UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2007
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 | ||
001-00973 | PUBLIC SERVICE ELECTRIC AND GAS COMPANY | 22-1212800 | ||
000-49614 | PSEG POWER LLC | 22-3663480 | ||
000-32503 | PSEG ENERGY HOLDINGS L.L.C. | 42-1544079 |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YesS No£
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
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Public Service Enterprise Group Incorporated | Large accelerated filerS | Accelerated filer£ | Non-accelerated filer£ | |||
Public Service Electric and Gas Company | Large accelerated filer£ | Accelerated filer£ | Non-accelerated filerS | |||
PSEG Power LLC | Large accelerated filer£ | Accelerated filer£ | Non-accelerated filerS | |||
PSEG Energy Holdings L.L.C. | Large accelerated filer£ | Accelerated filer£ | Non-accelerated filerS |
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes£ NoS
As of October 31, 2007, Public Service Enterprise Group Incorporated had 254,313,179 outstanding shares of its sole class of Common Stock, without par value.
As of October 31, 2007, 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.
PSEG Power LLC and PSEG Energy Holdings L.L.C. are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and are filing their respective Quarterly Reports on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
TABLE OF CONTENTS Page ii Item 1. 1 5 9 13 17 18 Note 3. Discontinued Operations, Dispositions and Impairments 21 24 25 35 38 39 41 43 44 46 47 49 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) 52 52 58 68 73 73 Item 3. 73 Item 4. 79 Item 1. 81 Item 1A. 82 Item 5. 82 Item 6. 87 88 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. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings) undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review should not be construed as a complete list of factors that could affect forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: • changes in energy policies and regulation, including market rules; • ability to attain satisfactory regulatory results; • ability to maintain operating performance and cash flow from investments at projected levels; • inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations; • continued market based rate authority, including any necessary mitigation measures; • energy transmission constraints or lack thereof and the availability of transmission facilities; • adverse changes in the market for energy, capacity, natural gas, coal, nuclear fuel, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas and power; • changes in the electric industry, including changes to regional transmission organizations and power pools; • changes in the number of market participants and the risk profiles of such participants; • adverse or unanticipated weather conditions that significantly impact costs and/or operations; • environmental regulations that significantly impact operations; • governmental and industry responses to global climate change; • changes in demand including the effects of conservation efforts and energy efficiency; • timing and success of efforts to develop generation, transmission and distribution projects; • credit, commodity, interest rate, counterparty and other financial market risks; • liquidity and the ability to access capital and maintain adequate credit ratings; • changes in rates of return on overall debt and equity markets that could adversely impact the value of pension and other postretirement benefits assets and liabilities and the Nuclear Decommissioning Trust Funds; • effectiveness of risk management and internal control systems; • ability to realize tax benefits and favorably resolve tax audit claims; • ability to attract and retain management and other key employees; • changes in political conditions; • changes in technology that make generation, transmission and/or distribution assets less competitive; • continued availability of insurance coverage at commercially reasonable rates; • involvement in lawsuits, including liability claims and commercial disputes; ii
• acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG’s, PSE&G’s, Power’s and Energy Holdings’ strategy or structure; • general economic conditions, including inflation or deflation; • changes in tax laws and regulations; • substantial competition in the domestic and worldwide energy markets; • margin posting requirements, especially during significant price movements for natural gas and power; • availability of fuel and timely transportation at reasonable prices; • delays, cost escalations or unsuccessful construction and development; • changes in regulation and safety and security measures at nuclear facilities; • changes in foreign currency exchange rates; • deterioration in the credit of lessees and their ability to adequately service lease rentals; • changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements; • ability to recover investments or service debt as a result of any of the risks or uncertainties mentioned herein; and • acts of war or terrorism. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings 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, PSEG, PSE&G, Power and Energy Holdings or their respective business prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and Energy Holdings expressly disclaims 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. In making any investment decision regarding PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings are not making, and you should not infer, any representation about the likely existence of any particular future set of facts or circumstances. 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. iii
PART I. FINANCIAL INFORMATION PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED For the Quarters For the Nine Months 2007 2006 2007 2006 (Millions) OPERATING REVENUES $ 3,475 $ 3,297 $ 9,888 $ 9,286 OPERATING EXPENSES Energy Costs 1,674 1,740 5,101 5,223 Operation and Maintenance 576 533 1,774 1,682 Write-down of Assets 12 — 12 263 Depreciation and Amortization 213 228 603 629 Taxes Other Than Income Taxes 31 32 104 100 Total Operating Expenses 2,506 2,533 7,594 7,897 Income from Equity Method Investments 33 30 86 93 OPERATING INCOME 1,002 794 2,380 1,482 Other Income 61 48 190 149 Other Deductions (57 ) (41 ) (130 ) (84 ) Interest Expense (191 ) (199 ) (560 ) (587 ) Preferred Stock Dividends (1 ) (1 ) (3 ) (3 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 814 601 1,877 957 Income Tax Expense (314 ) (229 ) (750 ) (388 ) INCOME FROM CONTINUING OPERATIONS 500 372 1,127 569 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of ($3), $1, ($18) and ($132) for the quarters and nine months ended 2007 and 2006, respectively 6 2 (17 ) 217 NET INCOME $ 506 $ 374 $ 1,110 $ 786 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC 254,272 251,747 253,603 251,471 DILUTED 254,545 252,329 253,983 252,161 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS $ 1.97 $ 1.47 $ 4.45 $ 2.26 NET INCOME $ 1.99 $ 1.48 $ 4.38 $ 3.12 DILUTED INCOME FROM CONTINUING OPERATIONS $ 1.97 $ 1.47 $ 4.44 $ 2.26 NET INCOME $ 1.99 $ 1.48 $ 4.37 $ 3.12 DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.585 $ 0.57 $ 1.755 $ 1.71 See Notes to Condensed Consolidated Financial Statements. 1
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
September 30,
Ended
September 30,
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED September 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 421 $ 125 Accounts Receivable, net of allowances of $55 and $52 in 2007 and 2006, respectively 1,520 1,359 Unbilled Revenues 237 328 Fuel 879 847 Materials and Supplies 318 290 Prepayments 233 72 Restricted Funds 80 79 Derivative Contracts 56 128 Assets of Discontinued Operations 297 622 Assets Held for Sale — 40 Other 91 45 Total Current Assets 4,132 3,935 PROPERTY, PLANT AND EQUIPMENT 19,717 18,698 Less: Accumulated Depreciation and Amortization (6,210 ) (5,831 ) Net Property, Plant and Equipment 13,507 12,867 NONCURRENT ASSETS Regulatory Assets 5,134 5,694 Long-Term Investments 3,876 3,868 Nuclear Decommissioning Trust (NDT) Funds 1,311 1,256 Other Special Funds 158 147 Goodwill 422 406 Intangibles 47 46 Derivative Contracts 55 55 Other 267 296 Total Noncurrent Assets 11,270 11,768 TOTAL ASSETS $ 28,909 $ 28,570 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED September 30, December 31, (Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 1,022 $ 849 Commercial Paper and Loans 204 381 Accounts Payable 916 960 Derivative Contracts 431 335 Accrued Interest 205 123 Accrued Taxes 68 149 Clean Energy Program 131 120 Liabilities of Discontinued Operations 134 134 Other 470 480 Total Current Liabilities 3,581 3,531 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 4,287 4,447 Regulatory Liabilities 446 646 Asset Retirement Obligations 537 509 Other Postretirement Benefit (OPEB) Costs 1,098 1,089 Accrued Pension Costs 318 327 Clean Energy Program 43 133 Environmental Costs 384 421 Derivative Contracts 150 204 Long-Term Accrued Taxes 538 — Other 156 170 Total Noncurrent Liabilities 7,957 7,946 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 7,408 7,636 Securitization Debt 1,581 1,708 Project Level, Non-Recourse Debt 805 735 Debt Supporting Trust Preferred Securities 186 186 Total Long-Term Debt 9,980 10,265 SUBSIDIARY’S PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006—795,234 shares 80 80 COMMON STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued; 2007—266,778,330 shares; 2006—266,372,440 shares 4,723 4,661 Treasury Stock, at cost; 2007—12,464,734 shares; 2006—13,727,032 shares (471 ) (516 ) Retained Earnings 3,186 2,711 Accumulated Other Comprehensive Loss (127 ) (108 ) Total Common Stockholders’ Equity 7,311 6,748 Total Capitalization 17,371 17,093 TOTAL LIABILITIES AND CAPITALIZATION $ 28,909 $ 28,570 See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED For The Nine Months 2007 2006 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 1,110 $ 786 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposition of Property, Plant and Equipment (3 ) (228 ) Gain on Disposal of Discontinued Operations, net of tax — (1 ) Depreciation and Amortization 606 645 Amortization of Nuclear Fuel 73 73 Provision for Deferred Income Taxes (Other than Leases) and ITC 45 (5 ) Non-Cash Employee Benefit Plan Costs 138 180 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes 46 32 (Gain) Loss on Sale of Investments (11 ) 255 Equity in Earnings of Affiliates Less Dividends Received (5 ) (45 ) Foreign Currency Transaction Loss 9 4 Realized and Unrealized Losses (Gains) on Energy Contracts and Other Derivatives 16 (32 ) (Under) Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs (38 ) 112 Under Recovery of Societal Benefits Charge (SBC) (29 ) (115 ) Cost of Removal (28 ) (26 ) Net Realized Gains and Income from NDT Funds (37 ) (54 ) Other Non-Cash Charges 6 16 Net Change in Working Capital (312 ) 58 Employee Benefit Plan Funding and Related Payments (76 ) (127 ) Investment Income and Dividend Distributions from Partnerships 13 7 Other 16 (102 ) Net Cash Provided By Operating Activities 1,539 1,433 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (973 ) (748 ) Proceeds from Sale of Discontinued Operations 325 494 Proceeds from Sale of Property, Plant and Equipment 43 3 Proceeds from the Sale of Investments and Return of Capital from Partnerships 15 186 Proceeds from NDT Funds Sales 1,275 1,056 Investment in NDT Funds (1,295 ) (1,069 ) Restricted Funds (4 ) (22 ) NDT Funds Interest and Dividends 35 29 Other (10 ) 18 Net Cash Used In Investing Activities (589 ) (53 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans (177 ) 452 Issuance of Long-Term Debt 350 — Issuance of Non-Recourse Debt 163 — Issuance of Common Stock 82 56 Redemption of Long-Term Debt (488 ) (1,131 ) Repayment of Non-Recourse Debt (35 ) (37 ) Repayment of Securitization Debt (121 ) (115 ) Redemption of Debt Underlying Trust Securities — (154 ) Cash Dividends Paid on Common Stock (445 ) (430 ) Other 16 (26 ) Net Cash Used In Financing Activities (655 ) (1,385 ) Effect of Exchange Rate Change 1 (2 ) Net Increase (Decrease) in Cash and Cash Equivalents 296 (7 ) Cash and Cash Equivalents at Beginning of Period 125 281 Cash and Cash Equivalents at End of Period $ 421 $ 274 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 460 $ 312 Interest Paid, Net of Amounts Capitalized $ 478 $ 510 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
September 30,
(Unaudited)
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For The Quarters Ended For The Nine Months Ended 2007 2006 2007 2006 (Millions) OPERATING REVENUES $ 2,106 $ 1,971 $ 6,340 $ 5,754 OPERATING EXPENSES Energy Costs 1,341 1,250 4,083 3,725 Operation and Maintenance 308 278 947 855 Depreciation and Amortization 161 174 449 476 Taxes Other Than Income Taxes 31 32 104 100 Total Operating Expenses 1,841 1,734 5,583 5,156 OPERATING INCOME 265 237 757 598 Other Income 2 6 12 18 Other Deductions (1 ) — (3 ) (2 ) Interest Expense (85 ) (86 ) (250 ) (254 ) INCOME BEFORE INCOME TAXES 181 157 516 360 Income Tax Expense (74 ) (69 ) (214 ) (160 ) NET INCOME 107 88 302 200 Preferred Stock Dividends (1 ) (1 ) (3 ) (3 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 106 $ 87 $ 299 $ 197 See disclosures regarding Public Service Electric and Gas Company included in the 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
September 30,
September 30,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY September 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 36 $ 28 Accounts Receivable, net of allowances of $50 in 2007 and $46 in 2006 887 805 Unbilled Revenues 237 328 Materials and Supplies 58 50 Prepayments 193 14 Restricted Funds 10 12 Derivative Contracts 1 2 Other 44 36 Total Current Assets 1,466 1,275 PROPERTY, PLANT AND EQUIPMENT 11,493 11,061 Less: Accumulated Depreciation and Amortization (3,972 ) (3,794 ) Net Property, Plant and Equipment 7,521 7,267 NONCURRENT ASSETS Regulatory Assets 5,134 5,694 Long-Term Investments 151 149 Other Special Funds 56 53 Other 112 115 Total Noncurrent Assets 5,453 6,011 TOTAL ASSETS $ 14,440 $ 14,553 See disclosures regarding Public Service Electric and Gas Company included in the 6
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY September 30, December 31, (Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 177 $ 284 Commercial Paper and Loans 204 31 Accounts Payable 326 254 Accounts Payable—Affiliated Companies, net 345 645 Accrued Interest 52 55 Clean Energy Program 131 120 Derivative Contracts 6 2 Other 300 322 Total Current Liabilities 1,541 1,713 NONCURRENT LIABILITIES Deferred Income Taxes and ITC 2,404 2,517 Other Postretirement Benefit (OPEB) Costs 899 898 Accrued Pension Costs 125 133 Regulatory Liabilities 446 646 Clean Energy Program 43 133 Environmental Costs 333 367 Asset Retirement Obligations 230 221 Derivative Contracts 28 18 Long-Term Accrued Taxes due Affiliate 61 — Other 8 6 Total Noncurrent Liabilities 4,577 4,939 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 3,352 3,003 Securitization Debt 1,581 1,708 Total Long-Term Debt 4,933 4,711 PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006— 795,234 shares 80 80 COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding 892 892 Contributed Capital 170 170 Basis Adjustment 986 986 Retained Earnings 1,260 1,061 Accumulated Other Comprehensive Income 1 1 Total Common Stockholder’s Equity 3,309 3,110 Total Capitalization 8,322 7,901 TOTAL LIABILITIES AND CAPITALIZATION $ 14,440 $ 14,553 See disclosures regarding Public Service Electric and Gas Company included in the 7
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited) ��
Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY For The Nine Months Ended 2007 2006 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 302 $ 200 Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization 449 476 Provision for Deferred Income Taxes and ITC (114 ) (69 ) Non-Cash Employee Benefit Plan Costs 104 128 Gain on Sale of Property, Plant and Equipment (3 ) — Non-Cash Interest Expense 9 14 Cost of Removal (28 ) (26 ) Employee Benefit Plan Funding and Related Payments (53 ) (81 ) Over Recovery of Electric Energy Costs (BGS and NTC) 1 39 (Under) Over Recovery of Gas Costs (39 ) 73 Under Recovery of SBC (29 ) (115 ) Other Non-Cash Charges (2 ) (3 ) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues 9 361 Materials and Supplies (8 ) — Prepayments (184 ) (106 ) Accrued Taxes (1 ) (25 ) Accrued Interest (3 ) (18 ) Accounts Payable 72 4 Accounts Receivable/Payable-Affiliated Companies, net (201 ) (337 ) Other Current Assets and Liabilities (35 ) (77 ) Other (2 ) (15 ) Net Cash Provided By Operating Activities 244 423 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (421 ) (392 ) Proceeds from the Sale of Property, Plant and Equipment 3 — Restricted Funds (1 ) (1 ) Net Cash Used In Investing Activities (419 ) (393 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 173 327 Issuance of Long-Term Debt 350 — Redemption of Securitization Debt (121 ) (115 ) Redemption of Long-Term Debt (113 ) (322 ) Deferred Issuance Costs (3 ) — Cash Dividends Paid on Common Stock (100 ) — Preferred Stock Dividends (3 ) (3 ) Net Cash Provided by (Used In) Financing Activities 183 (113 ) Net Increase (Decrease) In Cash and Cash Equivalents 8 (83 ) Cash and Cash Equivalents at Beginning of Period 28 159 Cash and Cash Equivalents at End of Period $ 36 $ 76 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 301 $ 187 Interest Paid, Net of Amounts Capitalized $ 241 $ 254 See disclosures regarding Public Service Electric and Gas Company included in the 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
September 30,
(Unaudited)
Operating Activities:
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
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| For The Quarters | For The Nine | ||||||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||||||
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OPERATING REVENUES |
| $ |
| 1,580 |
| $ |
| 1,455 |
| $ |
| 5,034 |
| $ |
| 4,551 | ||||||||||||
OPERATING EXPENSES |
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Energy Costs |
| 712 |
| 809 |
| 2,894 |
| 2,965 | ||||||||||||||||||||
Operation and Maintenance |
| 232 |
| 219 |
| 711 |
| 713 | ||||||||||||||||||||
Depreciation and Amortization |
| 36 |
| 36 |
| 104 |
| 103 | ||||||||||||||||||||
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Total Operating Expenses |
| 980 |
| 1,064 |
| 3,709 |
| 3,781 | ||||||||||||||||||||
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OPERATING INCOME |
| 600 |
| 391 |
| 1,325 |
| 770 | ||||||||||||||||||||
Other Income |
| 56 |
| 38 |
| 162 |
| 113 | ||||||||||||||||||||
Other Deductions |
| (42 | ) |
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| (26 | ) |
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| (105 | ) |
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| (59 | ) |
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Interest Expense |
| (43 | ) |
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| (39 | ) |
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| (119 | ) |
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| (107 | ) |
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INCOME FROM CONTINUING OPERATIONS |
| 571 |
| 364 |
| 1,263 |
| 717 | ||||||||||||||||||||
Income Tax Expense |
| (233 | ) |
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| (157 | ) |
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| (519 | ) |
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| (304 | ) |
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INCOME FROM CONTINUING OPERATIONS |
| 338 |
| 207 |
| 744 |
| 413 | ||||||||||||||||||||
Income (Loss) from Discontinued Operations, net of tax (expense) benefit of $(1), $2, $5 and $14 for the quarters and nine months ended 2007 and 2006, respectively |
| 1 |
| (2 | ) |
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| (8 | ) |
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| (19 | ) |
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EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
| $ |
| 339 |
| $ |
| 205 |
| $ |
| 736 |
| $ |
| 394 | ||||||||||||
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See disclosures regarding PSEG Power LLC included in the
Notes to Condensed Consolidated Financial Statements.
