 99 $ 34 $ 29 $ (88 ) For the Six Months Ended June 30, 2007: Net Cash Provided By (Used In) Operating Activities $ 145 $ 972 $ (41 ) $ (282 ) $ 794 Net Cash Provided By (Used In) Investing Activities $ 430 $ (219 ) $ (36 ) $ (347 ) $ (172 ) Net Cash (Used In) Provided By Financing Activities $ (575 ) $ (759 ) $ 77 $ 628 $ (629 ) As of June 30, 2008: Current Assets $ 2,447 $ 4,663 $ 370 $ (5,272 ) $ 2,208 Property, Plant and Equipment, net 151 3,955 921 — 5,027 Investment in Subsidiaries 3,256 148 — (3,404 ) — Noncurrent Assets 136 1,837 33 (430 ) 1,576 Total Assets $ 5,990 $ 10,603 $ 1,324 $ (9,106 ) $ 8,811 Current Liabilities $ 331 $ 6,177 $ 1,072 $ (5,273 ) $ 2,307 Noncurrent Liabilities 240 1,171 103 (429 ) 1,085 Long-Term Debt 2,653 — — — 2,653 Member’s Equity 2,766 3,255 149 (3,404 ) 2,766 Total Liabilities and Member’s Equity $ 5,990 $ 10,603 $ 1,324 $ (9,106 ) $ 8,811 As of December 31, 2007: Current Assets $ 2,553 $ 3,541 $ 360 $ (4,305 ) $ 2,149 Property, Plant and Equipment, net 149 3,669 934 (1 ) 4,751 Investment in Subsidiaries 3,538 168 — (3,706 ) — Noncurrent Assets 156 1,506 30 (256 ) 1,436 Total Assets $ 6,396 $ 8,884 $ 1,324 $ (8,268 ) $ 8,336 Current Liabilities $ 99 $ 4,489 $ 1,057 $ (4,307 ) $ 1,338 Noncurrent Liabilities 234 858 98 (255 ) 935 Long-Term Debt 2,902 — — — 2,902 Member’s Equity 3,161 3,537 169 (3,706 ) 3,161 Total Liabilities and Member’s Equity $ 6,396 $ 8,884 $ 1,324 $ (8,268 ) $ 8,336 46
(UNAUDITED)
Subsidiaries
Subsidiaries
Adjustments
Total
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL PSEG, Power and PSE&G This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company. The following discussion relates to the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that have occurred during 2008 and the future outlook for Power, PSE&G and PSEG Energy Holdings L.L.C. (Energy Holdings), as well as the key factors that will drive the future performance of these businesses. This discussion includes significant changes in or additions to information reported in the 2007 Annual Report on Form 10-K and refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2007 Annual Report on Form 10-K. PSEG’s business consists of four reportable segments, which are Power, PSE&G and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources). Power Power is an electric generation and wholesale energy marketing and trading company that is focused on generation markets in the Northeast and Mid Atlantic U.S. Through its subsidiaries, Power seeks to produce low-cost energy through efficient operations of its nuclear, coal and gas-fired generation facilities. Power seeks to balance this generation production with its fuel requirements and supply obligations through energy portfolio management. In addition to the electric generation business, Power’s revenues also include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G and to other customers. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and under regulation by the Federal Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. Global Domestically, Global has investments in power producers that own and operate electric generation in Texas, California and Hawaii, with smaller investments in New Hampshire and Pennsylvania. Global has reduced its international risk by monetizing most of its international investments. Resources Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Financial Results PSEG, Power and PSE&G PSEG had a Loss from Continuing Operations of $(166) million or $(0.32) per share for the quarter ended June 30, 2008, as compared to Income from Continuing Operations of $281 million, or $0.55 per share for the same quarter in 2007. PSEG had a Net Loss for the quarter ended June 30, 2008 of $(150) million or $(0.29) per share, as compared to Net Income of $275 million or 0.54 per share for the second quarter of 2007. PSEG had Income from Continuing Operations of $268 million, or $0.53 per share for the six months 47
CONDITION AND RESULTS OF OPERATIONS (MD&A)
ended June 30, 2008, as compared to $602 million, or $1.19 per share for the same period in 2007. PSEG’s Net Income for the six months ended June 30, 2008 was $298 million or $0.59 per share, as compared to Net Income of $604 million, or $1.19 per share for the same period in 2007. The quarter-over-quarter and six-month over six-month changes in PSEG’s Income from Continuing Operations and Net Income reflect improved earnings principally at Power which was more than offset by after-tax charges of $490 million recorded in June 2008 at Resources associated with deductions taken for tax purposes on certain types of leveraged lease transactions that are being challenged by the IRS. Earnings were also slightly lower at PSE&G. As of June 30, 2008, Resources had a total gross investment of $1.0 billion in such transactions. See Note 5. Commitments and Contingent Liabilities for additional information. The primary reasons for the quarter and year-to-date increases over the prior year periods at Power were higher prices and sales volumes, higher prices realized from recontracted Basic Generation Service (BGS) and higher mark-to-market (MTM) gains in 2008 as compared to 2007. The increases were somewhat offset by higher generation costs, largely due to increased prices for natural gas and coal purchases, higher Operation and Maintenance costs related to outages at certain of Fossil’s facilities and the recognition of $19 million and $47 million in the second quarter and first half of 2008, respectively, of additional other-than-temporary impairments on certain securities in the Nuclear Decommissioning Trust Funds. During 2008, commodity prices increased significantly, resulting in a material increase in Power’s Accumulated Other Comprehensive Loss of $(619) million for the six months ended June 30, 2008 mainly related to the derivative transactions entered into to hedge forecasted energy sales from its generation stations. Power’s required margin postings for sales contracts entered into in the normal course of business also significantly increased due to the increased commodity prices. Should commodity prices rise further, additional margin calls may be necessary relative to existing power sales contracts. Business Developments PSEG, Power and PSE&G In January 2008, PSEG’s Board of Directors approved a two-for-one stock split of PSEG’s outstanding shares of common stock. Also in January 2008, April 2008 and July 2008, PSEG’s Board of Directors approved a $0.3225 per share dividend for each of the first three quarters of 2008, reflecting an indicated annual dividend rate of $1.29 per share. In January 2008, PSE&G, ER&T, Power Connecticut, Fossil and Nuclear submitted market-based rate (MBR) filings to FERC in which they asserted that they either lack market power or, that market power is being effectively mitigated in various markets. In April 2008, FERC issued a decision that eliminates the need for these companies to conduct a market power analysis within the Northern PSEG sub-market. In June 2008, PJM filed a revised transmission capability study, potentially impacting the MBR analysis. In an order issued July 17, 2008, FERC clarified how MBR sellers should calculate transmission capability in their respective market areas. As a result, PSE&G, ER&T, Power Connecticut, Fossil and Nuclear expect to file a revised MBR analysis based on these recent orders by September 2, 2008. The outcome of this proceeding cannot be predicted. In February 2008, the BPU approved the results of New Jersey’s annual BGS-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price auctions and PSE&G successfully secured contracts to provide the anticipated electricity requirements for its customers. As a result of the February 2008 auction, new BGS-FP rates increased the average residential customer’s bill by approximately 12% effective June 2008. In March 2008, FERC approved the classification of new 69 kV facilities as transmission rather than distribution which PSE&G expects to result in improvements in reliability and more expeditious rate treatment for these facilities. In March 2008, the U.S. Department of Treasury issued final regulations regarding Investment Tax Credit (ITC) normalization, referring to deferred tax balances that were to be refunded to utility customers but were terminated upon New Jersey’s electric industry deregulation in 1999. The ruling confirmed that none of the generation-related ITC could be passed to utility customers without violating the normalization rules. In April 2008, the U.S. Supreme Court granted the request of industry petitioners, including Power, to review the question of whether Section 316(b) of the Federal Water Pollution Control Act allows the U.S. Environmental Protection Agency (EPA) to compare costs with benefits in determining the “best technology 48
available” for minimizing adverse environmental impact at cooling water intake structures. This matter could have a material impact on Power’s ability to renew Clean Water Act permits at a number of its larger plants without making significant equipment upgrades involving material expenditures. See Note 5. Commitments and Contingent Liabilities for additional information. In April 2008, New Jersey issued a draft Energy Master Plan (EMP). A final report is expected to be available later in 2008. The EMP proposes a number of actions to improve energy efficiency and increase the use of renewable resources and clean central station power for addressing climate change. In April 2008, the BPU approved a settlement agreement allowing PSE&G to invest approximately $105 million in a solar energy pilot program, designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. PSE&G will provide loans to customers in its electric service territory for the installation of solar photovoltaic systems on the customers’ premises. The program is open to commercial, industrial and residential customers. As of June 30, 2008, PSE&G has received applications for approximately 38.5% of the 30 MW program. In April 2008, FERC approved incentive rate treatment for PSE&G’s Susquehanna-Roseland transmission line project, which will enable PSE&G to earn an adequate return on investment, full recovery of construction costs and the authority to transfer certain incentives to affiliates that are members of Regional Transmission Organizations (RTOs). In May 2008, several state commissions, including the BPU and consumer advocacy agencies, as well as customer groups and certain federal agencies filed a complaint with FERC with respect to PJM’s Reliability Pricing Model (RPM) on the grounds that the capacity prices set in the first three RPM auctions were not just and reasonable. If granted by FERC, this complaint would have a material adverse impact on Power’s revenues. For additional information relating to this complaint and PJM’s evaluation of ways to improve the RPM process, see Item 5. Other Information. In May 2008, PSE&G submitted a request to the BPU for an increase in annual BGSS revenues of $376 million to be effective October 1, 2008, representing approximately a 20% increase on a typical residential gas customer’s bill. In June 2008, Power completed projects at Hope Creek and Salem Unit 2 anticipating increasing its nuclear generating capacity at those facilities by 125 MW and 15 MW, respectively. Phase I of the Hope Creek turbine replacement project increased the nominal capacity of the unit by 10 MW in 2005. Initial testing indicates that Phase II added approximately 125 MW of nominal capacity in the second quarter of 2008. Final performance testing will be conducted later this year. Phase I of the Salem Unit 2 turbine upgrade increased Power’s share of the nominal capacity by 14 MW in 2003. Phase II was completed and put in operation in the second quarter of 2008, concurrent with steam generator replacement and increased Power’s share of the nominal capacity by approximately 11 MW. Final performance testing will be conducted later this year. Power’s total expenditures for these projects were $212 million (including Interest Capitalized During Construction of $24 million). In June 2008, as a result of the recent court decisions regarding certain types of leveraged lease transactions, PSEG evaluated its unrecognized tax benefits under FIN 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48), and recorded an after-tax increase to the interest reserve of $135 million in the second quarter of 2008. This charge is recorded in Income Tax Expense in PSEG’s Condensed Consolidated Statements of Operations. PSEG also recorded a charge of $355 million under FSP 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction.” This charge is reflected as a reduction in Operating Revenues of $485 million with a partially offsetting reduction in Income Tax Expense of $130 million in PSEG’s Condensed Consolidated Statements of Operations. As the tax benefits associated with these lease transactions are timing differences, total cash flows and net income in a leveraged lease transaction remain the same after a change in the timing of the cash flows. The charges related to FSP 13-2 will therefore be recognized as income over the remaining terms of the affected leases. In July 2008, PSE&G filed a petition with FERC to implement a cost of service formula rate for its existing and future transmission investment. The request is based on a proposed ROE of 11.68% and, if approved, would allow PSE&G to update its transmission rates annually based on forecasted Operation and Maintenance and capital expenditures for the coming year, with no lag of recovery, and would provide for a true-up to actual expenditures in the subsequent year. PSE&G has requested an effective date of October 1, 2008. 49