9
PSEG POWER LLC September 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 9 $ 13 Accounts Receivable 499 430 Accounts Receivable—Affiliated Companies, net 233 495 Short-Term Loan to Affiliate 37 — Fuel 877 846 Materials and Supplies 220 202 Energy Trading Contracts 27 55 Derivative Contracts 15 56 Assets of Discontinued Operations — 325 Assets Held for Sale — 40 Other 33 26 Total Current Assets 1,950 2,488 PROPERTY, PLANT AND EQUIPMENT 6,371 5,868 Less: Accumulated Depreciation and Amortization (1,789 ) (1,638 ) Net Property, Plant and Equipment 4,582 4,230 NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Funds 1,311 1,256 Goodwill 16 16 Other Intangibles 34 35 Other Special Funds 44 42 Energy Trading Contracts 9 10 Derivative Contracts 4 19 Other 64 50 Total Noncurrent Assets 1,482 1,428 TOTAL ASSETS $ 8,014 $ 8,146 See disclosures regarding PSEG Power LLC included in the 10
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC September 30, December 31, (Millions) LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Accounts Payable $ 444 $ 589 Short-Term Loan from Affiliate — 54 Energy Trading Contracts 141 222 Derivative Contracts 251 90 Accrued Interest 80 34 Other 95 95 Total Current Liabilities 1,011 1,084 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 178 48 Asset Retirement Obligations 304 287 Other Postretirement Benefit (OPEB) Costs 143 138 Accrued Pension Costs 103 106 Energy Trading Contracts 11 19 Derivative Contracts 107 151 Environmental Costs 51 54 Long-Term Accrued Taxes due Affiliate 28 — Other 13 18 Total Noncurrent Liabilities 938 821 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt 2,818 2,818 MEMBER’S EQUITY Contributed Capital 2,000 2,000 Basis Adjustment (986 ) (986 ) Retained Earnings 2,483 2,586 Accumulated Other Comprehensive Loss (250 ) (177 ) Total Member’s Equity 3,247 3,423 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 8,014 $ 8,146 See disclosures regarding PSEG Power LLC included in the 11
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC For The Nine Months Ended 2007 2006 (Millions) (Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 736 $ 394 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposition of Property, Plant and Equipment — (1 ) Depreciation and Amortization 104 116 Amortization of Nuclear Fuel 73 73 Interest Accretion on Asset Retirement Obligations 17 25 Provision for Deferred Income Taxes and ITC 191 74 Unrealized Losses on Energy Contracts and Other Derivatives 28 17 Non-Cash Employee Benefit Plan Costs 21 34 Net Realized Gains and Income from NDT Funds (37 ) (54 ) Net Change in Working Capital: Fuel, Materials and Supplies (49 ) (57 ) Accounts Receivable (69 ) 412 Accrued Interest 46 39 Accounts Payable (181 ) (325 ) Accounts Receivable/Payable-Affiliated Companies, net 191 303 Other Current Assets and Liabilities (5 ) 25 Employee Benefit Plan Funding and Related Payments (13 ) (34 ) Other (5 ) (121 ) Net Cash Provided By Operating Activities 1,048 920 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (501 ) (316 ) Proceeds from Sale of Discontinued Operations 325 — Sales of Property, Plant and Equipment 40 1 Proceeds from NDT Funds Sales 1,275 1,056 NDT Funds Interest and Dividends 35 29 Investment in NDT Funds (1,295 ) (1,069 ) Short-Term Loan—Affiliated Company, net (37 ) — Other (15 ) 10 Net Cash Used In Investing Activities (173 ) (289 ) CASH FLOWS FROM FINANCING ACTIVITIES Cash Dividend Paid (825 ) — Redemption of Long-Term Debt — (500 ) Short-Term Loan—Affiliated Company, net (54 ) (134 ) Net Cash Used In Financing Activities (879 ) (634 ) Net Decrease in Cash and Cash Equivalents (4 ) (3 ) Cash and Cash Equivalents at Beginning of Period 13 8 Cash and Cash Equivalents at End of Period $ 9 $ 5 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid $ 266 $ 200 Interest Paid, Net of Amounts Capitalized $ 89 $ 92 See disclosures regarding PSEG Power LLC included in the 12
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
September 30,
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. For The Quarters For The Nine Months 2007 2006 2007 2006 (Millions) OPERATING REVENUES Electric Generation and Distribution Revenues $ 338 $ 343 $ 830 $ 896 Income from Leveraged and Operating Leases 31 38 96 115 Other 11 4 36 25 Total Operating Revenues 380 385 962 1,036 OPERATING EXPENSES Energy Costs 212 192 570 578 Operation and Maintenance 44 45 137 136 Write-down of Assets 12 — 12 263 Depreciation and Amortization 12 13 40 35 Total Operating Expenses 280 250 759 1,012 Income from Equity Method Investments 33 30 86 93 OPERATING INCOME 133 165 289 117 Other Income 5 13 23 30 Other Deductions (11 ) (14 ) (15 ) (21 ) Interest Expense (44 ) (49 ) (124 ) (146 ) INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST 83 115 173 (20 ) Income Tax (Expense) Benefit (17 ) (18 ) (48 ) 36 Minority Interests in Earnings of Subsidiaries — — 2 (1 ) INCOME FROM CONTINUING OPERATIONS 66 97 127 15 Income (Loss) from Discontinued Operations, net of tax expense of $2, $1, $23 and $4 for the quarters and nine months ended 2007 and 2006, respectively 5 4 (9 ) 8 Gain on Disposal of Discontinued Operations, net of tax expense of $142 for the nine months ended 2006 — — — 228 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 71 $ 101 $ 118 $ 251 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 13
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
September 30,
Ended
September 30,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. September 30, December 31, (Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 83 $ 83 Accounts Receivable: Trade—net of allowances of $5 and $6 in 2007 and 2006, respectively 121 95 Other Accounts Receivable 12 28 Notes Receivable: Affiliated Companies 257 28 Other 38 — Inventory 39 39 Restricted Funds 70 67 Assets of Discontinued Operations 297 297 Derivative Contracts 13 14 Other 8 9 Total Current Assets 938 660 PROPERTY, PLANT AND EQUIPMENT 1,621 1,553 Less: Accumulated Depreciation and Amortization (326 ) (288 ) Net Property, Plant and Equipment 1,295 1,265 NONCURRENT ASSETS Leveraged Leases, net 2,796 2,810 Corporate Joint Ventures and Partnership Interests 880 868 Goodwill 406 390 Other Intangibles 13 11 Derivative Contracts 42 26 Other 106 134 Total Noncurrent Assets 4,243 4,239 TOTAL ASSETS $ 6,476 $ 6,164 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 14
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. September 30, December 31, (Millions) LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 322 $ 42 Accounts Payable: Trade 77 52 Affiliated Companies 7 12 Derivative Contracts 31 16 Accrued Interest 52 26 Liabilities of Discontinued Operations 134 134 Other 61 66 Total Current Liabilities 684 348 NONCURRENT LIABILITIES Deferred Income Taxes and Investment and Energy Tax Credits 1,737 1,910 Derivative Contracts 2 11 Long-Term Accrued Taxes due to Affiliate 449 — Other 94 97 Total Noncurrent Liabilities 2,282 2,018 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) MINORITY INTERESTS 26 26 LONG-TERM DEBT Project Level, Non-Recourse Debt 805 735 Senior Notes 943 1,149 Total Long-Term Debt 1,748 1,884 MEMBER’S EQUITY Ordinary Unit 1,048 1,193 Retained Earnings 534 592 Accumulated Other Comprehensive Income 154 103 Total Member’s Equity 1,736 1,888 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 6,476 $ 6,164 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 15
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. For The Nine Months 2007 2006 (Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 118 $ 251 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 43 38 Demand Side Management Amortization 1 2 Deferred Income Taxes (Other than Leases) (27 ) (8 ) Leveraged Lease Income, Adjusted for Rents Received and 46 32 Equity in Earnings of Affiliates Less Than Dividends Received (5 ) (45 ) (Gain) Loss on Sale of Investments (11 ) 255 Gain on Sale of Discontinued Operations — (228 ) Unrealized Gain on Investments (2 ) — Foreign Currency Transaction Loss 9 4 Change in Fair Value of Derivative Financial Instruments (12 ) (49 ) Non-Cash Employee Benefit Plan Costs 1 2 Other Non-Cash (Credits) Charges (2 ) 3 Net Changes in Working Capital: Accounts Receivable (38 ) 12 Inventory 1 (15 ) Accounts Payable 17 (3 ) Accounts Receivable/Payable-Affiliated Companies, net 89 (90 ) Other Current Assets and Liabilities 22 (32 ) Investment Income and Dividend Distributions from Partnerships 13 7 Other 2 2 Net Cash Provided By Operating Activities 265 138 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (34 ) (37 ) Proceeds from Sale of Discontinued Operations — 494 Proceeds from the Sale of Investments 15 186 Proceeds from Sale of Other Assets 14 — Short-Term Loan Receivable—Affiliated Company, net (229 ) 34 Restricted Funds (3 ) (21 ) Other (8 ) 3 Net Cash (Used In) Provided By Investing Activities (245 ) 659 CASH FLOWS FROM FINANCING ACTIVITIES Repayment of Non-Recourse Long-Term Debt (35 ) (37 ) Issuance of Non-Recourse Long-Term Debt 163 — Repayment of Senior Notes — (309 ) Return of Contributed Capital (145 ) (425 ) Other (4 ) (1 ) Net Cash Used In Financing Activities (21 ) (772 ) Effect of Exchange Rate Change 1 (2 ) Net Increase In Cash and Cash Equivalents — 23 Cash and Cash Equivalents at Beginning of Period 83 61 Cash and Cash Equivalents at End of Period $ 83 $ 84 Supplemental Disclosure of Cash Flow Information: Income Taxes Received $ (93 ) $ (86 ) Interest Paid, Net of Amounts Capitalized $ 102 $ 108 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 16
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended
September 30,
(Unaudited)
Deferred Income Taxes
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), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings 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: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). PSE&G PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the 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. Power Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management function through three principal direct wholly owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to regulation by FERC, and certain Fossil subsidiaries are also subject to state regulation. Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC). Energy Holdings Energy Holdings has two principal, direct, wholly owned subsidiaries: PSEG Global L.L.C. (Global), which owns and operates international and domestic projects engaged in the generation and distribution 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. Services Services provides management and administrative and general services to PSEG and its subsidiaries. These include accounting, treasury, risk management, planning, information technology, tax, law, corporate secretarial, human resources, investor relations, corporate communications and certain other services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements. 17
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Basis of Presentation PSEG, PSE&G, Power and Energy Holdings 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, PSE&G’s, Power’s and Energy Holdings’ respective Annual Reports on Form 10-K for the year ended December 31, 2006 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007, as well as in PSEG’s and Energy Holdings’ amended Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2007. The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2006. Reclassifications PSEG, PSE&G, Power and Energy Holdings Certain reclassifications have been made to the prior quarter financial statements to conform to the current quarter presentation. The reclassifications relate primarily to PSE&G’s determination, during the fourth quarter of 2006, that the revenues and expenses related to one of its contracts that had been recorded on a gross basis would more appropriately be recorded on a net basis in Operating Revenues based upon the provisions of Emerging Issues Task Force (EITF) 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Therefore, prior amounts have been reclassified, resulting in reductions of $46 million and $147 million in both Operating Revenues and Energy Costs for the quarter and nine months ended September 30, 2006, respectively, for PSEG and PSE&G, with no impact on Operating Income. 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, PSE&G, Power and /or Energy Holdings. Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157) PSEG, PSE&G, Power and Energy Holdings 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. While this statement does not require any new fair value measurements, the application of this statement will change current practice for some fair value measurements. This statement also nullifies the guidance in footnote 3 of EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). The guidance in footnote 3 applies to derivative instruments measured at fair value at initial recognition, and it precludes immediate recognition in earnings of an 18
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS unrealized gain or loss, measured as the difference between the transaction price and the fair value of the instrument at initial recognition, if the fair value of the instrument is determined using significant unobservable inputs. Under EITF 02-3, an entity cannot recognize an unrealized gain or loss at inception of a derivative instrument unless the fair value of that instrument is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data. SFAS 157 requires that the principles of fair value measurement apply for derivatives and other financial instruments at initial recognition and in all subsequent periods. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. PSEG, PSE&G, Power and Energy Holdings are currently assessing the potential impact of SFAS 157 on their respective consolidated financial positions and results of operations. SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) PSEG, PSE&G, Power and Energy Holdings In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity will report unrealized gains and losses on items where the fair value option has been elected in earnings at each subsequent reporting date. 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 about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and the decision is required to be applied to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative effect adjustment to the opening balance of Retained Earnings. PSEG, PSE&G, Power and Energy Holdings are currently assessing the potential impact SFAS 159 may have on their respective consolidated financial positions and results of operations. FASB Staff Position (FSP) No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FSP 39-1) PSEG and Power In April 2007, the FASB issued FSP 39-1, which permits 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. Currently, PSEG and Power offset derivative contracts under master netting arrangements in accordance with FIN 39, “Offsetting of Amounts Related to Certain Contracts,” but do not net these balances with cash collateral positions. Under this FSP, PSEG and Power would be required to net cash collateral with the corresponding net derivative balance or elect to show all fair values gross. FSP 39-1 is effective for fiscal years beginning after November 15, 2007 and must be applied retroactively to all financial statements presented, unless it is impracticable to do so. PSEG and Power are currently evaluating the potential impact of FSP 39-1 on their respective financial positions. PSEG and Power expect no impact to their respective results of operations. 19
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following new accounting standards were adopted by PSEG, PSE&G, Power and Energy Holdings during 2007. FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48) PSEG, PSE&G, Power and Energy Holdings In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company has taken or expects to take on a tax return. Under FIN 48, the financial statements reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the position and all relevant facts. FIN 48 permits recognition of the benefit of tax positions only when it is “more likely-than-not” that the position is sustainable based on the merits of the position. It further limits the amount of tax benefit to be recognized to the largest amount of benefit that is greater than 50% likely of being realized. FIN 48 also requires disclosures about uncertainties in income tax positions, including a detailed roll-forward of unrecognized tax benefits taken that do not qualify for financial statement recognition. FIN 48 was effective January 1, 2007. In general, companies recorded the change in net assets that resulted from the application of FIN 48 as an adjustment to Retained Earnings. However, for PSE&G, because any charges to income arising from the adoption of FIN 48 should be recoverable in future rates, the offset to any incremental PSE&G liability was recorded as a Regulatory Asset rather than an adjustment to Retained Earnings. The following table presents the impact at January 1, 2007 on the Condensed Consolidated Balance Sheets for PSEG and its subsidiaries as a result of implementing FIN 48: PSE&G Power Energy PSEG Balance Sheet (Millions) Increase to Long-Term Accrued Taxes $ 26 $ 21 $ 355 $ 402 Decrease to Accumulated Deferred Income Tax Liability $ 15 $ 7 $ 246 $ 268 Increase to Regulatory Assets $ 11 $ — $ — $ 11 Decrease to Retained Earnings $ — $ 14 $ 109 $ 123 The after-tax expense resulting from the adoption of FIN 48 for the quarter and nine months ended September 30, 2007 are summarized as follows: Quarter Ended Nine Months Ended (Millions) PSEG $ 6 $ 16 Power $ 1 $ 4 Energy Holdings $ 5 $ 12 There was no impact on earnings for PSE&G. For additional information relating to the impacts of FIN 48, see Note 11. Income Taxes. In May 2007, the FASB issued FSP No. FIN 48-1, which provides guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. The adoption of this FSP did not have a material impact on the financial statements of PSEG, PSE&G, Power or Energy Holdings. FSP No. FAS 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” (FSP 13-2) PSEG and Energy Holdings In July 2006, the FASB issued FSP 13-2, which addressed how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the accounting by a lessor for that lease. The FSP amended SFAS 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually or more frequently, if events or circumstances indicate a change in timing is probable. If a change in timing has 20