In July 2008, the Clean Air Interstate Rule (CAIR) that would have required 28 eastern states to reduce nitrogen oxide (NOx) and sulfur dioxide (SO2) in the 2009, 2010 and 2015 timeframe was vacated by the United States Court of Appeals for the District of Columbia Circuit. Subsequent to that ruling, market prices for SO2 allowances have declined significantly, and a decline in electricity prices in certain states has occurred. Any significant decrease in electricity prices could adversely affect Power’s revenues. PSEG and Power cannot predict the ultimate resolution of CAIR, nor the ultimate effect on their results of operations. Power foresees no change in its existing construction response to controlling NOx and SO2. In July 2008, the Board of Directors of PSEG authorized the repurchase of up to $750 million of PSEG Common Stock to be executed over 18 months beginning August 1, 2008. PSEG is not obligated to acquire any specific number of shares and may suspend or terminate its share repurchases at any time. The amount and timing of any stock repurchases would be based on various factors such as management’s assessment of PSEG’s capital structure and liquidity, the market price of PSEG’s common stock and the opportunity to grow the business if investments are available. In July 2008, Global closed on the sale of its investment in the SAESA Group for a total purchase price of approximately $1.3 billion, including the assumption of approximately $413 million of the consolidated debt of the group. The sale resulted in an after-tax gain of approximately $180 million. Net cash proceeds, after Chilean and US taxes of approximately $275 million, were approximately $600 million. For additional information, see Item 5 Other Information and Note 5. Commitments and Contingent Liabilities. PSEG, Power and PSE&G PSEG’s future success will depend on the ability of Power, PSE&G and Energy Holdings to achieve their respective objectives and earnings expectations, as well as the successful completion of various construction projects and their respective growth initiatives, discussed below. There is no guarantee that such initiatives will be achieved since many issues need to be considered, such as system reliability concerns, regulatory approvals and construction or development costs. In general, PSEG believes it has growth opportunities in the following three key areas: • responding to climate change and continuing to improve environmental performance through investments in energy efficiency, renewables and clean central station power; • upgrading critical energy infrastructure; and • providing new energy supplies. Power A key factor for success is Power’s ability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Historically, Power’s nuclear and coal-fired facilities have produced over 50% and 25% of Power’s production, respectively. Power seeks to sell a portion of this anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of two to four years. With the vast majority of its power sourced from these lower-cost units, rising electric prices have yielded higher margins for Power. Over a longer-term horizon, if prices are sustained at levels reflective of what the current forward markets indicate, Power would have an attractive environment in which to contract for the sale of its anticipated output, allowing for potentially sustained higher profitability than recognized in prior years. However, with an increase in competition and market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While recent higher forward prices may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. For additional information on liquidity requirements, see Liquidity and Capital Resources. Power contracts for the future delivery of nuclear fuel and coal to support its contracted sales. Power’s estimated fuel needs are subject to change based upon the level of its operations as well as upon market demands for and on the price of coal, both of which have increased recently. Earlier in the year, Power revised the pricing for one of its coal supply agreements for the Mercer station through 2008. A second supplier for about 15% of Mercer’s coal requirements has declared a force majeure and has reduced 50
shipment volumes. Power is in negotiations with this supplier which may result in a change in pricing. An Indonesian supplier of coal for the Bridgeport and Hudson generating units has notified PSEG and its other customers of potential concerns on the part of the Indonesian government about contract prices in comparison to current market prices for deliveries after 2008. Power believes it can continue to manage its fuel sourcing needs in this dynamic market but rising prices and potential increasing demand could impact its future operations or financial results. Power could be impacted by a number of events, including regulatory or legislative actions favoring non-competitive markets, energy efficiency initiatives and regulatory policies favoring the construction of rate-based transmission that may result in increased imports of power, which may be subject to less stringent environmental regulation, into areas served by Power’s generation assets. Further, some of the market-based mechanisms in which Power participates, including BGS auctions and the RPM capacity payments, are at times the subject of review or discussion by some of the participants in the New Jersey and federal regulatory and political arenas, including FERC and the BPU, and the PJM market monitor. Accordingly, Power can provide no assurance that any or all of these mechanisms will continue to exist in their current form. For additional information, see Item 5. Other Information—Regulatory Issues. In addition, Power must be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements, including legislation, regulation and voluntary restrictions that address: • the control of carbon dioxide emissions to reduce the effects of global climate change and greenhouse gas; • other emissions such as NOx, SO2 and mercury; and • the potential need for significant upgrades to existing water intake structures and cooling systems at its larger once-through cooled plants, including Salem, Hudson, Mercer, Sewaren, New Haven and Bridgeport. Power recently completed two projects to increase the generating capacity of its Hope Creek and Salem Unit 2 facilities and has several other projects included in its forecasted capital expenditures. Power has two large environmental back-end technology projects underway at its Mercer and Hudson coal plants scheduled to be completed by the end of 2010. Power is focused on completing these projects on schedule and within the established budgets, but faces many risks typically involved in managing large construction projects. 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. Power estimates the cost of these generating units to be $130 million to $140 million. Power has initiated planning activities with respect to the construction of new gas-fired peaking capacity. Power’s final decision whether or not to proceed with construction of these units would depend on numerous items, including estimated capital and interconnection costs, available siting and Power’s ability to meet environmental permitting requirements. Power is also currently exploring the potential to build new nuclear generation and in addition may also seek growth from acquisition opportunities. PSE&G PSE&G’s results primarily depend on the treatment of the various rate and other issues by the BPU and FERC, as well as other state and federal regulatory agencies. Therefore, PSE&G’s success will depend on its ability to: • attain an adequate return on the investments it plans to make in its electric and gas transmission and distribution system; • continue cost containment initiatives; • maintain system reliability and safety levels; and • continue recovery of the regulatory assets it has deferred. PSE&G’s results will also be impacted by the level of recovery of distribution revenues in light of customer demand and conservation efforts. 51
As noted previously, PSE&G has recently filed a petition with FERC to implement a cost of service formula rate for its existing and future transmission investments. If approved, this forward-looking formula rate mechanism would allow PSE&G to update its transmission rates annually based on forecasted Operation and Maintenance Expense (O&M) and capital expenditures for the coming year, with no lag of recovery, and would provide for a true-up to actual expenditures in the subsequent year. Moreover, PSE&G has made a request to the BPU for an increase in annual BGSS revenues of $376 million to be effective October 1, 2008. Under the terms of the settlement of PSE&G’s most recent electric and gas base rate cases, it is required to file joint electric and gas petitions for future base rate increases and no base rate changes may become effective before November 15, 2009. PSE&G has also proposed various initiatives to meet energy goals under the EMP. As discussed above, PSE&G has received BPU approval allowing PSE&G to invest approximately $105 million over two years to help finance the installation of solar energy systems throughout its service area. PSE&G will be allowed to earn a return on and of its investment and partially recover its administrative costs to implement the Solar Energy Program through regulated rates. The program will support 30 MW of solar power in the next two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard requirements of 57 MW in PSE&G’s service area by May 2009 and May 2010. In order to meet the growing demand for electricity in the region in a safe, reliable and economically efficient manner, PJM has identified the need for several transmission projects as part of its Regional Transmission Expansion Plan (RTEP). One project is the Susquehanna-Roseland 500 kV transmission project that was approved by PJM and is currently in the permitting and siting phase with construction expected to begin in the spring of 2009 to meet the 2012 in-service date. PSE&G has the responsibility to build and own a portion of this transmission line and has been granted incentive rate treatment for this project. PSE&G will also be responsible for constructing and owning a portion of the Mid-Atlantic Pathway Project (MAPP), another 500 kV transmission line. The in-service date has not been finalized. There are several other 500 kV transmission projects, as well as 230 kV transmission project options, actively under consideration by PJM to address future reliability criteria violations in the PJM region. These projects have not yet been approved by PJM. For additional information, see Item 5. Other Information. Energy Holdings Energy Holdings’ earnings are primarily comprised of the results of operations at Global and Resources. As a merchant generation business with a load-following asset profile, Global’s largest domestic investment is in two generating facilities in Texas, and, as such, its success will be driven by the efficient operation of those plants and by changes in market conditions, particularly projected market heat rates and weather. Resources maintains a portfolio of investments which is designed to provide a fixed rate of return. However, its future performance is subject to tax risks, such as the impacts of changes to uncertain tax positions as determined by changes in substantive tax law and tax audit results, including resolution of significant tax audit claims associated with its leveraged lease transactions. See Note 5. Commitments and Contingent Liabilities for further discussion. In March 2008, a subsidiary of Global, together with Winergy Power Holdings, an unaffiliated New York-based private developer, submitted a proposal to the New Jersey Office of Clean Energy (OCE) to build a 350 MW wind farm approximately 16 miles off the shore of southern New Jersey. If the proposal is accepted by the OCE, subject to required permits, feasibility and environmental studies, financing and other conditions, the wind farm could be fully operational in 2013. PSEG, Power and PSE&G PSEG expects that continued strong cash from operations will be sufficient to fund dividends and support its capital expenditure program. This operating cash flow is expected to be generated primarily at Power with modest contributions from PSE&G and Energy Holdings. When combined with funds from asset sales and potential additional financing capacity, PSEG expects that it could have $2.5 billion of discretionary cash through the end of 2011 for incremental growth initiatives or to pursue its stock repurchase program. This discretionary cash currently assumes: • Potential payments totaling approximately $900 million to $950 million to address significant income tax claims related to certain leveraged lease transactions at Energy Holdings, discussed in Note 5. 52
Commitments and Contingent Liabilities, the amount of which is consistent with reserves taken under FIN 48. The overall outcome and timing of such potential cash payments cannot be predicted. • A forecast that includes greater levels of growth capital than included in the capital expenditures forecast included in the 2007 Form 10-K, but which remains under review as PSEG, Power and PSE&G continue to assess growth initiatives. There are several factors that could impact the amount of discretionary cash that at any point in time may actually be available, including: • the continued liquidity and strength of energy and capacity markets; • the cash required to resolve the significant income tax claims discussed above; • the ability to successfully deploy discretionary capital for growth; and • the continued availability of the capital markets to PSEG and its subsidiaries and the ability to finance the growth of their businesses. The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and six months ended June 30, 2008 and 2007 are presented below: Earnings (Losses) Quarters Ended Six Months Ended 2008 2007 2008 2007 (Millions) Power $ 240 $ 187 $ 515 $ 406 PSE&G 52 63 189 195 Global 18 33 33 6 Resources (A). (470 ) 15 (456 ) 31 Other (B) (6 ) (17 ) (13 ) (36 ) PSEG (Loss) Income from Continuing Operations (166 ) 281 268 602 Income (Loss) from Discontinued Operations (C) 16 (6 ) 30 2 PSEG Net (Loss) Income $ (150 ) $ 275 $ 298 $ 604 Earnings (Loss) Per Share (Diluted) Quarters Ended Six Months Ended June 30, 2008 2007 2008 2007 PSEG (Loss) Income from Continuing Operations $ (0.32 ) $ 0.55 $ 0.53 $ 1.19 Income (Loss) from Discontinued Operations (C) 0.03 (0.01 ) 0.06 0.00 PSEG Net (Loss) Income $ (0.29 ) $ 0.54 $ 0.59 $ 1.19
June 30,
June 30,
June 30,
| ||||||||||||||||||||
(A) |
| In the second quarter of 2008, Resources recorded after-tax charges of $490 million related to the IRS’ disallowance of deductions taken by taxpayers in prior years’ tax filings associated with certain types of leveraged lease transactions. As of June 30, 2008, Resources had a total gross investment of $1 billion in such transactions. See Note 5. Commitments and Contingent Liabilities for additional information. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Other activities include non-segment amounts of PSEG (as parent company) and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain administrative and general expenses at PSEG and Energy Holdings (as parent companies). | ||||||||||||||||||
| ||||||||||||||||||||
(C) |
| Includes Discontinued Operations of the SAESA Group in 2008 and 2007 and of Electroandes and Lawrenceburg in 2007. See Note 3. Discontinued Operations and Dispositions. | ||||||||||||||||||
As shown in the table above, PSEG had a Loss from Continuing Operations of $(166) million, or $(0.32) per share for the quarter ended June 30, 2008, as compared to Income from Continuing Operations of $281 million, or $0.55 per share for the same quarter in 2007. PSEG had a Net Loss for the quarter ended June 30, 2008 of $(150) million or $(0.29) per share, as compared to Net Income of $275 million, or $0.54 per share for the second quarter of 2007.
53
PSEG had Income from Continuing Operations of $268 million, or $0.53 per share for the six months ended June 30, 2008, as compared to $602 million, or $1.19 per share for the same period in 2007. PSEG’s Net Income for the six months ended June 30, 2008 was $298 million or $0.59 per share, as compared to Net Income of $604 million, or $1.19 per share for the same period in 2007. The changes in PSEG’s (Loss) Income from Continuing Operations and Net (Loss) Income primarily relate to changes in Net Income for Power, PSE&G and Energy Holdings, discussed below. PSEG For the Quarters Increase % For the Six Months Increase % 2008 2007 2008 2007 (Millions) (Millions) Operating Revenues $ 2,561 $ 2,707 $ (146 ) (5 ) $ 6,364 $ 6,215 $ 149 2 Energy Costs $ 1,540 $ 1,320 $ 220 17 $ 3,664 $ 3,297 $ 367 11 Operation and Maintenance $ 623 $ 578 $ 45 8 $ 1,254 $ 1,173 $ 81 7 Depreciation and Amortization $ 193 $ 191 $ 2 1 $ 387 $ 383 $ 4 1 Income from Equity Method Investments. $ 8 $ 26 $ (18 ) (69 ) $ 20 $ 53 $ (33 ) (62 ) Other Income and Deductions. $ 11 $ 21 $ (10 ) (48 ) $ 10 $ 57 $ (47 ) (82 ) Interest Expense $ (147 ) $ (182 ) $ (35 ) (19 ) $ (300 ) $ (364 ) $ (64 ) (18 ) Income Tax Expense $ (214 ) $ (171 ) $ 43 25 $ (448 ) $ (431 ) $ 17 4 Income (Loss) from Discontinued Operations $ 16 $ (6 ) $ 22 N/A $ 30 $ 2 $ 28 N/A PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, Power, PSE&G and Energy Holdings, excluding changes related to intercompany transactions, which are eliminated in consolidation, and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 14. Related-Party Transactions. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for Power, PSE&G and Energy Holdings that follow. Power For the quarter ended June 30, 2008, Power had Net Income of $240 million, an increase of $56 million as compared to the same period in the prior year. For the six months ended June 30, 2008, Power had Net Income of $515 million, an increase of $118 million as compared to the same period in the prior year. The primary reasons for the increases for the quarter and six month periods ended June 30, 2008 as compared to the comparable periods in 2007 were higher prices and sales volumes in PJM and higher prices realized from recontracted BGS contracts. The increases were somewhat offset by higher generation costs, largely due to higher prices for natural gas, higher Operation and Maintenance costs related to outages at certain of Fossil’s facilities and the recognition in 2008 of other-than-temporary impairments (OTTI) on certain securities in the Nuclear Decommissioning Trust (NDT) Funds in excess of those recognized in the same periods in 2007. In addition, Net Income for the three month periods included the effects of MTM gains of $27 million, after-tax, in 2008 as compared to $9 million of losses, after-tax, in 2007. Net Income for the six month periods included the effects of MTM gains of $30 million, after-tax, in 2008 as compared to $10 million, after-tax, of losses in 2007. The detail for the variances is discussed below: For the Quarters Increase % For the Six Months Increase % 2008 2007 2008 2007 (Millions) (Millions) Operating Revenues $ 1,623 $ 1,305 $ 318 24 $ 3,998 $ 3,454 $ 544 16 Energy Costs $ 867 $ 694 $ 173 25 $ 2,456 $ 2,182 $ 274 13 Operation and Maintenance $ 275 $ 241 $ 34 14 $ 514 $ 479 $ 35 7 Depreciation and Amortization $ 41 $ 34 $ 7 21 $ 79 $ 68 $ 11 16 Other Income and Deductions $ 6 $ 21 $ (15 ) (71 ) $ 1 $ 43 $ (42 ) (98 ) Interest Expense $ (41 ) $ (39 ) $ 2 5 $ (83 ) $ (76 ) $ 7 9 Income Tax Expense $ (165 ) $ (131 ) $ 34 26 $ (352 ) $ (286 ) $ 66 23 Loss from Discontinued Operations, net of tax benefit $ — $ (3 ) $ 3 100 $ — $ (9 ) $ 9 100 54
Ended June 30,
(Decrease)
Ended June 30,
(Decrease)
Ended June 30,
(Decrease)
Ended June 30,
(Decrease)
Operating Revenues The $318 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was due to increases of $277 million in generation revenues, $26 million in gas revenues and $15 million in trading revenues. The $544 million increase for the six months ended June 30, 2008, as compared to the same period in 2007, was due to increases of $504 million in generation revenues, $20 million in gas supply revenues and $20 million in trading revenues. Generation Generation revenues increased $277 million for the quarter ended June 30, 2008, as compared to the same period in 2007, due to an increase of $178 million primarily resulting from a higher volume of generation being sold at higher prices into PJM and an increase of $88 million mainly from higher prices on a higher volume of BGS-FP contracts. Also contributing to the increase was $32 million from higher capacity prices resulting from RPM in PJM. Generation revenues increased $504 million for the six months ended June 30, 2008, as compared to the same period in 2007, due to an increase of $312 million resulting from a higher volume of generation being sold at higher prices into PJM partially offset by losses of $54 million on financial hedging transactions at PJM. The increase was also due to $167 million from higher prices on BGS contracts. Also contributing to the increase was $87 million from higher capacity prices in PJM and New York. Gas Supply Gas supply revenues increased $26 million for the quarter ended June 30, 2008, as compared to the same period in 2007, principally due to a net increase of $32 million from sales under the BGSS contract, comprised of $68 million from higher prices partly offset by lower sales volumes of $36 million resulting from customer conservation and from milder average temperatures in 2008. The increase was also due to $10 million from sales to third party customers. These increases were partly offset by $16 million of higher losses on financial hedging transactions in 2008 as compared to the same period in 2007. Gas supply revenues increased $20 million for the six months ended June 30, 2008, as compared to the same period in 2007, principally due to a net increase of $35 million from sales under the BGSS contract, comprised of $107 million from higher prices partly offset by lower sales volumes of $72 million. Higher prices on sales to third party customers partly offset by reduced sales volumes also contributed $35 million to the increase. These increases were partially offset by $50 million in lower net gains on financial hedging transactions in 2008 as compared to the first half of 2007. Trading Revenues Trading revenues increased $15 million and $20 million for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, due primarily to gains on electric and firm transmission rights contracts. Operating Expenses Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as energy purchased in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs increased $173 million for the quarter ended June 30, 2008, as compared to the same period in 2007. Generation costs increased $134 million, reflecting an increase of $196 million mainly due to higher prices and higher volumes of natural gas used for fuel, as certain gas-fired units ran more frequently in 2008. The increase was somewhat offset by net gains of $68 million from financial hedging transactions, primarily related to contracts to purchase gas. Gas costs for BGSS increased $39 million, reflecting a net increase of $27 million due to higher inventory costs of $63 million partly offset by $36 million due to a reduced volume of gas sold to satisfy Power’s obligations under the BGSS contract and a net increase of $12 million on sales to third party customers due primarily to higher inventory costs. Energy Costs increased $274 million for the six months ended June 30, 2008, as compared to the same period in 2007. Generation costs increased $228 million, of which $305 million was due to higher fuel costs 55
related to higher prices and volumes of natural gas and coal. This increase was partly offset by net gains of $82 million from financial hedging transactions, mainly related to contracts to purchase gas. Gas costs increased $46 million, reflecting net increases of $20 million and $40 million related to Power’s obligations under the BGSS contract and sales to third party customers, respectively, reflecting higher inventory costs partially offset by reduced volumes. These increases were partially offset by a reduction of $15 million in losses on financial hedging transactions in 2008 as compared to the same period in 2007. Operation and Maintenance Operation and Maintenance expense increased $34 million for the quarter ended June 30, 2008, as compared to the same period in 2007, due to an increase at Fossil of $32 million, primarily related to outages at its Hudson, Linden and Bridgeport facilities. Operation and Maintenance expense increased $35 million for the six months ended June 30, 2008, as compared to the same period in 2007, primarily due to a net increase at Fossil of $22 million due to the outages in 2008 at the Hudson, Linden and Bridgeport facilities partially offset by the absence of maintenance costs incurred in 2007 for planned outages at certain other fossil stations. In addition, there was an increase of $8 million at Nuclear related to a planned outage at the Salem station in 2008. Depreciation and Amortization The $7 million and $11 million increases for the quarter and six month periods ended June 30, 2008, respectively, as compared to the same periods in 2007, were primarily due to a larger depreciable nuclear and fossil asset base in 2008. Of the increases, $2 million for the second quarter and $4 million for the first half of 2008 were attributable to depreciation of pollution-control equipment being placed into service on January 1, 2008 at Power’s coal-fired Bridgeport, Connecticut generating facility and $1 million was due to depreciation of the Salem 2 steam generator replacement being placed into service in May 2008. Other Income and Deductions Other Income and Deductions decreased $15 million for the quarter ended June 30, 2008, as compared to the same period in 2007. OTTI recognized on certain securities in the NDT Funds increased $19 million from $14 million in the second quarter of 2007 to $33 million in the second quarter of 2008, reflecting difficult market conditions in 2008. In addition, interest income received from PSEG decreased by $7 million due to a change in the short-term funding positions. These decreases were partially offset by an increase of $12 million from net gains related to the NDT Funds. Other Income and Deductions decreased $42 million for the six months ended June 30, 2008, as compared to the same period in 2007, as a result of an increase in OTTI of $47 million and lower interest income of $9 million from PSEG partially offset by a net increase of $12 million from net realized gains related to the NDT Funds. Interest Expense Interest Expense increased $7 million for the six months ended June 30, 2008, as compared to the same period in 2007, due primarily to the reclassification in 2007 of Interest Expense to Discontinued Operations of the Lawrenceburg facility, which was sold in May 2007, partially offset by higher capitalized interest costs of $7 million in 2008 related to various fossil and nuclear capital projects in process. Income Taxes Income Taxes increased $34 million and $66 million for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, primarily due to higher pre-tax income. Loss from Discontinued Operations, net of tax In May 2007, Power completed the sale of its Lawrenceburg generation facility. The sale price for the facility and inventory was $325 million. The transaction resulted in an after-tax charge to Power’s earnings of $208 million and was reflected as a charge to Discontinued Operations in the fourth quarter of 2006. Losses from Discontinued Operations of Lawrenceburg were $3 million and $9 million, respectively, for the quarter and six months ended June 30, 2007. 56