(UNAUDITED)
Holdings
Consolidated
September 30, 2007
September 30, 2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease. The guidance in this FSP was adopted on January 1, 2007. The cumulative effect of applying the provisions of this FSP was reported as an adjustment to the beginning balance of Retained Earnings as of the date of adoption. As a result of implementing FSP 13-2, upon adoption PSEG and Energy Holdings each recognized a reduction in Investment in Leveraged Leases of $69 million, a reduction in Deferred Income Taxes of $2 million and a reduction in Retained Earnings of $67 million. The impact to earnings resulting from the adoption of FSP 13-2 for the quarter and nine months ended September 30, 2007 was an after-tax decrease of $3 million and $9 million, respectively, for both PSEG and Energy Holdings. Note 3. Discontinued Operations, Dispositions and Impairments Discontinued Operations Power Lawrenceburg Energy Center (Lawrenceburg) On May 16, 2007, Power completed the sale of Lawrenceburg, a 1,096-megawatt (MW), gas-fired combined cycle electric generating plant located in Lawrenceburg, Indiana, to AEP Generating Company, a subsidiary of American Electric Power Company, Inc. 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. Lawrenceburg’s operating results for the quarter and nine months ended September 30, 2007 and 2006, which were reclassified to Discontinued Operations, are summarized below: Quarters Nine Months 2007 2006 2007 2006 (Millions) Operating Revenues $ — $ 34 $ — $ 40 Income (Loss) Before Income Taxes $ 2 $ (4 ) $ (13 ) $ (33 ) Net Income (Loss). $ 1 $ (2 ) $ (8 ) $ (19 ) The carrying amounts of the assets of Lawrenceburg as of December 31, 2006 are summarized in the following table: As of (Millions) Current Assets $ 10 Noncurrent Assets 315 Total Assets of Discontinued Operations $ 325 Energy Holdings Electroandes S.A. (Electroandes) On September 19, 2007, Global entered into an agreement for the sale of Electroandes, a hydro-electric generation and transmission company in Peru that owns and operates four hydro-generation plants with total capacity of 180 MW and 437 miles of electric transmission lines. The purchaser is a wholly owned subsidiary of Statkraft Norfund Power Invest of Norway. The sale was completed on October 17, 2007 for a total purchase price of approximately $390 million (subject to working capital and other adjustments), including the assumption of approximately $105 million of debt. Net cash proceeds, after taxes and including dividends 21
(UNAUDITED)
Ended
September 30,
Ended
September 30,
December 31,
2006
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS paid prior to closing, were approximately $220 million, which will result in an after-tax gain of approximately $65 million being recorded in the fourth quarter of 2007. The 2007 and 2006 operating results for Electroandes have been reclassified to Discontinued Operations. In conjunction with the reclassification to Discontinued Operations, Electroandes recorded a $19 million income tax expense in the second quarter of 2007 related to the discontinuation of applying Accounting Principles Board (APB) Opinion No. 23, “Accounting for Income Taxes—Special Areas,” as the income generated by Electroandes is no longer expected to be indefinitely reinvested. Electroandes’ operating results for the quarter and nine months ended September 30, 2007 and 2006 are summarized below: Quarters Nine Months 2007 2006 2007 2006 (Millions) Operating Revenues. $ 14 $ 15 $ 38 $ 44 Income Before Income Taxes $ 7 $ 5 $ 14 $ 14 Net Income (Loss) $ 5 $ 4 $ (9 ) $ 9 The carrying amounts of the assets of Electroandes as of September 30, 2007 and December 31, 2006 are summarized in the following table: As of As of (Millions) Current Assets $ 23 $ 25 Noncurrent Assets 274 272 Total Assets of Discontinued Operations $ 297 $ 297 Current Liabilities. $ 7 $ 9 Noncurrent Liabilities 127 125 Total Liabilities of Discontinued Operations $ 134 $ 134 Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina) On May 29, 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $228 million net of tax expense of $142 million. The 2006 operating results for Global’s assets in Poland have been reclassified to Discontinued Operations. Elcho’s and Skawina’s operating results for the nine months ended September 30, 2006 are summarized below: Nine Months Ended Elcho Skawina (Millions) Operating Revenues. $ 39 $ 44 (Loss) Income Before Income Taxes $ (3 ) $ 2 Net (Loss) Income $ (2 ) $ 1 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 22
(UNAUDITED)
Ended
September 30,
Ended
September 30,
September 30,
2007
December 31,
2006
September 30, 2006
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheet. In April 2007, Power sold the four turbines to a third party and received proceeds of $40 million, which approximated the recorded book value. Energy Holdings Global Chilquinta Energia S.A. (Chilquinta) and Luz del Sur S.A.A. (LDS) In October 2007, Global entered into an agreement to sell its 50% ownership interest in Chilquinta, an electric distribution company in Chile, and its 38% ownership of LDS, an electric distribution company in Peru to a subsidiary of AEI (formerly Ashmore Energy International), for approximately $685 million. Global expects to close the transaction by the end of 2007. Sempra Energy International Holdings BV (Sempra), Global’s partner in these investments, owns the remaining 50% of Chilquinta and an equal 38% stake in LDS (the remaining ownership of LDS is publicly traded on the Lima stock exchange). Sempra has a contractual right of first refusal for a limited period of time to purchase, on the same terms, the shares that are subject to the agreement with AEI. The tax expense resulting from the transaction is expected be equal to or slightly in excess of the pre-tax gain on the transaction. Net cash proceeds, after taxes, are expected to total between $480 million to $500 million. Thermal Energy Development Partnership, L.P. (Tracy Biomass) On December 22, 2006, Global entered into an agreement to sell its 34.5% interest in Tracy Biomass for $7 million. The sale closed on January 26, 2007 and resulted in a 2007 pre-tax gain of $7 million ($6 million after-tax). Rio Grande Energia S. A. (RGE) On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in a pre-tax write-down of $263 million ($178 million after-tax), primarily related to the devaluation of the Brazilian Real subsequent to Global’s acquisition of its interests in RGE in 1997. EGDC In August 2007, EGDC sold its Largo property for $12 million which approximated the recorded book value. EGDC received cash proceeds of $9 million and a note receivable for $3 million. Impairment Energy Holdings Venezuela PSEG has indirect ownership interests in two generating facilities in Maracay and Cagua, Venezuela that have a total capacity of 120 MW. The projects are owned and operated by Turboven Company Inc. (Turboven), an entity which is jointly-owned by Global (50%) and Corporacion Industrial de Energia (CIE). Global also has a 9% indirect interest in Turbogeneradores de Maracay through a partnership with CIE. During Global’s 2006 year-end review of its investments, management concluded that due to the current political situation in Venezuela, it was probable that Global would not be able to recover all of its investment in its Venezuelan operations. Therefore, Global recorded an impairment loss of $4 million, after-tax, to write down these investments in the fourth quarter of 2006. In January 2007, the Venezuelan government announced its intention to nationalize certain sectors of Venezuelan industry and commerce, including certain foreign-owned energy and communications companies. 23
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In a subsequent press release, Turboven was named as one of the companies that Venezuela intended to nationalize. Since these announcements, Venezuela has proceeded to nationalize certain companies. Global has entered into valuation discussions with the government of Venezuela as part of the nationalization efforts, which are ongoing. Based upon a recent review of the circumstances, an additional impairment charge of $7 million, after tax, was recorded in September 2007. 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 under PSEG’s stock option plans and upon payment of performance units. The following table shows the effect of these stock options and performance units on the weighted average number of shares outstanding used in calculating diluted EPS: Quarters Ended September 30, Nine Months Ended September 30, 2007 2006 2007 2006 Basic Diluted Basic Diluted Basic Diluted Basic Diluted EPS Numerator: Earnings (Millions) Continuing Operations $ 500 $ 500 $ 372 $ 372 $ 1,127 $ 1,127 $ 569 $ 569 Discontinued Operations 6 6 2 2 (17 ) (17 ) 217 217 Net Income $ 506 $ 506 $ 374 $ 374 $ 1,110 $ 1,110 $ 786 $ 786 EPS Denominator (Thousands): Weighted Average Common Shares Outstanding 254,272 254,272 251,747 251,747 253,603 253,603 251,471 251,471 Effect of Stock Options — 273 — 490 — 355 — 599 Effect of Stock Performance Units — — — 92 — 25 — 91 Total Shares 254,272 254,545 251,747 252,329 253,603 253,983 251,471 252,161 Earnings Per Share: Continuing Operations $ 1.97 $ 1.97 $ 1.47 $ 1.47 $ 4.45 $ 4.44 $ 2.26 $ 2.26 Discontinued Operations 0.02 0.02 0.01 0.01 (0.07 ) (0.07 ) 0.86 0.86 Net Income $ 1.99 $ 1.99 $ 1.48 $ 1.48 $ 4.38 $ 4.37 $ 3.12 $ 3.12 Dividend payments on common stock for the quarters ended September 30, 2007 and 2006 were $149 million ($0.585 per share) and $144 million ($0.57 per share), respectively. Dividend payments on common stock for the nine months ended September 30, 2007 and 2006 were $445 million ($1.755 per share) and $430 million ($1.71 per share), respectively. 24
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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 September 30, 2007 and December 31, 2006 was approximately $1.4 billion and $1.6 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 $483 million and $518 million as of September 30, 2007 and December 31, 2006, respectively. Power is subject to counterparty collateral calls related to commodity contracts and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts. As of September 30, 2007 and December 31, 2006, Power had the following margin posted and received to satisfy collateral obligations and support various contractual and environmental obligations, which were primarily in the form of letters of credit: As of As of (Millions) Margin Posted $ 151 $ 40 Margin Received $ 60 $ 86 Power also routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of September 30, 2007 and December 31, 2006, Power had deposited margin of $121 million and $89 million, respectively. In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide further performance assurance. Exchange-traded transactions that are margined and monitored separately from physical trading activity may not be subject to change in the event of a downgrade to Power’s rating. As of September 30, 2007, 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 25
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September 30,
2007
December 31,
2006
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to $588 million. Power believes that it has sufficient liquidity to post such collateral, if necessary. Energy Holdings Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects. Global also has a contingent guarantee that will expire in April 2011 related to debt service obligations associated with Chilquinta Energia S.A., an energy distribution company in Chile in which Global owns 50%. As of September 30, 2007 and December 31, 2006, the contingent guarantee was $25 million. In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies for which exposure is adequately supported by the outstanding letters of credit for PSEG Energy Technologies Asset Management Company LLC. As of September 30, 2007 and December 31, 2006, there were $14 million of such bonds outstanding, which are related to uncompleted construction projects. As of September 30, 2007 and December 31, 2006, there was an additional $2 million of performance guarantees related to Energy Technologies. As of September 30, 2007 and December 31, 2006, Energy Holdings and/or Global had various other guarantees amounting to $20 million and $30 million, respectively. Environmental Matters Hazardous Substances Power Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), 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. In January 2002, Power reached an agreement with the New Jersey Department of Environmental Protection (NJDEP) and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. On November 30, 2006, Power reached an agreement with the EPA and the NJDEP on an amendment to its 2002 agreement intended to achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson. The amended agreement with the EPA and the NJDEP, which received final approval from the U.S. District Court in New Jersey in May 2007, allows Power to continue operating Hudson and extends for four years the deadline for installing environmental controls beyond the previous December 31, 2006 deadline. 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 NOx, SO2, particulate matter and mercury. In July 2007, Power notified the EPA and the NJDEP that it will proceed with the installation of the additional emissions controls at Hudson, which are to be completed by the end of 2010. Under the program, Power has installed selective catalytic reductions at Mercer at a cost of $122 million. The cost of implementing the balance of the amended agreement is estimated at approximately $475 million 26
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS to $525 million for Mercer and $700 million to $750 million for Hudson and will be incurred by the end of 2010. Pursuant to the agreement, Fossil purchased and retired emissions allowances by July 31, 2007, paid a $6 million civil penalty and will contribute $3 million for programs to reduce particulate emissions from diesel engines in New Jersey. In March 2007, Fossil entered into an engineering, procurement and construction contract with a third party contractor to complete all back-end technology requirements for the Mercer station, as referenced above. Fossil signed a contract for construction management related to the Hudson back-end technology construction in July 2007. As a result of the agreement, Power’s environmental reserves include $3 million to account for the particulate matter reduction program. PSEG and Power recorded the charge in Other Deductions on their respective Condensed Consolidated Statements of Operations in the fourth quarter of 2006. Mercury Regulation New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The regulations in New Jersey require the units to meet certain emissions limits or reduce emissions by 90% by December 15, 2007. 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 are 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 a facility-specific control plan. Power believes, but cannot guarantee, that this filing will allow for the continued operation of both Mercer Units while baghouses are installed. Installation of the baghouses 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 the amended 2002 agreement that resolved issues arising out of the PSD and the 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 by the end of 2007. In February 2007, Pennsylvania finalized its “State-specific” requirements to reduce mercury emissions from coal-fired electric generating units. Currently, the regulations would not materially affect the costs already identified in Power’s capital expenditures forecast. The estimated costs of technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut and at its Mercer and Hudson Stations are included in Power’s capital expenditures 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. Natural Resource Damages PSEG, PSE&G and Power 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 27
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 PSE&G and Power, 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 approximately $20 million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. In 2006, the EPA notified the PRPs that the cost of its study will greatly exceed the $20 million initially estimated and after discussion, approximately 70 PRPs, including PSE&G and Power, 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 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%. Power has provided notice to insurers concerning this potential claim. In June 2007, the EPA announced a 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. 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 NJDEP requires persons conducting remediation to characterize injuries to natural resources and to address those injuries through restoration or damages. The NJDEP has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. In 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the Spill Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. On August 2, 2007, the National Oceanic and Atmospheric Administration of the United States Department of Commerce sent a letter to PSE&G and other companies identified as PRPs notifying them that it intended to perform an assessment of injuries to natural resources and inviting the PRPs to participate. The PRPs have not agreed to participate. Newark Bay Study Area The EPA sent PSE&G and eleven 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. 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 PSE&G 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 28
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS generating stations that PSE&G transferred to it, including the Hudson and Kearny Sites. Power has provided notice to insurers concerning this potential claim. PSE&G and Power are unable to estimate the cost of the investigation at this time. Other On June 29, 2007, the State of New Jersey filed multiple lawsuits against parties, including PSE&G, who were alleged to be responsible for injuries to natural resources in New Jersey, including a site being remediated under PSE&G’s MGP program. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, Newark Bay or other natural resource damages claims; however, such costs could be material. PSE&G MGP Remediation Program PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have been identified as sites requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. Specifically, 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 a former MGP 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. Since the inception of the Remediation Program in 1988 through September 30, 2007, PSE&G has had expenditures of $411 million. Based on the most recent estimates, the cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered in two rivers adjacent to two former MGP sites, could range between $798 million and $838 million, including amounts spent to date. No amount within the range was considered to be most likely. Therefore, $387 million was accrued as of September 30, 2007, which represents the difference between the low end of the total program cost estimate of $798 million and the total incurred costs through September 30, 2007 of $411 million. Of this amount, $54 million was recorded in Other Current Liabilities and $333 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $387 million Regulatory Asset was recorded. Costs for the Remediation Program were $42 million for 2006. PSE&G anticipates spending $47 million in 2007, $50 million in 2008, and an average of approximately $40 million per year each year thereafter through 2016. Power 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 September 30, 2007 and December 31, 2006 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 Federal Water 29
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. The U.S. Court of Appeals for the Second Circuit (Second Circuit Court) issued a decision after Power filed its application that rejected the use of restoration and the site-specific cost-benefit test under the Phase II 316(b) rule. On May 25, 2007, Power and other industry petitioners filed with the Second Circuit Court a request for a rehearing. In July 2007, the Second Circuit Court denied the request. Power will file a petition requesting that the U.S. Supreme Court review the matter, but can not predict whether it will be granted. 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 court cannot be determined at this time for all of Power’s facilities. Depending on the outcome of the petition to the Supreme Court, or actions by the EPA to promulgate a revised rule, this 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, New Haven and Bridgeport, 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 those five once-through cooled facilities, the related costs and impacts would be material to Power’s financial position, results of operations and net cash flows. For example, Power’s application to renew the permit, filed in February 2006 with the NJDEP, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of which Power’s share would be approximately $575 million. Potential costs associated with any closed-cycle cooling requirements are not included in Power’s currently forecasted capital expenditures. Energy Holdings Bioenergie S.p.A. (Bioenergie) In May 2006, Global became the majority shareholder of Bioenergie (formerly known as Prisma 2000 S.p.A.). Among other holdings, Bioenergie holds 100% of the stock of San Marco Bioenergie S.p.A. (San Marco), owner of a 20 MW biomass generation facility in Italy. Global also assumed operational responsibility for the facility in May 2006, which was previously operated by Carlo Gavazzi Green Power pursuant to a Services Agreement with a Global subsidiary. Global’s total investment in Bioenergie is approximately $71 million. In August 2006, Global became aware that the Italian government was conducting a criminal investigation regarding allegations of violations of the San Marco facility’s air permit. The scope of the investigation was subsequently expanded to include alleged violations of the facility’s waste recycling and waste storage permits. The Italian government has named five individuals as targets of the criminal investigation, including three former San Marco employees and two former members of the facility’s Board of Directors. San Marco has not been named as a target. In December 2006 and January 2007, the facility was served with orders suspending its operations. San Marco has fully cooperated with the Prosecuting Attorney regarding the ongoing investigation and has implemented the corrective actions designed to prevent recurrence of the violations. On April 26, 2007, the Prosecutor issued an order returning control of the plant to San Marco. The facility became fully operational during the third quarter of 2007. 30
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS New Generation and Development Power Power plans to modestly increase its generating capacity at Hope Creek and Salem Unit 2 in 2008. Phase I of the Hope Creek turbine replacement increased the capacity by 10 MW in 2005, and Phase II, which is expected to add approximately 125 MW of capacity, is expected to be completed in the second quarter of 2008 along with the Extended Power Uprate (EPU). Actions are expected to be completed during the fourth quarter 2007 refueling outage at Hope Creek to facilitate an online EPU implementation in the second quarter of 2008 upon receipt of NRC approval. Phase I of the Salem Unit 2 turbine upgrade increased Power’s share of the capacity by 14 MW in 2003. Phase II is currently scheduled for the spring of 2008, concurrent with steam generator replacement and is anticipated to increase Power’s share of the capacity by an additional 15 MW. As of September 30, 2007, Power’s expenditures for these projects were $191 million (including Interest Capitalized During Construction (IDC) of $22 million) with an aggregate estimated share of total costs for these projects of $211 million (including IDC of $23 million). Completion of the projects discussed above within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases, regulatory approvals and various other factors could result in changes in the operational dates or ultimate costs to complete. Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G and Power PSE&G is required to obtain all 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 (LSE) 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. Through the BGS auctions, PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows: Term Ending May May May May Term 34 months 36 months 36 months 36 months Load (MW) 2,840 2,840 2,882 2,758 $ per kWh $ 0.05515 $ 0.06541 $ 0.10251 $ 0.09888
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2007(a)
2008(b)
2009(c)
2010(d)
| ||||||||||||||||||||
(a) |
| Prices set in the February 2004 BGS auction. | ||||||||||||||||||
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(b) |
| Prices set in the February 2005 BGS auction. | ||||||||||||||||||
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(c) |
| Prices set in the February 2006 BGS auction. | ||||||||||||||||||
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(d) |
| Prices set in the February 2007 BGS auction. | ||||||||||||||||||
Power seeks to mitigate volatility in its results by contracting in advance for its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power enters into firm supply contracts with EDCs, as well as other firm sales and commitments.
31
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. 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 13. Related-Party Transactions. The BPU is currently conducting an audit of the gas procurement practices of all four New Jersey gas utilities, including PSE&G. The outcome of this proceeding cannot be predicted. Minimum Fuel Purchase Requirements Power Coal and Oil Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The coal purchase commitments through 2009 amount to approximately 90% of its average anticipated coal needs, including transportation. Total coal purchase commitments, including transportation, are approximately $1.1 billion extending through 2012. Nuclear Fuel 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 and uranium hexafluoride) to meet 100% of its total estimated requirements through 2011. Power has commitments for concentrates covering approximately 80% of its estimated requirements for 2012, 30% from 2013 through 2014 and 20% through 2016. Additionally, Power has commitments for uranium hexafluoride to meet 45% of its estimated requirements for 2012 and 20% from 2013 through 2016. These commitments, based on current market prices, which have increased substantially over the past two to three years, total approximately $490 million ($355 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 2010 that total approximately $230 million ($160 million Power’s estimated share). Power has commitments for the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek that total approximately $125 million ($90 million Power’s estimated share). Exelon Generation LLC (Exelon) has informed Power that the Peach Bottom plant has inventory and commitments to purchase sufficient quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of its total estimated requirements through 2010. Additionally, Exelon has commitments covering approximately 80% of its estimated requirements for 2011 and 45% for 2012. Exelon also has commitments that provide 100% of its uranium enrichment requirements for the Peach Bottom plant in 2008, 2010 and 2012. Additionally, Peach Bottom has a 93% commitment in 2009 and an 81% commitment in 2011. Exelon has commitments for the fabrication of fuel assemblies for reloads required through 2012 for Peach Bottom. In total, the Exelon commitment for nuclear fuel, conversion, enrichment and fabrication totals $593 million ($297 million Power’s estimated share). Natural Gas In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G. 32
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of September 30, 2007, the total minimum requirements under these contracts were approximately $1 billion through 2016. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Energy Holdings The Texas generation facilities have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of September 30, 2007, the plants had fuel purchase commitments totaling $137 million to support all of their contracted energy sales. Operating Services Contract (OSC) Power On January 17, 2005, Nuclear entered into an OSC with Exelon relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon to provide key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has used to manage its own nuclear facilities. Nuclear continues as the license holder with exclusive legal authority to operate and maintain the plants, retains responsibility for management oversight and has full authority with respect to the marketing of its share of the output from the facilities. Exelon is entitled to receive reimbursement of its costs in discharging its obligations, an annual operating services fee of $3 million and incentive fees up to $12 million annually based on attainment of goals relating to safety, capacity factor and operation and maintenance expenses. On October 27, 2006, Nuclear informed Exelon that it was electing to continue the OSC for up to two years beyond January 2007. In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations. As part of this plan, on January 1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon, became employees of Power. Power has continued to recruit additional employees to build its organizational structure. Power is implementing a plan to fully resume functions that Exelon currently performs, which Power expects will put it in a position to terminate the OSC by the end of 2007. Maintenance Agreement Power Power entered into a long-term contractual services agreement with a vendor in September 2003 to provide the outage and service needs for certain of Power’s generating units at market rates. The contract covers 25 years and could result in annual payments ranging from $10 million to $50 million for services, parts and materials rendered. Investment Tax Credits (ITC) PSEG and PSE&G As of June 1999, the Internal Revenue Service (IRS) had 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, were terminated upon New Jersey’s electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC liability relating to PSE&G’s generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New Jersey. Subsequently, PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002. 33
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS On May 11, 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 the normalization rules. On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by a BPU order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun. On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal. While the holding in the PLR is favorable for PSE&G, an outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter a position set out in certain December 21, 2005 proposed regulations. PSEG and PSE&G cannot determine the final outcome of this matter until the final Treasury regulations are issued. BPU Deferral Audit PSEG and PSE&G 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 (NUG) deferred balances. The BPU released the report on May 13, 2005. While the consultant to the BPU found that the Phase II deferral balances complied in all material respects with the BPU Orders regarding such deferrals, the consultant noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The amount in dispute is approximately $130 million. On January 31, 2007, PSE&G requested that the matter be transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the request on February 7, 2007. On May 25, 2007, PSE&G filed a Motion for Summary Judgment requesting dismissal of the matter. On September 28, 2007, the Administrative Law Judge issued an initial decision denying PSE&G’s motion and ordering the filing of testimony and evidentiary hearings. The BPU Staff and New Jersey Public Advocate’s Division of Rate Counsel have both asserted in briefs that $130 million be refunded to ratepayers. 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 impact of the outcome of this proceeding. New Jersey Clean Energy Program PSE&G 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 $90 million and $72 million for the nine months ended September 30, 2007 and 2006, respectively. The remaining liability has been recorded at a discounted present value with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC. The liability for the funding requirement as of September 30, 2007 and December 31, 2006 was $174 million and $253 million, respectively. 34
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Leveraged Lease Investments PSEG and Energy Holdings On November 16, 2006, the IRS issued a report with respect to its audit of PSEG’s corporate tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain of Resources’ lease transactions that are similar to a type that the IRS publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability. In February 2007, PSEG filed a protest to the Office of Appeals of the IRS. As of September 30, 2007 and December 31, 2006, Resources’ total gross investment in such transactions was approximately $1.5 billion. If all deductions associated with these lease transactions, entered into by PSEG between 1997 and 2002, are successfully challenged by the IRS, it would have a material adverse impact on PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is properly based on applicable statutes, regulations and case law and will aggressively contest the IRS’ disallowance. PSEG believes that it is more likely than not that it will prevail with respect to the IRS’ challenge, although no assurances can be given. If the IRS’ disallowance of tax benefits associated with all of these lease transactions was sustained, $853 million of PSEG’s deferred tax liabilities that have been recorded under leveraged lease accounting through September 30, 2007 would become currently payable. In addition, as of September 30, 2007 interest of approximately $166 million, after-tax, and penalties of $165 million may become payable, with potential additional interest and penalties of approximately $17 million accruing quarterly. Energy Holdings’ management has assessed the probability of various outcomes to this matter and recorded the tax effect to be realized in accordance with FIN 48. For additional information and guidance for leveraged leases, see Note 2. Recent Accounting Standards. Superintendencia Nacional de Administracion Tributaria (SUNAT) Energy Holdings Luz del Sur S.A.A. (LDS) In January 2007, SUNAT, the governing taxing authority in Peru, filed two tax assessments against LDS totaling $18 million, of which Global’s share would be $7 million based on its 38% interest in LDS. The assessments relate to deductions LDS claimed beginning in 2000 for certain operating fees it paid to International Technical Operators under a technical services agreement for certain bad debt deductions and certain other matters. The assessments include interest and penalties claimed by SUNAT. LDS believes that most of such deductions were appropriate and filed an appeal in February 2007. LDS believes it has valid legal defenses to these claims and that it should be successful in contesting these material items/disallowances; however, no assurances can be given regarding the outcome of this matter. Note 6. Financial Risk Management Activities PSEG, PSE&G, Power and Energy Holdings The operations of PSEG, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings uses derivative instruments as risk management tools consistent with its respective business plan and prudent business practices. 35