PSE&G For the quarter ended June 30, 2008, PSE&G had Net Income of $52 million, a decrease of $11 million as compared to the quarter ended June 30, 2007. For the year ended June 30, 2008, PSE&G had Net Income of $189 million, a decrease of $6 million as compared to the quarter ended June 30, 2007. The detail for the variances is discussed below: For the Quarters Increase % For the Six Months Increase % 2008 2007 2008 2007 (Millions) (Millions) Operating Revenues $ 1,858 $ 1,748 $ 110 6 $ 4,476 $ 4,234 $ 242 6 Energy Costs $ 1,213 $ 1,077 $ 136 13 $ 3,006 $ 2,742 $ 264 10 Operation and Maintenance $ 320 $ 314 $ 6 2 $ 680 $ 639 $ 41 6 Depreciation and Amortization $ 139 $ 143 $ (4 ) (3 ) $ 282 $ 288 $ (6 ) (2 ) Other Income and Deductions $ 2 $ 4 $ (2 ) (50 ) $ 6 $ 8 $ (2 ) (25 ) Interest Expense $ (81 ) $ (84 ) $ (3 ) (4 ) $ (162 ) $ (165 ) $ (3 ) (2 ) Income Tax Expense. $ (28 ) $ (41 ) $ (13 ) (32 ) $ (93 ) $ (140 ) $ (47 ) (34 ) Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services. PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial (C&I) customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings. PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply prices are set based on the results of these auctions for residential and smaller C&I customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger C&I customers is provided at a rate principally based on the hourly PJM real-time energy price. Customers may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric suppliers, and the majority of the customers subject to hourly pricing are currently receiving electric supply from third-party suppliers. Any differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the amounts of electric commodity revenue collected from customers is deferred and collected or returned to customers in subsequent months. The $110 million increase in operating revenues for the quarter ended June 30, 2008, as compared to the same period in 2007, was due to an increase of $134 million in commodity revenues offset by decreases of $21 million in delivery revenues and $3 million in other operating revenues, primarily related to appliance service contracts. The $242 million increase for the six months ended June 30, 2008, as compared to the same period in 2007, was due to increases of $262 million in commodity revenues offset by decreases of $16 million in delivery revenues, described below and $4 million in other operating revenues, primarily related to appliance service contracts. Commodity The $134 million increase in commodity-related revenues for the quarter ended June 30, 2008, as compared to 2007, was due to increases of $130 million and $4 million in electric and gas revenues, respectively. The electric increase was due to $91 million in higher BGS revenues (higher auction prices of $115 million offset by decreased volumes of $24 million) and $39 million in higher non-utility generation (NUG) revenues (higher prices of $36 million and $3 million in increased volumes). The gas increase was primarily due to $47 million in price variances for C&I customers offset by $43 million in lower volumes due to weather. Prices charged to C&I customers are market-based. 57
Ended June 30,
(Decrease)
Ended June 30,
(Decrease)
The $262 million increase in commodity related revenues for the six months ended June 30, 2087, as compared to the same period in 2007, was due to increases in electric revenues of $230 million and gas revenues of $32 million. The increase in electric revenues was primarily due to $192 million in higher BGS revenues (higher auction prices of $225 million offset by decreased sales of $33 million) and $55 million in higher NUG revenues (higher prices of $52 million and $3 million in increased volumes), offset by $17 million in lower non-utility generation clause (NGC) revenues. The increase in gas revenues was primarily due to $116 million in higher BGSS prices offset by $84 million in lower volumes due to weather. Delivery The $21 million decrease in delivery revenues for the quarter ended June 30, 2008, as compared to the same period in 2007, was due to decreases of $18 million in gas revenues and $3 million in electric revenues. The gas decrease was primarily due to $18 million in lower volumes primarily due to weather. The electric decrease was due primarily to $12 million in decreased volumes due to weather offset by $9 million in higher prices. The $16 million decrease in delivery revenues for the six months ended June 30, 2008, as compared to the same period in 2007, was due to a $33 million decrease in gas revenues offset by a $17 million increase in electric revenues. The gas decrease was due to $30 million in decreased sales primarily due to weather and $3 million due to the Societal Benefits Clause (SBC) rate decreases in March 2007. The electric increase was due primarily to $27 million for increased SBC rates offset by $14 million in decreased volumes due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses. Operating Expenses Energy Costs The $136 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was comprised of increases of $131 million and $5 million in electric and gas costs, respectively. The electric increase was due to $152 million or 20% in higher prices for BGS and NUG purchases and $5 million in increased NUG volumes offset by $26 million or 4% in lower volumes due to weather. The gas increase was caused by $52 million or 16% in higher BGSS prices offset by $47 million or 16% in lower volumes, primarily due to weather. The $264 million increase for the six months ended June 30, 2008, as compared to the same period in 2007, was comprised of increases of $231 million in electric costs and $33 million in gas costs. The increase in electric costs was primarily due to $260 million or 18% in higher prices for BGS and NUG purchases and $4 million in higher NUG volumes offset by $33 million or 3% in lower BGS volumes due to weather. The increase in gas costs was caused by an $86 million or 7% increase in higher prices offset by $53 million or 8% in lower volumes due to weather. Operation and Maintenance The $6 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was primarily due to $6 million in higher labor costs due to added headcount, pay increases and overtime related to storm work. The $41 million increase for the six months ended June 30, 2008, as compared to the same period in 2007, was due primarily to $23 million in increased amortization of deferred expenses, resulting primarily from an SBC rate increase in March 2007. Labor costs increased $11 million due to added headcount, pay increases and overtime related to storm work. Other increases included $2 million for advertising expense, $2 million for injuries and damages reserves, $1 million for property taxes and $1 million for bad debt expense. Depreciation and Amortization The $4 million decrease for the quarter ended June 30, 2008, as compared to the same period in 2007, was due primarily to a $3 million decrease in regulatory asset amortization, $2 million reduction in software amortization and a $2 million decrease in the amortization of U.S. Department of Energy (DOE) enrichment facility decommissioning costs. These decreases were offset by a $3 million increase due to increased plant in service. The $6 million decrease for the six months ended June 30, 2008, as compared to the same period in 2007, was due primarily to a $4 million decrease in Regulatory Asset amortization, a $4 million reduction in 58
software amortization and a $3 million decrease in the amortization of DOE enrichment facility decommissioning costs. These decreases were offset by a $5 million increase due to increased plant in service. Other Income and Deductions The $2 million decrease for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, were due primarily to decreased interest income on Rabbi Trust and Money Market investments. Income Taxes The $13 million decrease for the quarter ended June 30, 2008, as compared to the same period in 2007, was primarily due to $10 million on lower pre-tax income and $3 million in various tax adjustments. The $47 million decrease for the six months ended June 30, 2008, as compared to the same period in 2007, was primarily due to decreased taxes of $22 million on lower pre-tax income, a $22 million decrease related to a one-time remeasurement of the FIN 48 reserves resulting from an IRS approved refund claim at PSEG for earlier tax years and $3 million in various tax adjustments. Energy Holdings For the quarter ended June 30, 2008, Energy Holdings had a Net Loss of $(437) million, as compared to Net Income of $44 million for the same period in 2007. For the six months ended June 30, 2008, Energy Holdings had a Net Loss of $(395) million, as compared to Net Income of $47 million for the same period in 2007. The changes for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, were primarily due to recording a charge of $490 million (after tax) in the second quarter of 2008 associated with certain types of leveraged lease transactions at Resources. See Note 5. Commitments and Contingent Liabilities. Excluding the $490 million after-tax charge, earnings increased by $9 million and $48 million for the quarter and six months ended June 30, 2008, respectively, as compared to the same periods in 2007. The increases for the quarter and for the six months were primarily due to increased income from Global’s Texas facilities relating to spark spread (the difference between the market price of electricity and the costs of natural gas fuel), decreased interest expense due to lower debt balances as a result of asset sales in late 2007 that allowed for greater debt repayment and increased earnings at Bioenergie, Global’s subsidiary in Italy, where the San Marco facility did not operate during the first half of 2007. The detail for the variances is discussed below: For the Increase % For the Increase % 2008 2007 2008 2007 (Millions) (Millions) Operating Revenues. $ (229 ) $ 236 $ (465 ) N/A $ (87 ) $ 384 $ (471 ) N/A Energy Costs $ 151 $ 132 $ 19 14 $ 224 $ 228 $ (4 ) (2 ) Operation and Maintenance $ 36 $ 30 $ 6 20 $ 74 $ 68 $ 6 9 Depreciation and Amortization. $ 10 $ 10 $ — N/A $ 19 $ 20 $ (1 ) (5 ) Income from Equity Method Investments $ 8 $ 26 $ (18 ) (69 ) $ 20 $ 53 $ (33 ) (62 ) Other Income and Deductions $ 5 $ 3 $ 2 67 $ 8 $ 17 $ (9 ) (53 ) Interest Expense $ (19 ) $ (36 ) $ (17 ) (47 ) $ (43 ) $ (75 ) $ (32 ) (43 ) Income Tax Expense $ (21 ) $ (10 ) $ 11 N/A $ (6 ) $ (27 ) $ (21 ) (78 ) Income (Loss) from Discontinued Operations $ 16 $ (3 ) $ 19 N/A $ 30 $ 11 $ 19 N/A Operating Revenues The $465 million and $471 million decreases for the quarter and six months ended June 30, 2008, respectively, as compared to the same periods in 2007, were primarily the result of recording a $485 million (pre-tax) charge related to the IRS’ disallowance of deductions taken in prior years associated with certain types of leveraged lease transactions at Resources in June 2008. See Note 5. Commitments and Contingent Liabilities. Excluding the lease transaction charges, Operating Revenues increased by $20 million for the second quarter of 2008, as compared to the same period in 2007, primarily due to higher revenue from the Texas and 59
Quarters Ended
June 30,
(Decrease)
Six Months
Ended
June 30,
(Decrease)