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Derivative Instruments and Hedging Activities Commodity Contracts Power Power actively transacts in 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 the Northeastern and Mid Atlantic United States. 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, futures and FTRs. Higher market prices for electricity and capacity at September 30, 2007 versus December 31, 2006 have resulted in additional unrealized losses on many of these contracts leading to an increase in Accumulated Other Comprehensive Loss (OCL). Power marks its derivative energy-related contracts to market in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133) with changes in fair value charged to the Condensed Consolidated Statements of Operations (except certain contracts that are designated as effective hedges or contracts that qualify for the normal purchases and normal sales exception). Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results. 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 September 30, 2007, the fair value of these hedges was $(338) million and along with realized losses on hedges of $(4) million retained in OCL, resulted in $(201) million after-tax recorded in OCL. As of December 31, 2006, the fair value of these hedges was $(166) million. These hedges, along with realized losses on hedges of $(19) million retained in OCL, resulted in a $(108) million after-tax balance in OCL. The increase of $93 million in OCL during the nine months ended September 30, 2007 was caused mainly by higher electricity market prices. During the 12 months ending September 30, 2008, $144 million after-tax of net unrealized and realized losses on these commodity derivatives is expected to be reclassified to earnings. Approximately $50 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ending September 30, 2009. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(3) million as of September 30, 2007. The expiration date of the longest-dated cash flow hedge is in 2010. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. These contracts are used primarily for fuel purchases for generation and BGSS requirements and for electricity purchases for contractual sales obligations and a minor portion is used in Power’s Nuclear Decommissioning Trust Funds. 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 Condensed Consolidated Statements of Operations. The net fair value of these instruments as of September 30, 2007 was $(10) million. The net fair value of these instruments as of December 31, 2006 was $(2) million. 36
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Holdings Other Derivatives The Texas generation facilities enter into electricity forward and capacity sales contracts to sell portions of their 2,000 MW capacity through 2010, with the balance sold into the daily spot market. The Texas generation facilities 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 the Texas generation facilities, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value. The net fair value of the open positions was $55 million and $38 million as of September 30, 2007 and December 31, 2006, respectively. Interest Rates PSEG, PSE&G, Power and Energy Holdings PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives. Fair Value Hedges PSEG and Power In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of September 30, 2007 and December 31, 2006, the fair value of the hedge was $(4) million and $(9) million, respectively. Cash Flow Hedges PSEG, PSE&G and Energy Holdings PSEG, PSE&G and Energy Holdings 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 OCL. As of September 30, 2007, the fair value of these cash flow hedges was $(3) million and $(3) million at PSE&G and Energy Holdings, respectively. As of December 31, 2006, the fair value of these cash flow hedges was $(4) million, primarily at PSE&G. The $(3) million and $(4) million at PSE&G as of September 30, 2007 and December 31, 2006, respectively, is not included in OCL, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the 12 months ending September 30, 2008, approximately $1 million of net unrealized losses (net of taxes) on interest rate derivatives is expected to be reclassified to earnings at Energy Holdings. During the next 12 months, less than $1 million of unrealized losses (net of taxes) on interest rate derivatives in OCL is expected to be reclassified at PSEG. As of September 30, 2007, there was no hedge ineffectiveness associated with these hedges. Foreign Currencies Energy Holdings Global is exposed to foreign currency risk and other foreign operation risks that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered into monetary 37
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Peruvian Nuevo Sol and the Chilean Peso and to a lesser extent, the Euro. Changes in valuation of these currencies can impact the value of Global’s investments, results of operations, financial condition and cash flows. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global may also use foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations. Although the Chilean Peso and the Peruvian Nuevo Sol had originally depreciated relative to the U.S. Dollar after Global’s initial investments, the currencies have appreciated significantly over the past few years. The net cumulative foreign currency revaluations have increased the total amount of Energy Holdings’ Member’s Equity by $189 million as of September 30, 2007. Hedges of Net Investments in Foreign Operations Energy Holdings In March and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated with the exposure in the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(30) million and $(25) million as of September 30, 2007 and December 31, 2006, respectively. The change in fair value of the majority of the swaps is recorded in Cumulative Translation Adjustment within OCL. As a result, Energy Holdings’ Member’s Equity was reduced by $27 million as of September 30, 2007. Note 7. Comprehensive Income (Loss), Net of Tax PSE&G Power Energy Other(A) Consolidated (Millions) For the Quarter Ended September 30, 2007: Net Income (Loss) $ 107 $ 339 $ 71 $ (11 ) $ 506 Other Comprehensive Income — 52 32 2 86 Comprehensive Income (Loss) $ 107 $ 391 $ 103 $ (9 ) $ 592 For the Quarter Ended September 30, 2006: Net Income (Loss) $ 88 $ 205 $ 101 $ (20 ) $ 374 Other Comprehensive Income (Loss). 1 204 1 — 206 Comprehensive Income (Loss) $ 89 $ 409 $ 102 $ (20 ) $ 580 For the Nine Months Ended September 30, 2007: Net Income (Loss) $ 302 $ 736 $ 118 $ (46 ) $ 1,110 Other Comprehensive (Loss) Income. — (73 ) 51 3 (19 ) Comprehensive Income (Loss) $ 302 $ 663 $ 169 $ (43 ) $ 1,091 For the Nine Months Ended September 30, 2006: Net Income (Loss) $ 200 $ 394 $ 251 $ (59 ) $ 786 Other Comprehensive Income 1 383 192 — 576 Comprehensive Income (Loss) $ 201 $ 777 $ 443 $ (59 ) $ 1,362 38
(UNAUDITED)
Holdings
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Accumulated Other Comprehensive Income (Loss) Balance as of PSE&G Power Energy Other (A) Balance as of (Millions) For the Nine Months Ended Derivative Contracts. $ (114 ) $ — $ (92 ) $ (1 ) $ — $ (207 ) Pension and OPEB Plans. (214 ) — 8 — 2 (204 ) Currency Translation Adjustment 110 — — 52 — 162 NDT Funds 108 — 11 — — 119 Other 2 — — — 1 3 $ (108 ) $ — $ (73 ) $ 51 $ 3 $ (127 ) Balance as of PSE&G Power Energy Other (A) Balance as of (Millions) For the Nine Months Ended Derivative Contracts $ (626 ) $ — $ 374 $ 54 $ — $ (198 ) Pension and OPEB Plans (11 ) 1 1 — — (9 ) Currency Translation Adjustment (44 ) — — 138 — 94 NDT Funds 72 — 8 — — 80 $ (609 ) $ 1 $ 383 $ 192 $ — $ (33 )
(UNAUDITED)
December 31,
2006
Holdings
September 30,
2007
September 30, 2007:
December 31,
2005
Holdings
September 30,
2006
September 30, 2006:
| ||||||||||||||||||||
(A) |
| Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations. | ||||||||||||||||||
Note 8. Changes in Capitalization
PSEG
In May 2007, PSEG redeemed the outstanding $375 million of its Floating Rate Notes Due 2008 at 100% of the principal amount.
For the nine months ended September 30, 2007, PSEG issued 1,077,122 shares of its common stock in connection with settling stock options under its Long-Term Incentive Plan (LTIP) for $48 million.
For the nine months ended September 30, 2007, PSEG issued 405,890 shares of its common stock under its Dividend Reinvestment and Stock Purchase Plan (DRASPP) and Employee Stock Purchase Plan (ESPP) for $34 million.
PSE&G
On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds.
On May 14, 2007, PSE&G issued $350 million of 5.80% Secured Medium Term Notes Series E due 2037. The proceeds were used to reduce short-term debt.
In September 2007, PSE&G paid cash dividends to PSEG of $100 million.
In September 2007, June 2007 and March 2007, PSE&G Transition Funding LLC (Transition Funding) repaid $43 million, $36 million and $38 million, respectively, of its transition bonds.
In June 2007, PSE&G Transition Funding II LLC (Transition Funding II) repaid $4 million of its transition bonds.
39
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power Power paid cash dividends to PSEG of $125 million, $450 million and $250 million in March 2007, June 2007 and September 2007, respectively. Energy Holdings In March 2007, Energy Holdings made a cash distribution to PSEG of $145 million in the form of a return of capital. In August 2007, Sociedad Austral de Electricidad S.A., a wholly owned subsidiary of Global, issued 3.80% bonds (approximately 7%, including current inflationary adjustment) for net proceeds of $163 million with a final maturity of June 30, 2028. The proceeds were used principally to repay loans due to Energy Holdings which then loaned the funds to PSEG for short-term funding. During the first nine months of 2007, Energy Holdings’ subsidiaries repaid $35 million of non-recourse debt, including $31 million by Global, primarily related to the Texas generation facilities, $2 million by Resources and $2 million by EGDC. 40
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 9. Other Income and Deductions
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other(A)
Consolidated
Total
(Millions)
Other Income:
For the Quarter Ended September 30, 2007:
Interest and Dividend Income
$
2
$
5
$
2
$
(2
)
$
7
NDT Fund Realized Gains
—
37
—
—
37
NDT Interest and Dividend Income
—
12
—
—
12
Gain on Sale of Property, Plant and Equipment
2
—
—
—
2
Change in Derivative Fair Value
—
—
2
—
2
Other
(2
)
2
1
—
1
Total Other Income
$
2
$
56
$
5
$
(2
)
$
61
For the Quarter Ended September 30, 2006:
Interest and Dividend Income
$
3
$
3
$
13
$
(9
)
$
10
NDT Fund Realized Gains
—
20
—
—
20
NDT Interest and Dividend Income
—
10
—
—
10
Other
3
5
—
—
8
Total Other Income
$
6
$
38
$
13
$
(9
)
$
48
For the Nine Months Ended September 30, 2007:
Interest and Dividend Income
$
8
$
20
$
7
$
(9
)
$
26
NDT Fund Realized Gains
—
102
—
—
102
NDT Interest and Dividend Income
—
37
—
—
37
Arbitration Award (Konya-Ilgin)
—
—
9
—
9
Change in Derivative Fair Value
—
—
3
—
3
Gain on Sale of Property, Plant and Equipment
2
—
—
—
2
Minority Interest
—
—
—
2
2
Other
2
3
4
—
9
Total Other Income
$
12
$
162
$
23
$
(7
)
$
190
For the Nine Months Ended September 30, 2006:
Interest and Dividend Income
$
9
$
10
$
22
$
(12
)
$
29
NDT Fund Realized Gains
—
69
—
—
69
NDT Interest and Dividend Income
—
29
—
—
29
Foreign Currency Gains
—
—
2
—
2
Change in Derivative Fair Value
—
—
2
—
2
Other
9
5
4
—
18
Total Other Income
$
18
$
113
$
30
$
(12
)
$
149
41
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSE&G Power Energy Other(A) Consolidated (Millions) Other Deductions: For the Quarter Ended September 30, 2007: NDT Fund Realized Losses and Expenses $ — $ 26 $ — $ — $ 26 Other-Than-Temporary Impairment of Investments — 16 — — 16 Donations 1 — — 1 2 Foreign Currency Losses — — 6 — 6 Change in Derivative Fair Value — — 4 — 4 Other — — 1 2 3 Total Other Deductions $ 1 $ 42 $ 11 $ 3 $ 57 For the Quarter Ended September 30, 2006: Donations $ — $ — $ — $ 1 $ 1 NDT Fund Realized Losses and Expenses — 12 — — 12 Foreign Currency Losses — — 2 — 2 Change in Derivative Fair Value — — — — — Loss on Extinguishment of Debt — — 12 — 12 Environmental Reserves — 14 — — 14 Total Other Deductions $ — $ 26 $ 14 $ 1 $ 41 For the Nine Months Ended September 30, 2007: Donations $ 2 $ — $ — $ 6 $ 8 NDT Fund Realized Losses and Expenses — 62 — — 62 Other-Than-Temporary Impairment of Investments — 40 — — 40 Foreign Currency Losses — — 9 — 9 Change in Derivative Fair Value — — 5 — 5 Loss on Disposition of Assets — 2 — — 2 Other 1 1 1 1 4 Total Other Deductions $ 3 $ 105 $ 15 $ 7 $ 130 For the Nine Months Ended September 30, 2006: Donations $ 2 $ — $ — $ 1 $ 3 NDT Fund Realized Losses and Expenses — 44 — — 44 Foreign Currency Losses — — 5 — 5 Change in Derivative Fair Value — — 3 — 3 Minority Interest — — — 1 1 Loss on Extinguishment of Debt — — 12 — 12 Loss on Disposition of Assets — 1 — — 1 Environmental Reserves — 14 1 — 15 Total Other Deductions $ 2 $ 59 $ 21 $ 2 $ 84
(UNAUDITED)
Holdings
Total
| ||||||||||||||||||||
(A) |
| Other consists of reclassifications for minority interests in PSEG’s consolidated results of operations and intercompany eliminations at PSEG (as parent company). | ||||||||||||||||||
42
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 10. Pension and Other Postretirement Benefits (OPEB) PSEG PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. Pension Benefits OPEB Pension Benefits OPEB Quarters Quarters Nine Months Ended Nine Months Ended 2007 2006 2007 2006 2007 2006 2007 2006 (Millions) Components of Net Periodic Benefit Costs: Service Cost $ 20 $ 22 $ 4 $ 4 $ 62 $ 65 $ 12 $ 13 Interest Cost 55 53 18 17 163 158 54 51 Expected Return on Plan Assets (72 ) (65 ) (3 ) (2 ) (216 ) (199 ) (10 ) (8 ) Amortization of Net Transition Obligation — — 7 7 — — 21 21 Prior Service Cost 2 3 3 4 8 8 9 10 Loss 5 14 2 2 15 41 6 6 Net Periodic Benefit Costs 10 27 31 32 32 73 92 93 Effect of Regulatory Asset — — 4 4 — — 14 14 Total Benefit Costs $ 10 $ 27 $ 35 $ 36 $ 32 $ 73 $ 106 $ 107 PSE&G, Power, Energy Holdings and Services Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows: Pension Benefits OPEB Pension Benefits OPEB Quarters Quarters Nine Months Ended Nine Months Ended 2007 2006 2007 2006 2007 2006 2007 2006 (Millions) PSE&G $ 4 $ 14 $ 30 $ 31 $ 14 $ 37 $ 90 $ 91 Power 3 8 4 4 9 22 12 12 Energy Holdings — 1 — — 1 2 — — Services 3 4 1 1 8 12 4 4 Total PSEG Consolidated Benefit Costs $ 10 $ 27 $ 35 $ 36 $ 32 $ 73 $ 106 $ 107 43
Ended
September 30,
Ended
September 30,
September 30,
September 30,
Ended
September 30,
Ended
September 30,
September 30,
September 30,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) An analysis of the tax provision expense is as follows: PSE&G Power Energy Other (A) Consolidated (Millions) For the Quarter Ended September 30, 2007: Income (Loss) Before Income Taxes $ 181 $ 571 $ 83 $ (21 ) $ 814 Tax Computed at the Statutory Rate 63 200 29 (7 ) 285 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 12 35 — (2 ) 45 Rate Differential between Foreign/Domestic Operations — — (17 ) — (17 ) Uncertain Tax Positions. — 1 5 — 6 Other (1 ) (3 ) — (1 ) (5 ) Total Income Tax Expense (Benefit) $ 74 $ 233 $ 17 $ (10 ) $ 314 Effective Income Tax Rate 40.9 % 40.8 % 20.5 % 47.6 % 38.6 % For the Quarter Ended September 30, 2006: Income (Loss) Before Income Taxes $ 157 $ 364 $ 115 $ (35 ) $ 601 Tax Computed at the Statutory Rate 55 127 40 (12 ) 210 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 12 23 (3 ) (2 ) 30 Rate Differential between Foreign/Domestic Operations — — (21 ) — (21 ) Plant-Related Items 4 — — — 4 Other (2 ) 7 2 (1 ) 6 Total Income Tax Expense (Benefit) $ 69 $ 157 $ 18 $ (15 ) $ 229 Effective Income Tax Rate 43.9 % 43.1 % 15.7 % 42.9 % 38.1 % For the Nine Months Ended September 30, 2007: Income (Loss) Before Income Taxes $ 516 $ 1,263 $ 173 $ (75 ) $ 1,877 Tax Computed at the Statutory Rate 181 442 61 (27 ) 657 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 36 76 (3 ) (4 ) 105 Rate Differential between Foreign/Domestic Operations — — (21 ) — (21 ) Uncertain Tax Positions — 4 11 — 15 Other (3 ) (3 ) — — (6 ) Total Income Tax Expense (Benefit) $ 214 $ 519 $ 48 $ (31 ) $ 750 Effective Income Tax Rate 41.5 % 41.1 % 27.7 % 41.3 % 40.0 % For the Nine Months Ended September 30, 2006: Income (Loss) Before Income Taxes $ 360 $ 717 $ (20 ) $ (100 ) $ 957 Tax Computed at the Statutory Rate 126 251 (7 ) (35 ) 335 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit 27 44 (8 ) (5 ) 58 Rate Differential between Foreign/Domestic Operations — — (25 ) — (25 ) Plant-Related Items 12 — — — 12 Other (5 ) 9 4 — 8 Total Income Tax Expense (Benefit) $ 160 $ 304 $ (36 ) $ (40 ) $ 388 Effective Income Tax Rate 44.4 % 42.4 % NA 40.0 % 40.5 %
Holdings
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. | ||||||||||||||||||
44
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) PSEG, PSE&G, Power and Energy Holdings 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. For additional information, see Note 2. Recent Accounting Standards. Upon adoption, PSEG, PSE&G, Power and Energy Holdings recorded the following amounts related to their respective uncertain tax positions:
PSE&G
Power
Energy
Holdings
Other (B)
PSEG
Consolidated
Unrecognized Tax Benefits (A)
$
55
$
21
$
408
$
1
$
485
Accumulated Deferred Income Taxes associated with Unrecognized Tax Benefits
(15
)
(7
)
(246
)
—
(268
)
Regulatory Asset-Unrecognized Tax Benefits
(11
)
—
—
—
(11
)
Unrecognized Tax Benefits that, if recognized, would impact the effective tax rate (A)
$
29
$
14
$
162
$
1
$
206
Interest and Penalties Accrued.
$
4
$
3
$
82
$
—
$
89
| ||||||||||||||||||||
(A) |
| Includes interest and penalties | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs. | ||||||||||||||||||
There were no material changes to the amounts above during the quarter ended September 30, 2007. Net income for PSEG, Power and Energy Holdings could be impacted by changes to FIN 48 liabilities as determined by changes in substantive tax law and tax audit results. It is reasonably possible that certain unrecognized tax benefits related to certain asset sales that have occurred, or could occur in the future, may become recognized within the next 12 months. The amount of such benefits that may become recognized within the next 12 months is approximately $11 million. This amount has not been reflected in any gain or loss computations. PSEG, PSE&G, Power and Energy Holdings include all accrued interest and penalties required to be recorded under FIN 48 as income tax expense.
Income tax years for PSEG, PSE&G, Power and Energy Holdings that remain subject to examination by material jurisdictions, where an examination has not already concluded, are as follows:
|
|
|
|
|
|
|
|
|
| PSE&G | Power | Energy | PSEG | ||||
United States |
|
|
|
|
|
|
|
|
Federal | 2001-2006 | 2001-2006 | 2001-2006 | 2001-2006 | ||||
New Jersey | 2001-2006 | N/A | 1997-2006 | 1997-2006 | ||||
Pennsylvania | 2003-2006 | N/A | 2003-2006 | 2003-2006 | ||||
Connecticut | N/A | N/A | N/A | 2003-2006 | ||||
Texas | N/A | N/A | 2006 | 2006 | ||||
California | N/A | N/A | 2002-2006 | 2002-2006 | ||||
Indiana | N/A | N/A | N/A | 2003-2006 | ||||
Ohio | N/A | N/A | N/A | 2003-2005 | ||||
Foreign |
|
|
|
|
|
|
|
|
Chile | N/A | N/A | 2004-2006 | 2004-2006 | ||||
Peru | N/A | N/A | 2002-2006 | 2002-2006 |
45
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 12. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below: PSE&G Power Energy Holdings Other (B) Consolidated Resources Global Other (A) (Millions) For the Quarter Ended September 30, 2007: Total Operating Revenues. $ 2,106 $ 1,580 $ 40 $ 338 $ 2 $ (591 ) $ 3,475 Income (Loss) from Continuing Operations 107 338 15 52 (1 ) (11 ) 500 Income from Discontinued Operations, net of tax — 1 — 5 — — 6 Net Income (Loss) 107 339 15 57 (1 ) (11 ) 506 Preferred Securities Dividends. (1 ) — — — — 1 — Segment Earnings (Loss) 106 339 15 57 (1 ) (10 ) 506 Gross Additions to Long-Lived Assets 125 178 — 5 — 6 314 For the Quarter Ended September 30, 2006: Total Operating Revenues. $ 1,971 $ 1,455 $ 40 $ 343 $ 2 $ (514 ) $ 3,297 Income (Loss) from Continuing Operations 88 207 10 88 (1 ) (20 ) 372 (Loss) Income from Discontinued Operations, net of tax — (2 ) — 4 — — 2 Net Income (Loss) 88 205 10 92 (1 ) (20 ) 374 Preferred Securities Dividends (1 ) — — — — 1 — Segment Earnings (Loss) 87 205 10 92 (1 ) (19 ) 374 Gross Additions to Long-Lived Assets 133 123 — 17 — 2 275 For the Nine Months Ended September 30, 2007: Total Operating Revenues. $ 6,340 $ 5,034 $ 119 $ 837 $ 6 $ (2,448 ) $ 9,888 Income (Loss) from Continuing Operations 302 744 46 83 (2 ) (46 ) 1,127 Loss from Discontinued Operations, net of tax — (8 ) — (9 ) — — (17 ) Net Income (Loss) 302 736 46 74 (2 ) (46 ) 1,110 Preferred Securities Dividends (3 ) — — — — 3 — Segment Earnings (Loss) 299 736 46 74 (2 ) (43 ) 1,110 Gross Additions to Long Lived Assets 421 501 — 33 1 17 973 For the Nine Months Ended September 30, 2006: Total Operating Revenues $ 5,754 $ 4,551 $ 133 $ 896 $ 7 $ (2,055 ) $ 9,286 Income (Loss) from Continuing Operations 200 413 49 (31 ) (3 ) (59 ) 569 (Loss) Income from Discontinued Operations, net of tax — (19 ) — 8 — — (11 ) Gain on Disposal of Discontinued Operations, net of tax — — — 228 — — 228 Net Income (Loss) 200 394 49 205 (3 ) (59 ) 786 Preferred Securities Dividends (3 ) — — — — 3 — Segment Earnings (Loss) 197 394 49 205 (3 ) (56 ) 786 Gross Additions to Long Lived Assets 392 316 — 36 1 3 748 46
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) PSE&G Power Energy Holdings Other (B) Consolidated Total Resources Global Other (A) (Millions) As of September 30, 2007: Total Assets $ 14,440 $ 8,014 $ 2,949 $ 3,211 $ 316 $ (21 ) $ 28,909 Investments in Equity Method Subsidiaries $ — $ 18 $ 7 $ 832 $ — $ — $ 857 As of December 31, 2006: Total Assets $ 14,553 $ 8,146 $ 2,969 $ 3,095 $ 100 $ (293 ) $ 28,570 Investments in Equity Method Subsidiaries $ — $ 16 $ 5 $ 817 $ — $ — $ 838
| ||||||||||||||||||||
(A) |
| Energy Holdings’ other activities include amounts applicable to Energy Holdings (as parent company) and EGDC. The net losses primarily relate to financing and certain administrative and general costs of Energy Holdings. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| PSEG’s other activities include amounts applicable to PSEG (as parent corporation), 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 13. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at PSEG, as parent corporation. | ||||||||||||||||||
Note 13. Related-Party Transactions
The majority of the following discussion relates to intercompany transactions. These transactions were 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
PSE&G and Power
The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Power’s Billings for the | |||||||||||||||||||||||||||
| Quarters | Nine Months Ended | ||||||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||
BGS |
| $ |
| 408 |
| $ |
| 330 |
| $ |
| 889 |
| $ |
| 594 | ||||||||||||
BGSS |
| $ |
| 173 |
| $ |
| 175 |
| $ |
| 1,537 |
| $ |
| 1,435 | ||||||||||||
As of September 30, 2007 and December 31, 2006, Power had net receivables from PSE&G of $183 million and $367 million, respectively, primarily related to the BGS and BGSS contracts. In addition, as of September 30, 2007 and December 31, 2006, PSE&G had a payable to Power of $100 million and $177 million, respectively, related to gas supply hedges Power entered into for BGSS.
47
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Services PSE&G, Power and Energy Holdings Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below: Services’ Billings for the Quarters Ended Nine Months Ended Payable to Services as of 2007 2006 2007 2006 September 30, December 31, (Millions) PSE&G $ 58 $ 50 $ 165 $ 158 $ 35 $ 41 Power $ 34 $ 29 $ 101 $ 99 $ 18 $ 21 Energy Holdings $ 4 $ 4 $ 14 $ 13 $ 2 $ 2 PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services. Tax Sharing Agreements PSEG, PSE&G, Power and Energy Holdings PSE&G, Power and Energy Holdings had payables to PSEG related to taxes as follows: Payable to PSEG as of September 30, December 31, (Millions) PSE&G $ 29 $ 63 Power $ 35 $ 28 Energy Holdings $ 6 $ 10 As a result of the adoption of FIN 48, PSE&G, Power and Energy Holdings each recorded payables to PSEG related to uncertain tax positions. See Note 2. Recent Accounting Standards. Such amounts as of September 30, 2007 were as follows: Payable to PSEG (Millions) PSE&G $ 61 Power $ 28 Energy Holdings $ 449 Affiliate Loans and Advances PSEG and Power As of September 30, 2007, Power had a demand note receivable of $37 million due from PSEG. As of December 31, 2006, Power had a demand note payable to PSEG of $54 million for short-term funding needs. PSEG and Energy Holdings As of September 30, 2007 and December 31, 2006, Energy Holdings had a demand note receivable due from PSEG of $257 million and $28 million, respectively. These notes reflect the investment of Energy Holdings’ excess cash with PSEG. 48
September 30,
September 30,
2007
2006
2007
2006
as of
September 30, 2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) PSE&G and Services As of each of September 30, 2007 and December 31, 2006, 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 September 30, 2007 and December 31, 2006, Power had advanced working capital to Services of $17 million. This amount is included in Other Noncurrent Assets on Power’s Condensed Consolidated Balance Sheets. Other PSEG and PSE&G As of September 30, 2007 and December 31, 2006, PSE&G had net receivables from PSEG of $1 million and $3 million, respectively, related to amounts that PSEG had collected on PSE&G’s behalf. PSEG and Power As of September 30, 2007 and December 31, 2006, Power had net receivables from PSEG of $2 million and less than $1 million, respectively, related to amounts that PSEG had collected on Power’s behalf. Energy Holdings and PSE&G As of each of September 30, 2007 and December 31, 2006, Energy Holdings had a receivable of $1 million related to efficiency incentive initiatives performed for PSE&G’s customers. Energy Holdings recorded revenues for such services of $1 million and $2 million for the quarters ended September 30, 2007 and 2006, respectively, and $3 million and $9 million for the nine months ended September 30, 2007 and 2006, respectively. 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 September 30, 2007: Revenues $ — $ 1,830 $ 23 $ (273 ) $ 1,580 Operating Expenses — 1,227 25 (272 ) 980 Operating Income (Loss) — 603 (2 ) (1 ) 600 Equity Earnings (Losses) of Subsidiaries 339 (8 ) — (331 ) — Other Income 48 71 — (63 ) 56 Other Deductions — (42 ) — — (42 ) Interest Expense (47 ) (46 ) (13 ) 63 (43 ) Income Tax (Expense)/Benefit (1 ) (239 ) 5 2 (233 ) Gain (Loss) on Discontinued Operations, net of Tax Benefit (Expense) — — 2 (1 ) 1 Net Income (Loss) $ 339 $ 339 $ (8 ) $ (331 ) $ 339 49
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Power Guarantor Other Consolidating Consolidated (Millions) For the Quarter Ended September 30, 2006: Revenues $ — $ 1,680 $ 33 $ (258 ) $ 1,455 Operating Expenses — 1,295 46 (277 ) 1,064 Operating Income (Loss) — 385 (13 ) 19 391 Equity Earnings (Losses) of Subsidiaries 204 (9 ) — (195 ) — Other Income 44 49 4 (59 ) 38 Other Deductions — (27 ) — 1 (26 ) Interest Expense (45 ) (42 ) (35 ) 83 (39 ) Income Tax Benefit/(Expense) 2 (158 ) 19 (20 ) (157 ) Income/(Loss) on Discontinued Operations — 8 18 (28 ) (2 ) Net Income (Loss) $ 205 $ 206 $ (7 ) $ (199 ) $ 205 For the Nine Months Ended September 30, 2007: Revenues $ — $ 5,789 $ 77 $ (832 ) $ 5,034 Operating Expenses — 4,464 77 (832 ) 3,709 Operating Income — 1,325 — — 1,325 Equity Earnings (Losses) of Subsidiaries 744 (30 ) — (714 ) — Other Income 148 202 — (188 ) 162 Other Deductions — (105 ) — — (105 ) Interest Expense (156 ) (114 ) (36 ) 187 (119 ) Income Tax (Expense)/Benefit — (534 ) 14 1 (519 ) Loss on Discontinued Operations — — (7 ) (1 ) (8 ) Net Income (Loss) $ 736 $ 744 $ (29 ) $ (715 ) $ 736 For the Nine Months Ended September 30, 2006: Revenues $ — $ 5,269 $ 103 $ (821 ) $ 4,551 Operating Expenses 1 4,518 82 (820 ) 3,781 Operating (Loss) Income (1 ) 751 21 (1 ) 770 Equity Earnings (Losses) of Subsidiaries 402 (32 ) — (370 ) — Other Income 126 138 5 (156 ) 113 Other Deductions — (59 ) (1 ) 1 (59 ) Interest Expense (142 ) (88 ) (33 ) 156 (107 ) Income Tax Benefit/(Expense) 9 (314 ) 2 (1 ) (304 ) Income/(Loss) on Discontinued Operations — 8 (27 ) — (19 ) Net Income (Loss) $ 394 $ 404 $ (33 ) $ (371 ) $ 394 For the Nine Months Ended September 30, 2007: Net Cash Provided By (Used In) Operating Activities $ 1,175 $ 1,398 $ (45 ) $ (1,480 ) $ 1,048 Net Cash (Used In) Provided By Investing Activities $ (335 ) $ (653 ) $ (55 ) $ 870 $ (173 ) Net Cash (Used In) Provided By Financing Activities $ (840 ) $ (749 ) $ 100 $ 610 $ (879 ) 50
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Power Guarantor Other Consolidating Consolidated (Millions) For the Nine Months Ended September 30, 2006: Net Cash Provided By (Used In) Operating Activities $ 318 $ 1,303 $ 10 $ (711 ) $ 920 Net Cash Provided By (Used In) Investing Activities $ 182 $ (1,237 ) $ 29 $ 737 $ (289 ) Net Cash Used In Financing Activities $ (500 ) $ (69 ) $ (39 ) $ (26 ) $ (634 ) As of September 30, 2007 Current Assets $ 2,318 $ 3,729 $ 351 $ (4,448 ) $ 1,950 Property, Plant and Equipment, net 149 3,541 892 — 4,582 Investment in Subsidiaries 3,824 179 — (4,003 ) — Noncurrent Assets 183 1,519 35 (255 ) 1,482 Total Assets $ 6,474 $ 8,968 $ 1,278 $ (8,706 ) $ 8,014 Current Liabilities $ 126 $ 4,332 $ 1,003 $ (4,450 ) $ 1,011 Noncurrent Liabilities 283 812 96 (253 ) 938 Long-Term Debt 2,818 — — — 2,818 Member’s Equity 3,247 3,824 179 (4,003 ) 3,247 Total Liabilities and Member’s Equity $ 6,474 $ 8,968 $ 1,278 $ (8,706 ) $ 8,014 As of December 31, 2006 Current Assets $ 1,982 $ 3,416 $ 531 $ (3,441 ) $ 2,488 Property, Plant and Equipment, net 150 3,226 854 — 4,230 Investment in Subsidiaries 4,287 201 — (4,488 ) — Noncurrent Assets 173 1,398 79 (222 ) 1,428 Total Assets $ 6,592 $ 8,241 $ 1,464 $ (8,151 ) $ 8,146 Current Liabilities $ 97 $ 3,179 $ 1,251 $ (3,443 ) $ 1,084 Noncurrent Liabilities 253 776 12 (220 ) 821 Long-Term Debt 2,818 — — — 2,818 Member’s Equity 3,424 4,286 201 (4,488 ) 3,423 Total Liabilities and Member’s Equity $ 6,592 $ 8,241 $ 1,464 $ (8,151 ) $ 8,146 51
Subsidiaries
Subsidiaries
Adjustments
Total