Bioenergie assets. The increase at Texas was primarily due to higher 2008 prices partially offset by lower volumes and higher MTM losses. The San Marco plant did not operate during the first half of 2007. The increases were partially offset by lower lease revenue of $7 million at Resources. Excluding the lease transaction charges, Operating Revenues increased by $14 million for the six months ended June 30, 2008, as compared to the same period in 2007, primarily due to higher revenue from the Texas and Bioenergie assets. The increase at Texas was primarily due to higher 2008 prices partially offset by lower volumes and higher MTM losses. The San Marco plant did not operate during the first half of 2007. This was partially offset by lower lease revenues at Resources and the absence of a gain on the sale of Global’s interest in Tracy Biomass in January 2007. Operating Expenses Energy Costs The $19 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was primarily due to a $15 million increase at the Texas generation facilities, primarily due to higher prices, and a $4 million increase at Bioenergie with the San Marco facility being operational during 2008. The $15 million increase at the Texas generation facilities was primarily due to a $50 million price increase, partially offset by a $30 million decrease in MTM activity and a $6 million decrease in volume. The $4 million decrease for the six months ended June 30, 2008, as compared to the same periods in 2007, was primarily due to a $14 million decrease at the Texas generation facilities primarily due to MTM activity related to gas contracts in 2008 and a reduction in fuel consumption, partially offset by an increase in price and by a $10 million increase at Bioenergie. Operation and Maintenance The $6 million increases for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, were due primarily to an increase at the Texas generation facilities due to a scheduled maintenance outage, higher costs at Bioenergie, an increase in general and administrative expenses relating primarily to higher outside services at Global and additional severance and retention accruals. Depreciation and Amortization The $1 million decrease for the six months ended June 30, 2008, as compared to the same period in 2007, was due to lower depreciation at the Texas generation facilities. Income from Equity Method Investments The $18 million and the $33 million decreases for the quarter and six months ended June 30, 2008, as compared to the same periods in 2007, were primarily due to the absence of income from Global’s 50% ownership interest in the Chilean electric distributor, Chilquinta and Global’s 37.9% ownership interest in the Peruvian electric distributor, Luz Del Sur (LDS) which were sold in December 2007. Income from Chilquinta was $11 million and $18 million for the quarter and six months ended June 30, 2007, respectively. Income from LDS was $6 million and $13 million for the quarter and six months ended June 30, 2007, respectively. Other Income and Deductions The $2 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was primarily due to an increase in interest and dividend income. The $9 million decrease for the six months ended June 30, 2008, as compared to the same period in 2007, was primarily due to the absence of a $9 million pre-tax gain in the first quarter of 2007 relating to the receipt of an arbitration award from the Turkish government regarding the construction of a power plant in the Konya-Ilgin region of Turkey, partially offset by an increase in interest and dividend income. Interest Expense The $17 million and the $32 million decreases for the quarter and the six months ended June 30, 2008, as compared to the same periods in 2007, were primarily due to lower debt balances. See Note 8. Changes in Capitalization for more information. 60
Income Taxes The $11 million increase for the quarter ended June 30, 2008, as compared to the same period in 2007, was primarily due to a $16 million increase in taxes at Global due to higher pre-tax income combined with FIN 48 adjustments, partially offset by a $5 million decrease in taxes at Resources. The decrease at Resources was primarily due to an increase of $135 million under FIN 48 for the interest reserve related to the aforementioned leveraged lease transactions, which was more than offset by a $130 million reduction in taxes due to the charge against revenues related to such leases and a $10 million decrease attributable to current year state tax benefits and other FIN 48 adjustments. See Note 5. Commitments and Contingent Liabilities for a discussion of the Leveraged lease transactions, and the impact on Resources income taxes. The $21 million decrease for the six months ended June 30, 2008, as compared to the same period in 2007, was primarily due to an IRS-approved refund claim at PSEG for earlier tax years and FIN 48 adjustments. Income from Discontinued Operations, net of tax SAESA Group In December 2007, Global announced its plan to sell its investment in the SAESA Group of companies. As a result, operating results for the SAESA Group have been presented as Discontinued Operations. Income from Discontinued Operations related to the SAESA Group for each of the quarters ended June 30, 2008 and 2007 were $16 million and $11 million, respectively. Income from Discontinued Operations related to the SAESA Group for the six months ended June 30, 2008 and 2007 were $30 million and $25 million, respectively. See Note 3. Discontinued Operations and Dispositions for additional information. Electroandes In June 2007, Energy Holdings reclassified its investment in Electroandes to Discontinued Operations. In conjunction with the reclassification to Discontinued Operations, Global recorded a $19 million income tax expense in the second quarter of 2007 related to the discontinuation of applying APB 23, as the income generated by Electroandes was no longer expected to be indefinitely reinvested. Losses from Discontinued Operations for the quarter and six months ended June 30, 2007 were $14 million. On October 17, 2007, Global completed the sale of Electroandes for a total purchase price of $390 million, including the assumption of approximately $108 million of debt. See Note 3. Discontinued Operations and Dispositions for additional information. LIQUIDITY AND CAPITAL RESOURCES The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, Power, PSE&G and Energy Holdings. Operating Cash Flows PSEG For the six months ended June 30, 2008, PSEG’s operating cash flow decreased by $160 million from $784 million to $624 million, as compared to the same period in 2007, due to changes from its subsidiaries as discussed below. Power Power’s operating cash flow decreased $328 million from $794 million to $466 million for the six months ended June 30, 2008, as compared to the same period in 2007, primarily resulting from a $240 million greater increase in cash collateral requirements in the first six months of 2008 as compared to the same period in 2007 as well as the effect on fuel inventory levels of higher gas, coal and oil prices in 2008. PSE&G PSE&G’s operating cash flow increased $399 million from $(117) million to $282 million for the six months ended June 30, 2008, as compared to the same period in 2007. The increase was primarily due to a $170 million increase in cash collateral held by PSE&G, primarily under BGS contracts, a $116 million improvement in customer accounts receivable, and a $55 million increase in cash flow from deferred income 61
taxes. In the first half of 2008, PSE&G experienced a normal seasonal decline in the accounts receivable balance while in the comparable period in 2007 the cash collections from customers were lower due to very mild weather in December 2006. The increase in cash flow from deferred income taxes was a combination of a new benefit for bonus depreciation in 2008 and the absence of a tax adjustment paid in 2007. Energy Holdings Energy Holdings’ operating cash flow decreased $257 million from $139 million to $(118) million for the six months ended June 30, 2008, as compared to the same period in 2007. The decrease was mainly attributable to increased tax payments, primarily related to the sale of Chilquinta and LDS, combined with lower distributions from Global’s equity method investments for the six months ended June 30, 2008, as compared to the same period in 2007. Common Stock Dividends Dividend payments on common stock for the quarters ended June 30, 2008 and 2007 were $0.3225 and $0.2925 per share, respectively, and totaled $164 million and $148 million, respectively. Dividend payments on common stock for the six months ended June 30, 2008 and 2007 were $0.6450 and $0.5850 per share, respectively, and totaled $328 million and $296 million, respectively. On July 15, 2008, PSEG’s Board of Directors approved a common stock dividend of $0.3225 per share for the third quarter of 2008, reflecting an indicated annual dividend rate of $1.29 per share. PSEG expects to continue to pay cash dividends on its common stock; however, the declaration and payment of future dividends to holders of PSEG common stock will be at the discretion of the Board of Directors and will depend upon many factors, including PSEG’s financial condition, earnings, cash flows, capital requirements of its business, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant. Short-Term Liquidity PSEG, Power and PSE&G As of June 30, 2008, PSEG and its subsidiaries had the following committed credit facilities. Each of the facilities is restricted as to availability and use to the specific companies as listed below. PSEG, Power and PSE&G continually monitor their liquidity and seek to add capacity as needed to meet their liquidity requirements. In June 2008, PSEG, Power and PSE&G added capacity of $147 million, $175 million and $28 million, respectively. 62
Company Expiration Total Primary Usage Available (Millions) PSEG: 5-year Credit Facility (A) Dec 2012 $ 1,047 CP Support/ $ 839 $ 208 Bilateral Credit Facility (B) June 2009 $ 100 CP Support/ $ — $ 100 Uncommitted Bilateral Agreement N/A N/A Funding $ 85 N/A Power: 5-year Credit Facility (A) Dec 2012 $ 1,675 Funding/Letters $ 1,170 (C) $ 505 Bilateral Credit Facility (D) March 2009 $ 150 Funding/Letters $ 80 (C) $ 70 Bilateral Credit Facility (B) June 2009 $ 100 Funding/Letters $ — $ 100 Bilateral Credit Facility March 2010 $ 100 Funding/Letters $ 97 (C) $ 3 PSE&G: 5-year Credit Facility (A) June 2012 $ 628 CP Support/ $ 197 $ 431 Uncommitted Bilateral Agreement N/A N/A Funding $ 3 N/A Energy Holdings: 5-year Credit Facility June 2010 $ 150 Funding/Letters $ 14 $ 136
Date
Facility
Purpose
as of
June 30,
2008
Liquidity
as of
June 30,
2008
Funding/Letters
of Credit
Funding
of Credit
of Credit
of Credit
of Credit
Funding/Letters
of Credit
of Credit
| ||||||||||||||||||||
(A) |
| During June 2008, the credit facilities for PSEG, Power and PSE&G were increased by $47 million, $75 million and $28 million, respectively, when a new counterparty made a commitment to all three credit facilities. In 2012, the facilities will be reduced by these same incremental amounts. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| During June 2008, PSEG and Power each entered into these bilateral credit facilities. | ||||||||||||||||||
| ||||||||||||||||||||
(C) |
| These amounts relate to letters of credit outstanding. | ||||||||||||||||||
| ||||||||||||||||||||
(D) |
| Power had a $200 million bilateral credit facility that expired in March 2008. In April 2008, Power renewed the facility, reducing it to $150 million with the same counterparty on similar terms. | ||||||||||||||||||
Power
As of June 30, 2008, PSEG had loaned $400 million to Power.