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) Following are the significant changes in or additions to information reported in the 2006 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with such Statements and Notes. This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company. OVERVIEW OF 2007 AND FUTURE OUTLOOK PSEG, PSE&G, Power and Energy Holdings PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C. (Resources). The following discussion relates to the markets in which PSEG’s subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that have occurred during the first nine months of 2007 and future outlook for PSE&G, Power and Energy Holdings, as well as the key factors that will drive the future performance of these businesses. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. The BPU approved rate increases for both gas and electric distribution service in November 2006. Per terms of a settlement, PSE&G is required to file a joint gas and electric petition for any future base rate increases and no base rate changes may become effective before November 15, 2009. Overview and Future Outlook In February 2007, the BPU approved the results of New Jersey’s annual Basic Generation Service (BGS)-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price (CIEP) auctions and PSE&G successfully secured contracts to provide the electricity requirements for the majority of its customers’ needs. The Governor of New Jersey has directed the BPU, in partnership with other New Jersey agencies, to develop an Energy Master Plan (EMP) that reduces energy consumption while emphasizing energy efficiency, conservation and renewable energy resources to meet New Jersey’s future energy demands in a manner designed to reduce CO2 emissions to 1990 levels by 2020. In conjunction with these efforts, on April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. Under the plan, PSE&G would invest approximately $100 million over two years following BPU approval to help finance the installation of solar systems throughout its service area. If approved by the BPU, the initiative could begin by the end of 2007 and support 30 MW of solar power in the following two years, fulfilling approximately 50% of the BPU’s Renewable Portfolio Standard (RPS) requirements in PSE&G’s service area for 2009 and 2010. On July 12, 2007, the BPU established a schedule for consideration of this proposal. Meetings have been held and interveners have filed testimony with the BPU. On June 8, 2007, PSE&G endorsed the construction of three new 500 kV transmission lines intended to significantly improve the reliability of the electrical grid serving New Jersey customers. On June 22, 2007, PJM Interconnection, L.L.C. (PJM)’s Board of Managers approved construction of one of the proposed lines and assigned construction responsibility to PSE&G, Pennsylvania Power and Light (PPL) and FirstEnergy Corporation (FirstEnergy) for their respective service territories. On October 9, 2007, PJM provided a formal 52
letter notification to PSE&G identifying PSE&G as the responsible party for the construction of both its portion of the new line and the portion originally assigned to FirstEnergy. The estimated cost of PSE&G’s portion of this construction project is between $550 million and $650 million. PSE&G’s costs will go into transmission rate base, subject to regulatory approval, and can be expected to have a positive impact on revenues and earnings for PSE&G. PSE&G expects the FERC rate mechanisms will allow for collection of these costs during construction. In addition, the U.S. Department of Energy (DOE) has now designated the Mid-Atlantic Area Corridor, which encompasses all of New Jersey, as a transmission corridor to which FERC back-stop eminent domain authority will attach. The two other lines which PSE&G has endorsed have not yet been submitted to PJM for approval, as required by PJM rules, but PSE&G believes that construction of these lines, which would follow existing transmission rights-of-way, are needed to enhance the reliability of the transmission system and to relieve congestion within New Jersey. On June 1, 2007, new electric BGS-Fixed Price FP rates went into effect with an expected increase of approximately 12% to residential customers’ bills. Also on June 1, 2007, PSE&G filed for a 2% increase in the Basic Gas Supply Service (BGSS) gas rate effective October 1, 2007. PSE&G is awaiting a decision by the Office of Administrative Law (OAL) and has the ability to put in place two self- implementing BGSS increases on December 1, 2007 and February 1, 2008 of up to 5% and also may reduce the BGSS rate at any time. The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. PSE&G’s success will depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels, continue recovery of the regulatory assets it has deferred and attain an adequate return on the investments it plans to make in its electric and gas transmission and distribution system and the level of recovery of distribution revenues in light of customer demand and conservation efforts. FERC’s ruling regarding PJM long-term transmission rate design, which remains subject to rehearing, benefits PSE&G customers by preserving lower rates than would likely be in effect under proposed rate design modifications. Since PSE&G earns no margin on the commodity portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G; however, commodity costs continue to put upward pressure on customer charges. Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market in the Northeast and Mid Atlantic U.S. Power’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. ER&T and Fossil’s subsidiary, PSEG Power Connecticut LLC, sell power at wholesale under FERC-approved market-based rate tariffs. Certain subsidiaries of Fossil are subject to state regulation and Nuclear is also subject to regulation by the Nuclear Regulatory Commission. Through its subsidiaries, Power seeks to produce low-cost energy through efficient operations of its nuclear, coal and gas-fired generation facilities, balance its generation production, fuel requirements and supply obligations through energy portfolio management and pursue disciplined growth. In addition to the electric generation business, Power’s revenues include gas supply sales under the Basic Gas Supply Service (BGSS) contract with PSE&G. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the availability of Power’s diverse fleet of generation units to produce these products as well as the prices of commodities, such as electricity, gas, nuclear fuel, coal and emissions, can have a material effect on Power’s profitability. In recent years, the prices at which transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM West, have escalated considerably over historical prices. Broad market price increases such as these are expected to have a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced over 50% and 25% of Power’s production, respectively. With the vast majority of its power sourced from these lower-cost units, the rise in electric prices is anticipated to yield higher near-term margins for Power. Over a longer- term horizon, if these higher prices are sustained at levels reflective of what the current forward markets indicate, Power would have an attractive environment in which to contract for the sale of its anticipated output, allowing for potentially sustained higher profitability than recognized in prior years. These prices also increase the cost of replacement power, thereby placing incremental risk on the 53
operations of the generating units to produce these products. Further, changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output, capacity and fuel needs. Power believes this contracting strategy increases stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some exposure to market changes as well as provide some protection in the event of unexpected generation outages. Power seeks to sell a portion of its anticipated nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to three years. By contrast, Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched only when aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or coal units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments. In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. At the present time, some of Power’s existing contractual obligations, entered into during lower-priced periods, are anticipated to result in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market. Overview and Future Outlook During the first nine months of 2007, Power continued to benefit from strong energy markets and sustained improvement in the performance of its generating facilities. Going forward, Power expects margin improvements to continue as higher prices for its nuclear and coal-fired generation output are realized due to the rolling nature of its forward hedge positions and the expiration of older power contracts. In PJM, the Reliability Pricing Model (RPM) provides generators with capacity payments for the reliability provided by their respective facilities. The Forward Capacity Market (FCM) in the New England Power Pool provides for similar reliability-based capacity payments. FERC has approved the market changes in each of these markets, beginning on June 1, 2007 for the RPM transition period and on December 1, 2006 for the FCM transition period. On April 13, 2007, July 13, 2007 and October 12, 2007, respectively, PJM announced the results of its base residual auctions for the 2007–2008, 2008–2009 and 2009–2010 delivery years. The prices received by generation assets, including those of Power, located within the Eastern Mid Atlantic Area Council (MAAC) zone, the MAAC plus Allegheny Power System zone (MAAC + APS) and the rest of PJM, (other than within the Eastern MAAC, MAAC + APS and Southwest MAAC zones (Rest of Pool)) cleared at the prices listed in the following table. Delivery Year Zones June 1, 2007 to June 1, 2008 to June 1, 2009 to MW-day kW-yr MW-day kW-yr MW-day kW-yr Eastern MAAC $ 197.67 $ 72.15 $ 148.80 $ 54.31 $ 191.32 $ 69.83 MAAC + APS (A) $ — $ — $ — $ — $ 191.32 $ 69.83 Rest of Pool $ 40.80 $ 14.89 $ 111.92 $ 40.85 $ 97.82 $ 35.70
May 31, 2008
May 31, 2009
May 31, 2010
| ||||||||||||||||||||
(A) |
| not a separate pool until the 2009–2010 auction. | ||||||||||||||||||
The capacity price that will be charged to load serving entities for obligations in the Eastern MAAC zone is $177.51/MW-day ($65/kW-yr) in the 2007–2008 delivery year, $143.51/MW-day ($56/kW-yr) in the 2008–2009 delivery year and $188.32/MW-day ($69/kW-yr) in the 2009-2010 delivery year.
As a normal part of its contracting strategy, Power enters into contracts to sell capacity for future delivery. One such contract is New Jersey’s BGS contract, which is fixed rate and includes several energy-related components, one of which is capacity. As a result, only a portion of Power’s capacity was open to realize prices in the recent RPM auctions in PJM since a significant portion of Power’s capacity was
54
contracted as part of the three-year BGS auctions in which Power had won 11 tranches in 2005, 20 tranches in 2006 and 19 tranches in 2007, as well as other contracting activity. On average, each of these fixed-price BGS tranches requires approximately 120 MW of capacity on a daily basis. Power anticipates increasing capacity amounts available to realize auction prices for future years as its existing contracts roll off. The balance of Power’s PJM capacity has obtained price certainty through May 31, 2010 as a result of the first three RPM auctions. Power has also obtained price certainty for all of its capacity in New England through May 31, 2010 as a result of the fixed price nature of the transitional FCM auction. On a prospective basis, many factors will affect the pricing for capacity in PJM, including but not limited to: •
changes in demand;
•
changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.);
•
increases in transmission capability between zones; and
•
changes to the pricing mechanism created by PJM, including increasing the potential number of zones to as many as 24 zones in future years, which could create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM may propose over time.
Management cannot predict what pricing will result from future auctions.
In October 2007, Power announced that it has initiated planning activities with respect to the construction of up to 400 MW of new gas-fired peaking capacity that could be available to bid into PJM’s RPM base residual auctions in 2008 for supply beginning as early as 2010. Power estimates that the cost of this new construction could range from $250 million to $350 million. Power has requested that PJM perform a feasibility study to determine the impact to the grid of adding a total of 1,000 MW of new gas-fired capacity at some of its existing generating stations located in the constrained Eastern MAAC reliability region. Power’s final decision whether or not to proceed with construction of any of these units will depend, in part, on estimated capital and interconnection costs, available siting and Power’s ability to meet environmental permitting requirements. None of the costs related to these units are included in Power’s forecasted capital expenditures.
A key factor in Power’s ability to achieve its objectives is its ability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to satisfy its obligations. Power’s ability to achieve its objectives will also depend on the continuation of reasonable capacity markets. Power must also be able to effectively manage its construction projects and continue to economically operate its generation facilities under increasingly stringent environmental requirements, including legislation, regulation and voluntary restrictions to address:
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• |
| the control of carbon 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 intake structures and cooling systems at its larger once-through cooled plants, including Salem, Hudson, Mercer, New Haven and Bridgeport. | ||||||||||||||||||
Power has two large environmental back-end technology projects underway at its Mercer and Hudson coal plants aggregating approximately $1.2 billion in capital costs. These projects are scheduled to be completed by the end of 2010. Power is focused on completing these projects on schedule and within the budgets established for them, but faces all the risks typically involved in managing large construction projects.
In addition, with an increase in competition and market complexity and constantly changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. For additional information on liquidity requirements, see Liquidity and Capital Resources.