During the quarter ended June 30, 2008, Power’s required margin postings for sales contracts entered into in the normal course of business increased significantly. The required margin postings will fluctuate based on volatility in commodity prices. Should commodity prices continue to rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are fulfilled, liquidity requirements are reduced.
In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio. As of June 30, 2008, Power believes it could obtain the liquidity required to meet its potential required posting of collateral which could result from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities for further information.
63
External Financings For information related to External Financings, see Note 8. Changes in Capitalization. Debt Covenants PSEG’s, Power’s and PSE&G’s respective credit agreements may contain maximum debt to total capitalization ratios and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, Power and PSE&G, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as financial performance or liquidity measures. PSEG Financial covenants contained in PSEG’s note purchase agreements related to the private placement of debt include a ratio of total debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans and certain letters of credit) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that such ratio not be more than 70.0%. As of June 30, 2008, PSEG’s ratio of debt to capitalization (as defined above) was 59.1%. PSEG’s credit facilities contain a similar but less restrictive financial covenant where total debt excludes letters of credit related to collateral postings and total capitalization excludes any impacts for Accumulated Other Comprehensive Income/Loss adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This covenant requires that such ratio not be more than 70.0%. As of June 30, 2008, PSEG’s ratio of debt to capitalization (as defined above) was 51.4%. Power Financial covenants contained in Power’s credit facilities include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of June 30, 2008, Power’s ratio of debt to total capitalization (as defined above) was 41.3%. PSE&G Financial covenants contained in PSE&G’s credit facility include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of June 30, 2008, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 46.5%. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2 to 1, and/or against retired Mortgage Bonds. As of June 30, 2008, PSE&G’s Mortgage coverage ratio was 4.1 to 1 and the Mortgage would permit up to $2.2 billion aggregate principal amount of new Mortgage Bonds to be issued against previous bondable additions and improvements to its property. Credit Ratings PSEG, Power and PSE&G If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, Power’s and PSE&G’s securities and serve to materially increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so 64
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 June 2008, Moody’s affirmed the rating of Energy Holdings and changed the ratings outlook to Stable from Negative. In July 2008, Moody’s affirmed the ratings of PSEG and PSE&G and changed the ratings outlook of both companies to Stable from Negative. The rating and outlook of Power remained unchanged. 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. | ||||||||||||||||||
Other Comprehensive Income
PSEG, Power and PSE&G
For information related to Other Comprehensive Income/Loss, see Note 7. Comprehensive Income (Loss), Net of Tax.
PSEG, Power and PSE&G
It is expected that the majority of funding for capital requirements of Power and PSE&G will come from their respective internally generated funds. The balance will be provided by the issuance of debt at the respective subsidiary or project level and by equity contributions from PSEG.
Power
During the six months ended June 30, 2008, Power made $353 million of capital expenditures (excluding $31 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 5. Commitments and Contingent Liabilities.
PSE&G
During the six months ended June 30, 2008, PSE&G made $345 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $345 million does not include expenditures for cost of removal, net of salvage, of $20 million, which are included in operating cash flows.
PSEG, Power and PSE&G
For information related to recent accounting matters, see Note 2. Recent Accounting Standards.
65
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES PSEG, Power and PSE&G The market risk inherent in PSEG’s, Power’s and PSE&G’s market-risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, Power and PSE&G have a Risk Management Committee comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Additionally, PSEG, Power and PSE&G are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG’s and its subsidiaries’ Condensed Consolidated Financial Statements. Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, Power and PSE&G for the year ended December 31, 2007 or Quarterly Reports on Form 10-Q for the quarter ended March 31, 2008. Commodity Contracts The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity. Normal Operations and Hedging Activities Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors. Under SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Loss, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings. Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement. Trading Power maintains a strategy of entering into positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in earnings. 66
ABOUT MARKET RISK
Value-at-Risk (VaR) Models Power Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses. Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR. The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non- trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio. Higher market prices and volatilities have lead to a higher non-trading VaR as compared to June 30, 2007 and December 31, 2007. As of June 30, 2008, trading VaR was $2 million and as of December 31, 2007, trading VaR was less than $1 million. Trading VaR Non-Trading (Millions) For the Quarter Ended June 30, 2008 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End $ 2 $ 64 Average for the Period $ 1 $ 70 High $ 3 $ 84 Low $ — * $ 60 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End $ 3 $ 100 Average for the Period $ 2 $ 110 High $ 4 $ 131 Low $ — * $ 94
MTM VaR
| ||||||||||||||||||||
* |
| less than $1 million | ||||||||||||||||||
Other Supplemental Information Regarding Market Risk
Power
The following tables describe the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and six months ended June 30, 2008. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in these tables highlight, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. For additional information, see Note 6. Financial Risk Management Activities.
67
Operating Revenues
For the Quarter Ended June 30, 2008
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Position
$
(9
)
$
18
$
9
Realization at Settlement of Contracts
—
(13
)
(13
)
Total Change in Unrealized Fair Value
(9
)
5
(4
)
Realized Net Settlement of Transactions Subject to MTM
—
13
13
Net MTM Gains
(9
)
18
9
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications
1,614
—
1,614
Total Operating Revenues
$
1,605
$
18
$
1,623
Operating Revenues
For the Six Months Ended June 30, 2008
|
|
|
|
|
|
| |||||||||||||||
| Normal | Trading | Total | ||||||||||||||||||
| (Millions) | ||||||||||||||||||||
MTM Activities: |
|
|
|
|
|
| |||||||||||||||
Unrealized MTM Gains (Losses) |
|
|
|
|
|
| |||||||||||||||
Changes in Fair Value of Open Position |
| $ |
| 5 |
| $ |
| 20 |
| $ |
| 25 | |||||||||
Realization at Settlement of Contracts |
| (1 | ) |
|
| (15 | ) |
|
| (16 | ) |
| |||||||||
|
|
|
|
|
|
| |||||||||||||||
Total Change in Unrealized Fair Value |
| 4 |
| 5 |
| 9 | |||||||||||||||
Realized Net Settlement of Transactions Subject to MTM |
| 1 |
| 15 |
| 16 | |||||||||||||||
|
|
|
|
|
|
| |||||||||||||||
Net MTM Gains |
| 5 |
| 20 |
| 25 | |||||||||||||||
Accrual Activities: |
|
|
|
|
|
| |||||||||||||||
Accrual Activities—Revenue, Including Hedge Reclassifications |
| 3,973 |
| — |
| 3,973 | |||||||||||||||
|
|
|
|
|
|
| |||||||||||||||
Total Operating Revenues |
| $ |
| 3,978 |
| $ |
| 20 |
| $ |
| 3,998 | |||||||||
|
|
|
|
|
|
| |||||||||||||||
| ||||||||||||||||||||
(A) |
| Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets. | ||||||||||||||||||
68
The following table indicates Power’s energy contracts, including Power’s hedging activity related to ABT and derivative instruments that qualify for hedge accounting under SFAS 133. This table and the one that follows present amounts segregated by portfolio that are then netted for those counterparties with whom Power has the right to offset and therefore, are not necessarily indicative of amounts presented on the Condensed Consolidated Balance Sheets. The balances with counterparties with whom Power has master netting agreements may also be offset against collateral amounts with those counterparties. As of June 30, 2008, $418 million of cash collateral was offset against a Net Derivative Contract Liability of $1,071 million. This resulted in a Net Derivative Contract Liability of $653 million as presented on the Condensed Consolidated Balance Sheet. Energy Contract Net Assets/Liabilities
As of June 30, 2008
Normal Operations
and Hedging
Trading
Total
(Millions)
MTM Energy Assets
Current Assets
$
300
$
88
$
388
Noncurrent Assets
23
30
53
Total MTM Energy Assets
323
118
441
MTM Energy Liabilities
Current Liabilities
$
(796
)
$
(33
)
$
(829
)
Noncurrent Liabilities
(655
)
(28
)
(683
)
Total MTM Energy Liabilities
(1,451
)
(61
)
(1,512
)
Total MTM Energy Contract Net (Liabilities) Assets
$
(1,128
)
$
57
$
(1,071
)
The following table presents the maturity of net fair value of MTM energy contracts.
Maturity of Net Fair Value of MTM Energy Trading Contracts
As of June 30, 2008
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Maturities within | |||||||||||||||||||||||||||
2008 | 2009 | 2010-2012 | Total | |||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||
Trading |
| $ |
| 46 |
| $ |
| 12 |
| $ |
| (1 | ) |
|
| $ |
| 57 | ||||||||||
Normal Operations and Hedging |
| (231 | ) |
|
| (594 | ) |
|
| (303 | ) |
|
| (1,128 | ) |
| ||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Total Net Unrealized Losses on MTM Contracts |
| $ |
| (185 | ) |
|
| $ |
| (582 | ) |
|
| $ |
| (304 | ) |
|
| $ |
| (1,071 | ) |
| ||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
69
Global The following table describes the drivers of Global’s marketing activities and Operating Revenues included in PSEG’s Condensed Consolidated Statement of Operations for the quarter and six months ended June 30, 2008. Normal operations and hedging activities represent the marketing of electricity available from Global’s owned generation sold into the market. Activities accounted for under the accrual method account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. Operating Revenues Normal Operations (Millions) MTM Activities: Unrealized MTM Losses Changes in Fair Value of Open Position $ (20 ) Realization at Settlement of Contracts — Total Change in Unrealized Fair Value (20 ) Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications 246 Total Operating Revenues $ 226 Operating Revenues Normal Operations (Millions) MTM Activities: Unrealized MTM Losses Changes in Fair Value of Open Position $ (17 ) Realization at Settlement of Contracts — Total Change in Unrealized Fair Value (17 ) Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications 351 Total Operating Revenues $ 334
For the Quarter Ended June 30, 2008
and Hedging (A)
For the Six Months Ended June 30, 2008
and Hedging (A)
| ||||||||||||||||||||
(A) |
| Includes derivative contracts that Global enters into to hedge anticipated exposures related to its owned and contracted generation supply. | ||||||||||||||||||
70
The following table indicates Global’s energy contract net assets. Energy Contract Net Assets/Liabilities
As of June 30, 2008
Normal Operations
and Hedging
(Millions)
MTM Energy Assets
Current Assets
$
21
Noncurrent Assets
32
Total MTM Energy Assets
53
MTM Energy Liabilities
Current Liabilities
$
41
Noncurrent Liabilities
—
Total MTM Energy Liabilities
41
Total MTM Energy Contract Net Assets
$
12
The following table presents the maturity of net fair value of MTM energy contracts.
Maturity of Net Fair Value of MTM Energy Contracts
As of June 30, 2008
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Maturities within | |||||||||||||||||||||||||||
2008 | 2009 | 2010- | Total | |||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||
Total Net Unrealized (Losses) Gains on MTM Contracts |
| $ |
| (32 | ) |
|
| $ |
| 23 |
| $ |
| 21 |
| $ |
| 12 | ||||||||||
Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate.
PSEG and Power
The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG and Power are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses, net of taxes that are expected to be reclassified out of Accumulated Other Comprehensive Loss and into earnings over the next twelve months.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of June 30, 2008
|
|
|
|
| ||||||||||
| Accumulated Other | Portion Expected | ||||||||||||
| (Millions) | |||||||||||||
Commodities |
| $ |
| (870 | ) |
|
| $ |
| (478 | ) |
| ||
Interest Rates |
| (8 | ) |
|
| (4 | ) |
| ||||||
|
|
|
|
| ||||||||||
Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss |
| $ |
| (878 | ) |
|
| $ |
| (482 | ) |
| ||
|
|
|
|
| ||||||||||
71
Power Credit Risk The following table provides information on Power’s credit exposure, net of collateral, as of June 30, 2008. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. Schedule of Credit Risk Exposure on Energy Contracts Net Assets Rating Current Securities Net Number of Net (Millions) (Millions) Investment Grade—External Rating $ 322 $ 15 $ 307 1 (A) $ 94 Non-Investment Grade—External Rating 466 — 466 2 (B) 466 Investment Grade—No External Rating — — — — — Non-Investment Grade—No External Rating 56 1 55 — — Total $ 844 $ 16 $ 828 3 $ 560
As of June 30, 2008
Exposure
Held as
Collateral
Exposure
Counterparties
>10%
Exposure of
Counterparties
>10%
| ||||||||||||||||||||
(A) |
| PSE&G is a counterparty with net exposure of $94 million. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Credit exposure with non-investment grade counterparties is with two coal suppliers to Power. Therefore, this exposure relates to the risk of a counterparty non-performing under its obligations rather than payment risk. Coal prices have risen sharply since the beginning of 2008. | ||||||||||||||||||
The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure. As of June 30, 2008, Power had 133 active counterparties.
ITEM 4. CONTROLS AND PROCEDURES
PSEG, Power and PSE&G
Disclosure Controls and Procedures
PSEG, Power and PSE&G have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act) to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported 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. PSEG, Power and PSE&G have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that 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
PSEG, Power and PSE&G continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2008 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
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PSEG, Power and PSE&G PSEG, Power and PSE&G are parties to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2007 Annual Reports on Form 10-K of PSEG, Power and PSE&G and Item 1 of Part II of the respective Quarterly Reports on Form 10-Q of PSEG, Power and PSE&G for the quarter ended March 31, 2008, see Note 5. Commitments and Contingent Liabilities and Item 5. Other Information, Regulatory Issues. 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, 2007 and Quarterly Reports on Form 10-Q for the quarter ended March 31, 2008. 2007 Form 10-K, Page 35 and March 31, 2008 Quarterly Report on Form 10-Q. We may be adversely affected by changes in energy deregulation policies, including market design rules. The energy industry continues to experience significant change. Our business has been impacted by rules established that create locational capacity markets in each of PJM, New England and New York. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. While the existence of these rules has had a positive impact on Power’s revenues, as its generation in PJM and New England is located in constrained areas, both PJM’s and New England’s locational capacity market design rules have been challenged in court. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows. In May 2008, several state commissions, customer groups and certain federal agencies filed a complaint with FERC against PJM with respect to its RPM. In July 2008, Power and PSE&G filed a brief with the United States Court of Appeals for the District of Columbia Circuit due to concerns regarding the manner in which the Cost of New Entry (CONE) under RPM is calculated. Other petitioners, including the BPU, also filed briefs. For additional information on Capacity Market Issues see Item 5. Other Information. 2007 Form 10-K, Page 37 and March 31, 2008 Quarterly Report on Form 10-Q. Certain of our leveraged lease transactions at Resources may be successfully challenged by the IRS, which would have a material adverse effect on our taxes, operating results and cash flows. The IRS has disallowed all deductions associated with certain lease transactions that are similar to a type that the IRS publicly announced its intention to challenge, for tax years 1997 through 2000, and 2001 through 2003. As of June 30, 2008 and December 31, 2007, Resources’ total gross investment in such transactions was $1 billion and $1.5 billion, respectively. There are several tax cases involving other taxpayers with similar leverage lease investments that are pending. To date, three cases have been decided at the trial court level, two of which were decided in favor of the government. An appeal of one of these decisions was recently affirmed. The third case involves a jury verdict that is currently being challenged by both parties on inconsistency grounds. PSEG believes that its leasing transactions are fully consistent with Resources’ long-standing business model and its focus on energy-related assets of the type which PSEG has traditionally owned and operated. Based on the status of discussions with the IRS, and considering developments in other cases,PSEG currently anticipates that it will pay $300 million to $350 million in taxes, interest and penalties claimed by the IRS for the 1997–2000 audit cycle later in 2008, and subsequently commence litigation to recover a refund. If the IRS’ disallowance of tax benefits associated with all of these lease transactions was sustained, approximately $1,166 million would become currently payable as of June 30, 2008. This is composed of $957 73
million of deferred tax liabilities that have been recorded under leveraged lease accounting through June 30, 2008 and cumulative interest on this deficiency of $209 million, after-tax. In addition, as of June 30, 2008, penalties of $147 million have been proposed by the IRS. Interest and penalties grow at the rate of $15 million per quarter. In December 2007, PSEG deposited $100 million with the IRS to defray potential interest costs associated with this disputed tax liability. In the event PSEG is successful in its defense of its position, the deposit is fully refundable with interest. A resolution of this matter, consistent with the reserves established under FIN 48, could result in additional tax and interest payments approximating $900 million to $950 million, including the amounts for the 1997–2000 audit cycle discussed above. Certain information reported under the 2007 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2007 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarter ended March 31, 2008. References are to the related pages on the Form 10-K or March 31, 2008 Form 10-Q as printed and distributed. REGULATORY ISSUES Federal Regulation FERC PSEG, Power and PSE&G Regulation of Wholesale Sales—Generation/Market Issues 2007 Form 10-K, Page 15.Under FERC regulations, public utilities must receive FERC authorization to sell power in interstate commerce. Public utilities may sell power at cost-based rates or may apply to FERC for authority to sell power at market-based rates (MBR). In order to obtain approval to sell power at MBR, FERC must first make a determination that the requesting company lacks market power in the relevant markets. Once this determination is made, and MBR authority is granted, the public utility’s individual sales made under the MBR authority are not reviewed or approved by FERC but are reported to FERC in quarterly reports. PSE&G, ER&T, Power Connecticut, Fossil and Nuclear submitted MBR filings in January 2008 to FERC in which they asserted that they either lack any generation market power or, if they do possess any market power, that market power is being effectively mitigated. They further asserted that, to the extent that FERC analyzes market power held in the small sub-market of Northern PSEG, PJM mitigation rules (including price capping for bids) eliminate the potential for the exercise of market power in this sub-market. FERC issued a decision in April 2008 that (i) eliminates the need for these companies to conduct a market power analysis within the Northern PSEG sub-market; (ii) adopts a rebuttable presumption that existing RTO mitigation schemes eliminate any market power concerns; and (iii) requires additional market power studies. In June 2008, PJM filed a revised transmission capability study for PJM East, which will affect the calculation of import values and potentially impact upon the MBR analysis. In an order issued July 17, 2008, FERC clarified how MBR sellers should calculate transmission capability in their respective market areas. As a result, PSE&G, ER&T, Power Connecticut, Fossil and Nuclear will file a revised MBR analysis based on these recent orders by September 2, 2008. The outcome of this proceeding cannot be predicted. Capacity Market Issues 2007 Form 10-K, Page 16. RPM is a locational installed capacity market design for the PJM region, including a forward auction for installed capacity. Under RPM, generators located in constrained areas within PJM are paid more for their capacity so that they are incented to locate in those areas where generation capacity is most needed. Four PJM capacity auctions covering commitment periods extending from June 1, 2007 through May 31, 2011 have been held to date. 74
• On July 21, 2008, Power and PSE&G filed a brief with the United States Court of Appeals for the District of Columbia Circuit due to concerns regarding the manner in which the CONE is calculated. Other petitioners’ briefs, including the BPU, were also filed. Power and PSE&G strongly support the RPM design but believe that certain components of the design, particularly the CONE mechanism, should be modified. If the CONE is set too low, generators in the PJM markets may not be adequately compensated for existing capacity and may not have sufficient incentives to construct new generating units. •
On May 30, 2008, several state commissions, including the BPU and consumer advocate agencies, as well as customer groups and certain federal agencies (RPM Buyers) filed a complaint with FERC against PJM with respect to RPM.
The complaint challenges the results of the RPM capacity auctions held for the 2008/2009, 2009/2010 and 2010/2011 delivery years. The RPM Buyers assert that various RPM rules permitted suppliers to reduce the amount of capacity offered into the auctions, thereby increasing prices, and that PJM’s mitigation measures were inadequate to restrain the exercise of market power in the capacity auctions. The RPM Buyers requested that FERC find that the clearing prices produced are unlawful and thus should not be charged to capacity buyers or paid to capacity sellers such as Power, and requested refunds, with a refund effective date of May 30, 2008.
This complaint, if granted by FERC, would have a material impact on Power’s transitional auction revenues.
PSEG, along with many other auction participants, filed a response with FERC to the RPM Buyers complaint on July 14, 2008. The outcome cannot be predicted.
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PJM is evaluating ways to improve RPM. PJM retained the Brattle Group, an outside consultant, to prepare a report evaluating the efficacy of the RPM model. This report, which was issued on June 30, 2008, recommends maintaining the basic design elements of RPM but also proposes changes to RPM that would, among other things, (i) increase the pool of resources that can be bid into RPM, e.g. enhancing the ability of efficiency and demand response resources to bid in; (ii) revise the penalty structure for deficiencies and unavailability of capacity resources, perhaps increasing the penalties levied on demand resources; (iii) redesign the incremental auction process by creating a single type of incremental auction; and (iv) evaluate and refine the process for calculating the net CONE.
PJM initiated a stakeholder process to address some or all of the recommendations proposed in the Brattle Group report, which will likely result in a filing by PJM by the end of 2008 with FERC to implement certain changes to RPM.
Reactive Power
In May 2008, ER&T filed with FERC to increase its annual fixed revenues by $18 million to reflect its provision of reactive power support in PJM. Reactive power encompasses certain ancillary services necessary to maintain voltage support and operate the system. No protests were filed at FERC regarding the filing, though PJM filed to challenge the proposed effective date. PJM filed comments asking FERC not to make the rates effective in May, due to concerns with retroactive billing adjustments, but rather to make the rates effective the first day of the month that FERC approves the filing. As requested by FERC, ER&T provided additional support for its filing on July 8, 2008. No protests were filed by the comment date.
FERC Transmission Regulation
PSE&G Transmission Rate Case Filing
On July 7, 2008, PSE&G filed a petition with FERC to implement a cost of service formula rate for PSE&G’s existing and future transmission investment.
Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which takes O&M expenditures and capital investments and applies an approved Return on Equity (ROE). PSE&G has proposed a forward-looking formula rate mechanism, which has been approved by FERC for other transmission owners. If approved, this mechanism would allow PSE&G to update its transmission rates annually based on forecasted O&M and
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capital expenditures for the coming year, with no lag of recovery, and would provide for a true-up to actual expenditures in the subsequent year. PSE&G has proposed an ROE of 11.68%, which would include the previously approved 50 basis point adder for RTO membership. While PSE&G has not requested approval in this petition of any incentive rates, the formula rate mechanism would provide for recovery of previously-approved transmission rate incentives as well as a mechanism for recovery of any transmission incentives authorized in the future. PSE&G has requested an effective date of October 1, 2008. The matter is pending at FERC. Transmission Rates and Cost Allocation 2007 Form 10-K, Page 17.In 2007, PJM and its members reached a settlement regarding how to allocate costs for new lower voltage (below 500 kilovolts (kV)) transmission expansion. Specifically, PJM will use a “beneficiary pays” methodology, identifying the beneficiaries of a particular expansion and allocating costs to those beneficiaries. Power and PSE&G supported this settlement as properly allocating costs for such facilities and ensuring that only the correct amounts of costs are allocated to ratepayers. On July 29, 2008, the FERC issued an order approving this settlement. While the settlement is quite comprehensive in establishing how to determine the beneficiaries of a particular transmission expansion and allocating the costs to those beneficiaries, the parties could not reach agreement on certain issues related to whether and how merchant transmission facilities that have firm rights to export power out of PJM to another region should be included in the beneficiary pays analysis and be responsible for a share of the costs of the transmission upgrades. Rather, these issues were set for hearing before FERC. A hearing on these issues was held in May and briefing occurred in June and July. A decision is expected from FERC-assigned Administrative Law Judge (ALJ) in September of 2008. While PSEG cannot predict the outcome of this proceeding, PSEG continues to support allocation of cost responsibility to these merchant transmission projects as they have a comparable impact on the transmission system as load within PJM. Transmission Expansion 2007 Form 10-K, Page 17. In June 2007, PSE&G endorsed the construction of three new 500 kV transmission lines intended to address reliability issues of the electrical grid serving New Jersey customers. Also in June 2007, PJM approved construction of one of the proposed lines (Susquehanna-Roseland line) and in April 2008, FERC approved incentive rate treatment for the line. In May 2008, seven state consumer advocates, including the New Jersey Division of Rate Counsel (Rate Counsel), sought rehearing of FERC’s April 2008 order approving the incentive rate treatment. In June 2008, PSE&G and PPL filed an answer to this rehearing request, urging FERC to deny the request for rehearing. The rehearing request is currently pending at FERC. Through the RTEP process, PJM has identified the need for the construction of a 500kV transmission line running from Virginia through Maryland and Delaware and terminating in Salem township. PSE&G will be responsible for the constructing and operating a portion of this line, known as the Mid-Atlantic Pathway Project (MAPP). The in-service date has not been finalized. PSE&G’s costs are estimated to be approximately $150 million, which are not included in its current capital expenditures forecast. Con Edison In November 2001, Consolidated Edison Company of New York, Inc. (Con Ed) filed a complaint with FERC against PSE&G, PJM and NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. Both PSE&G and Con Ed have sought judicial review of FERC orders addressing these contracts before the US Court of Appeals for the District of Columbia Circuit. The matter remains pending. The agreements expire in May 2012. On April 22, 2008, pursuant to FERC rules that permit holders of long-term transmission rights to extend their entitlements, PJM filed contracts with FERC which would extend until 2017 the transmission service that is the subject of the disputed agreements between PSE&G and Con Ed. PSE&G has protested PJM’s filing. This protest is pending at FERC. 76
PSE&G is unable to predict the outcome of these proceedings. Nuclear Regulatory Commission (NRC) Power Additional NRC Oversight 2007 Form 10-K, Page 19. Power has been advised by the NRC that Salem Unit 1 will be subject to additional oversight. The additional NRC oversight is due to a negative change in the performance indicator related to the plant’s diesel back-up power system. This increased oversight will include a supplemental inspection to provide assurance that the problem has been adequately addressed. Power will continue to be under heightened oversight until inspection and reviews are completed by the NRC in the fourth quarter of 2008. State Regulation PSE&G SBC Filing 2007 Form 10-K, Page 20.The SBC is a mechanism designed to insure recovery of costs associated with activities required to be accomplished to achieve specific government mandated public policy determinations. The programs that are covered by the SBC (gas and electric) are energy efficiency and renewable energy programs, Manufactured Gas Plant RAC and the USF. In addition, the electric SBC includes a Social Programs component. All components include interest on both over and under recoveries. In May 2007, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation charge (NGC) rates. A revised motion was filed in October 2007. In June 2008 PSE&G received the ALJ’s Initial Decision disallowing a portion of its claimed lost revenues. The ALJ granted an electric increase of $89.7 million compared to $89.8 million requested and a gas increase of $15.2 million compared to PSE&G’s request of $16.7 million. Exceptions and reply exceptions were filed in July 2008. Power and PSE&G BGSS 2007 Form 10-K, Page 21. BGSS is the mechanism approved by the BPU designed to recover all gas costs related to the supply for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. Revenues are matched with costs using deferred accounting, with the goal of achieving a zero cumulative balance by September 30 of each year. In May 2008, PSE&G requested an increase in annual BGSS revenues of $376 million, excluding Sales and Use Tax, to be effective October 1, 2008. This represents an approximate 20% increase on a typical residential gas customer’s bill. Based on discussions with the BPU Staff, PSE&G submitted a proposed Stipulation of the Parties that would place the filed rate into effect on October 1, 2008 on a provisional basis, subject to refund. The matter is currently pending at the BPU. Solar Initiative 2007 Form 10-K, Page 22.InApril 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. This program received final BPU approval and a written BPU order in April 2008. Under the plan, PSE&G will invest approximately $105 million over two years in a pilot program to help finance the installation of 30 MW of solar systems throughout its electric service area. PSE&G will provide loans to customers in its electric service territory for the installation of solar photovoltaic systems on the customers’ premises. The borrowers can repay the loans over a period of either 10 years (for residential customer loans) or 15 years (for all other loans) by providing PSE&G with solar renewable energy certificates (SRECs). Borrowers will also have the option to repay the loans with cash. The program will support 30 MW of solar power, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard requirements in PSE&G’s service area in May 2009 and May 2010. 77
PSE&G will be allowed a return of 11.11% on invested capital, including income tax effects. The program was opened up to non-residential customers on April 17, 2008. As of June 30, 2008, applications have been received for approximately 38.5% of the 30 MW program. Beginning July 2008, the program became available to residential customers. The BPU is also considering whether additional measures are needed to stimulate solar development in New Jersey. A stakeholder working group was recently concluded, focusing on such issues as whether New Jersey utilities like PSE&G should be required to purchase SRECs from solar developers to stimulate the market. PSE&G has proposed to continue working within the construct of its solar loan program, and to potentially expand the program or extend its duration. New Jersey Energy Master Plan (EMP) 2007 Form 10-K, Page 22. State law in New Jersey requires that an EMP be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. A draft EMP was released in April 2008 with a final plan expected to be completed later in the year. It proposes a number of the actions to improve energy efficiency and increase the use of renewable resources and clean central station power for addressing climate change, including to: •
conduct a complete review of the BGS auction process;
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maximize energy conservation and energy efficiency to reduce New Jersey’s projected energy use by 20% by the year 2020;
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reduce prices by decreasing peak demand by 5,700 MW by 2020;
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meet 22.5% of New Jersey’s electricity needs from renewable sources;
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develop new low carbon emitting, efficient power plants to help close the gap between the supply and demand of electricity;
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invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey; and
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consider the establishment of a state power authority or a state energy council.
PSE&G has expressed its desire to be a partner to the State in the EMP. To this end PSE&G has proposed several programs in filings with the BPU addressing different components of the EMP goals, has submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation and has been actively involved in the broad-based constituent working groups created to develop these strategies. PSEG and PSE&G participated in the EMP roundtable discussions conducted by the State of New Jersey in June 2008 and will participate in upcoming public proceedings to review the conclusions and recommendations of the EMP.
Advanced Metering Infrastructure (AMI) Technologies
2007 Form 10-K, Page 22. In December 2007, PSE&G filed a petition with the BPU requesting expedited approval to deploy and test AMI technologies, to enable customers to monitor energy use, conserve energy, reduce costs during peak periods and reduce CO2 emissions that contribute to global climate change. In June 2008, the BPU approved a pilot program. PSE&G is in the initial design stages.
Carbon Abatement Program
2007 Form 10-K, Page 22.In December 2007, PSE&G filed a petition with the BPU seeking expedited approval of a carbon abatement pilot program. This filing was withdrawn on May 1, 2008.
A petition for approval for a small scale carbon abatement program was filed with the BPU in June 2008 seeking approval under the Regional Greenhouse Gas Initiative (RGGI) legislation which was signed into law in January 2008. PSE&G proposes to invest up to $46 million over four years in programs across specific customer segments. The program is designed to support the State’s EMP goals and promote energy efficiency. PSE&G has requested a return on this investment at its established rate. The matter is currently pending. This amount is not included in PSE&G’s projected capital expenditures.
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A listing of exhibits being filed with this document is as follows: a. PSEG: Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 31: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 (1934 Act) Exhibit 31.1: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.1: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code b. Power: Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.2: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 31.3: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32.2: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.3: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code c. PSE&G: Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements Exhibit 31.4: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 31.5: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32.4: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.5: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 79
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: August 1, 2008 80
(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: August 1, 2008 81
(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: August 1, 2008 82
(Registrant)
Vice President and Controller
(Principal Accounting Officer)