Power could also be impacted by a number of market and regulatory events, including regulatory or legislative actions favoring non-competitive markets, energy efficiency initiatives, and regulatory policies favoring the construction of rate-based transmission that may result in increased imports of generation, which may be subject to less stringent environmental regulation, into areas served by Power’s generation assets. Further, some of the market-based mechanisms in which Power participates, including BGS auctions and
55
RPM capacity payments, are currently the subject of review or discussion by some of the participants in the New Jersey and federal regulatory and political arenas and the PJM market monitor. Power can provide no assurance that these mechanisms will continue to exist in their current form for the foreseeable future. Energy Holdings Energy Holdings’ operations are principally conducted through its subsidiaries—Global, which has invested in international rate-regulated distribution companies and domestic and international generation companies, and Resources, which primarily invests in energy-related, leveraged leases. Global Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in select domestic and international markets. During 2007, Energy Holdings has continued to reduce its investments in international markets with the sale of Electroandes which was completed on October 17, 2007, and the expected close on the sale of Chilquinta Energia S.A. (Chilquinta) and Luz del Sur S.A.A. (LDS), discussed below. Global’s domestic operations continue to perform well and provide the opportunity for growth. As a merchant generation business with a load-following asset profile, the results of Global’s Texas generation facilities are driven by changes in market conditions, particularly projected market heat rates and weather. Its results are also impacted by the recognition of unrealized mark-to-market (MTM) gains and losses on fixed-price contracts that expire in 2010. Beginning in December 2008, ERCOT will transition from a zonal market to a nodal wholesale market. The redesigned grid will consist of more than 4,000 nodes replacing the current four congestion management zones. The implementation of the nodal market design is expected to deliver improved price signals, improved dispatch efficiencies and direct assignment of local congestion. Energy Holdings is currently evaluating the potential impact this change will have on its Texas generation facilities. 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. Resources’ investments, net of deferred taxes, are approximately $1.1 billion, approximately 90% of which relates to energy-related leveraged leases. Resources also continues to own interests in three airplanes, which are under lease to Northwest Airlines (Northwest) for an aggregate book value investment of $38 million as of September 30, 2007. In July 2007, Resources received a stock distribution from Northwest as a result of its bankruptcy proceedings, and recorded income of $7 million. Resources’ future performance is subject to tax risks related to its lease transactions. See Note 5. Commitments and Contingent Liabilities of the Notes for further discussion. Overview and Future Outlook Energy Holdings’ margins have decreased at Global in 2007 relative to 2006 primarily relating to the lower MTM gains at the Texas generation facilities, scheduled maintenance outages at the Texas generation facilities that were completed in the first half of 2007 and the shutdown of the Bioenergie San Marco facility during the first half of 2007. Also contributing to the decrease are higher taxes due to the impact of adopting Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48) and related standards and lower earnings due to asset sales. Energy Holdings continues to review Global’s portfolio, with a focus on optimizing operations at its distribution companies to improve earnings and increase value and will consider opportunistic monetizations, as appropriate, based on valuations and potential alternate uses of capital. In October 2007, Global entered into an agreement to sell its 50% ownership interest in Chilquinta, an electric distribution company in Chile, and its 38% ownership of LDS, an electric distribution company in Peru to a subsidiary of AEI (formerly Ashmore Energy International), for approximately $685 million. Global expects 56
to close the transaction by the end of 2007. With respect to Global’s international generation investments, on September 19, 2007, Global entered into a definitive agreement for the sale of its interests in Electroandes S.A. (Electroandes), its 180 MW hydro-electric generation and transmission company in Peru to a wholly owned subsidiary of Statkraft Norfund Power Invest (SN Power) of Norway. The sale closed on October 17, 2007, for a total purchase price of approximately $390 million (subject to working capital and other adjustments), including the assumption of approximately $105 million of debt. After-tax net cash proceeds, including dividends paid prior to closing, were approximately $220 million. For additional information on Electroandes, Chilquinta and LDS, see Note 3. Discontinued Operations, Dispositions and Impairments. Global is exploring options for its aggregate $128 million equity investment in three other international generation projects, Bioenergie S.p.A. (Bioenergie) in Italy, Turboven Company Inc. (Turboven) in Venezuela and Power Generating Company Limited (PPN) in India. In June 2007, Global restarted Bionergie’s San Marco biomass generation facility after a seven-month outage due to a criminal investigation regarding allegations of violations of the facility’s air permit. With respect to Global’s investment in Turboven, Global recently entered into preliminary valuation discussions with the government of Venezuela as part of the nationalization efforts which are ongoing. Based upon a recent review of the circumstances, an impairment charge of $7 million, after-tax, was recorded in September 2007 to further write down Global’s Venezuelan investments. No assurances can be given as to whether Global can recover the current book value of the investments in Venezuela. Global’s investment in India is currently more stable than in prior years as evidenced by dividend payments of $6 million to date in 2007 and $4 million during 2006. Including the proceeds from the sale of Electroandes, Energy Holdings has over $450 million of available cash, a portion of which has been loaned to PSEG for short-term funding needs. Energy Holdings expects to use a portion of these funds and the funds from the expected closing on the sale of Chilquinta and LDS to repay its $207 million maturity in February 2008 and is evaluating other uses of these proceeds, including other potential debt reduction, loans and/or dividends to PSEG, new investments in domestic generation, including within the renewables sector, and general corporate purposes. Energy Holdings faces risks related to the tax treatment of uncertain tax positions which will be impacted by new accounting guidance under FIN 48 and FASB Staff Position No. FAS 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” (FAS 13-2), both of which were effective as of January 1, 2007. Based on its evaluation of this new guidance, Energy Holdings recorded a reduction to its opening 2007 Retained Earnings of $176 million. In addition, this new guidance will have an impact on Energy Holdings’ future earnings, including an anticipated earnings after-tax reduction of $29 million in 2007, which represents the majority of the anticipated impact on PSEG. Energy Holdings’ future earnings could also be impacted by changes to FIN 48 liabilities as determined by changes in substantive tax law and tax audit results, including resolution of tax audit claims associated with Resources’ leveraged lease transactions. See Note 2. Recent Accounting Standards and Note 5. Commitments and Contingent Liabilities of the Notes for further discussion. 57
The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and nine months ended September 30, 2007 and 2006 are presented below: Earnings (Losses) Quarters Nine Months 2007 2006 2007 2006 (Millions) PSE&G $ 107 $ 88 $ 302 $ 200 Power 338 207 744 413 Energy Holdings: Global (D) 52 88 83 (31 ) Resources. 15 10 46 49 Other (A) (1 ) (1 ) (2 ) (3 ) �� Total Energy Holdings 66 97 127 15 Other (B) (11 ) (20 ) (46 ) (59 ) PSEG Income from Continuing Operations 500 372 1,127 569 Income (Loss) from Discontinued Operations, including Gain on 6 2 (17 ) 217 PSEG Net Income $ 506 $ 374 $ 1,110 $ 786 Earnings Per Share (Diluted) Quarters Nine Months 2007 2006 2007 2006 PSEG Income from Continuing Operations $ 1.97 $ 1.47 $ 4.44 $ 2.26 Income (Loss) from Discontinued Operations, including Gain on 0.02 0.01 (0.07 ) 0.86 PSEG Net Income $ 1.99 $ 1.48 $ 4.37 $ 3.12 (A) Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and certain other administrative and general expenses at Energy Holdings. (B) Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends for PSE&G in 2007 and 2006, merger expenses in 2006, interest on certain financing transactions and certain other administrative and general expenses at PSEG (as parent company) in 2007 and 2006. (C) Includes Discontinued Operations of Electroandes and Lawrenceburg in 2007 and 2006 and the Gain on Disposal of Skawina and Elcho and their Discontinued Operations in 2006. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes. (D) Global’s Income from Continuing Operations for the nine months ended September 30, 2006 includes a $178 million after-tax loss on the sale of its indirect ownership in Rio Grande Energia (RGE) in June 2006. As shown in the table above, PSEG had Income from Continuing Operations of $500 million, or $1.97 per share for the quarter ended September 30, 2007, as compared to Income from Continuing Operations of $372 million, or $1.47 per share for the same quarter in 2006. PSEG’s Net Income for the quarter ended September 30, 2007 was $506 million or $1.99 per share, as compared to Net Income of $374 million, or $1.48 per share for the third quarter of 2006. PSEG had Income from Continuing Operations of $1.127 billion, or $4.44 per share for the nine months ended September 30, 2007, as compared to $569 million, or $2.26 per share for the same period in 2006. PSEG’s Net Income for the nine months ended September 30, 2007 was $1.110 billion or $4.37 per share, as compared to Net Income of $786 million, or $3.12 per share for the same period in 2006. The changes in PSEG’s Income from Continuing Operations and Net Income primarily relate to changes in Net Income for PSE&G, Power and Energy Holdings, discussed below. 58
Ended
September 30,
Ended
September 30,
Disposal (C)
Ended
September 30,
Ended
September 30,
Disposal (C)
PSEG For the Quarters Increase % For the Nine Months Increase % 2007 2006 2007 2006 (Millions) (Millions) Operating Revenues $ 3,475 $ 3,297 $ 178 5 $ 9,888 $ 9,286 $ 602 6 Energy Costs $ 1,674 $ 1,740 $ (66 ) (4 ) $ 5,101 $ 5,223 $ (122 ) (2 ) Operation and Maintenance $ 576 $ 533 $ 43 8 $ 1,774 $ 1,682 $ 92 5 Write-down of Assets $ 12 $ — $ 12 100 $ 12 $ 263 $ (251 ) (95 ) Depreciation and Amortization $ 213 $ 228 $ (15 ) (7 ) $ 603 $ 629 $ (26 ) (4 ) Income from Equity Method Investments. $ 33 $ 30 $ 3 10 $ 86 $ 93 $ (7 ) (8 ) Other Income and Deductions. $ 4 $ 7 $ (3 ) (43 ) $ 60 $ 65 $ (5 ) (8 ) Interest Expense $ (191 ) $ (199 ) $ (8 ) (4 ) $ (560 ) $ (587 ) $ (27 ) (5 ) Income Tax Expense $ (314 ) $ (229 ) $ 85 37 $ (750 ) $ (388 ) $ 362 93 Income (Loss) from Discontinued Operations, including Gain on Disposal in 2006, net of tax $ 6 $ 2 $ 4 N/A $ (17 ) $ 217 $ (234 ) N/A PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power 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 13. Related-Party Transactions of the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow. PSE&G For the quarter ended September 30, 2007, PSE&G had Net Income of $106 million, an increase of $19 million as compared to the quarter ended September 30, 2006. For the nine months ended September 30, 2007, PSE&G had Net Income of $299 million, an increase of $102 million as compared to the same period in 2006. These increases were primarily the result of increased volumes due to weather and price increases resulting from the electric and gas base rate cases settled in November 2006. The detail for the variances is discussed below: For the Quarters Increase % For the Nine Months Increase % 2007 2006 2007 2006 (Millions) (Millions) Operating Revenues $ 2,106 $ 1,971 $ 135 7 $ 6,340 $ 5,754 $ 586 10 Energy Costs $ 1,341 $ 1,250 $ 91 7 $ 4,083 $ 3,725 $ 358 10 Operation and Maintenance $ 308 $ 278 $ 30 11 $ 947 $ 855 $ 92 11 Depreciation and Amortization $ 161 $ 174 $ (13 ) (7 ) $ 449 $ 476 $ (27 ) (6 ) Other Income and Deductions $ 1 $ 6 $ (5 ) N/A $ 9 $ 16 $ (7 ) (44 ) Interest Expense $ (85 ) $ (86 ) $ (1 ) (1 ) $ (250 ) $ (254 ) $ (4 ) (2 ) Income Tax Expense. $ (74 ) $ (69 ) $ 5 7 $ (214 ) $ (160 ) $ 54 34 Operating Revenues PSE&G has three sources of revenue: commodity related revenues from the sales of energy to customers and the sale of energy, capacity and commodity 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 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 59
Ended September 30,
(Decrease)
Ended September 30,
(Decrease)
Ended September 30,
(Decrease)
Ended September 30,
(Decrease)
are set based on the results of these auctions for residential and smaller industrial and commercial customers, and are translated into seasonally-adjusted fixed rates. Electric supply for larger industrial and commercial 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 from or returned to customers in subsequent months. PSE&G also purchases electric commodity from several Non-Utility Generation (NUG) which is resold in the PJM market. Most of the NUG contracts are priced above market under long term contracts. PSE&G recoups the difference in price through the Non-Utility Generation Charge (NGC). The $135 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to increases of $89 million in commodity revenues and $45 million in delivery revenues, described below and $1 million in other operating revenues, primarily related to appliance service contracts. The $586 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was due to increases of $358 million in commodity revenues and $221 million in delivery revenues, described below and $7 million in other operating revenues, primarily related to appliance service contracts. Commodity The $89 million increase in commodity related revenues for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to increases in electric revenues of $106 million and offset by a decrease in gas revenues of $17 million. The increase in electric revenues was due to $117 million in higher BGS revenues (higher auction prices of $133 million offset by decreased sales of $16 million) and $16 million in higher NUG revenues (higher prices of $15 million and increased sales of $1 million), offset by a $27 million decrease in the electric non-utility generation transition charge (NGC) revenues due to a March 2007 rate change. The decrease in gas revenues was primarily due to $13 million in lower BGSS prices and $4 million in decreased sales due to weather. The $358 million increase in commodity related revenues for the nine months ended September 30, 2007, as compared to the same period in 2006, was due to increases in electric revenues of $351 million and gas revenues of $7 million. The increase in electric revenues was due to $394 million in higher BGS revenues (higher auction prices of $365 million plus increased sales of $29 million) and $10 million in higher NUG revenues (higher prices of $22 million offset by decreased sales of $11 million), offset by a $54 million decrease in the electric NGC revenues due to a March 2007 rate change. The increase in gas revenues was primarily due to $139 million in increased sales due to weather offset by $133 million in lower BGSS prices. Delivery The $45 million increase in delivery revenues for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to a $42 million increase in electric and a $3 million increase in gas revenues. The electric increase was due primarily to $28 million for increased Societal Benefits Clause (SBC) rates and $13 million from a rate increase effective November 9, 2006. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below. The gas increase was primarily due to $5 million in the SBC rate increases November 1, 2006 and March 9, 2007 and $3 million in rate relief effective November 9, 2006 offset by $4 million in reduced sales. The $221 million increase in delivery revenues for the nine months ended September 30, 2007, as compared to the same period in 2006, was due to a $117 million increase in electric and a $104 million increase in gas revenues. The electric increase was due primarily to $54 million for increased SBC rates, $32 million in rate relief effective November 9, 2006 and $31 million in increased sales and demands primarily due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below. The gas increase was due to $44 million in increased sales primarily due to weather, $32 million due to the SBC rate increases on November 1, 2006 and March 9, 2007 and $28 million due to rate relief effective November 9, 2006. 60
Operating Expenses Energy Costs The $91 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was comprised of an increase of $108 million in electric costs offset by a $17 million decrease in gas costs. The increase in electric costs was due to $120 million or 14% of higher prices for BGS and NUG purchases and $2 million or 3% of higher NUG volumes offset by $14 million or 2% in lower BGS volumes due to weather. The decrease in gas costs was caused by a $21 million or 10% decrease in price offset by a $4 million or 2% increase in sales volumes due primarily to weather. The $358 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was comprised of increases of $353 million in electric costs and $5 million in gas costs. The increase in electric costs was due to $341 million or 19% in higher prices for BGS and NUG purchases and $30 million or 2% in higher BGS volumes due to weather, offset by $18 million or 6% in lower NUG volumes. The increase in gas costs was caused by a $133 million or 9% increase in sales volumes due primarily to weather offset by $128 million or 8% in lower prices. Operation and Maintenance The $30 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was due primarily to increased SBC expenses of $34 million, resulting from rate increases in November 2006 and March 2007, a higher reserve for injuries and damages of $3 million and increased payroll of $2 million. Offsetting the increases was $5 million in lower pension expense and $3 million in lower overtime expense. The $92 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was due primarily to increased SBC expenses of $95 million, resulting from rate increases in November 2006 and March 2007, increased payroll of $6 million and a higher reserve for injuries and damages of $3 million. Offsetting the increases was $14 million in lower pension expense. Depreciation and Amortization The $13 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, was due primarily to decreases of $9 million due to revised plant depreciation rates and $3 million due to lower cost of removal rates, both resulting from the November 2006 rate case. Also contributing to the decrease was $3 million due to software previously amortized in 2006. This was offset by increases of $2 million due to amortization of regulatory assets. The $27 million decrease for the nine months ended September 30, 2007, as compared to the same period in 2006, was due primarily to decreases of $27 million due to revised plant depreciation rates and $10 million due to lower cost of removal rates, both resulting from the November 2006 rate case. Also contributing to the decrease was $5 million due to software previously amortized in 2006. This was offset by increases of $8 million due to amortization of regulatory assets and $6 million due to additional plant in service. Other Income The $4 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due to $5 million reduction in income tax gross-ups on contributions in aid of construction (CIAC). CIAC is taxable and PSE&G recognizes the gross-up as income when collected. Also contributing to the decrease was $1 million in lower investment income. These decreases were offset by a $2 million gain on the sale of property. The $6 million decrease for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to $7 million reduction in income tax gross-ups on contributions in aid of construction (CIAC). Also contributing to the decrease was $1 million in lower investment income. These decreases were offset by a $2 million gain on the sale of property. 61
Income Taxes The $5 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due to increased taxes of $10 million on higher pre-tax income offset by $5 million in various tax adjustments and tax credits. The $54 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to increased taxes of $64 million on higher pre-tax income offset by $10 million in various tax adjustments and tax credits. Power For the quarter ended September 30, 2007, Power had Net Income of $339 million, an increase of $134 million as compared to the same period in the prior year. For the nine months ended September 30, 2007, Power had Net Income of $736 million, an increase of $342 million as compared to the same period in the prior year. The primary reasons for the increases were higher prices realized from new contracts combined with higher sales volumes and lower generation costs. Improved margins and higher sales volumes under the BGSS contract due to a colder winter heating season and more favorable fuel pricing in 2007 also contributed to the increase. The increase in Net Income for the quarter also included the recognition of MTM gains of $7 million ($4 million, after-tax) in 2007 as compared to $20 million ($12 million, after-tax) of gains in the same quarter in 2006. The increase in Net Income for the nine month period included the effects of MTM losses of $10 million ($6 million, after-tax) in 2007 as compared to $3 million ($2 million, after-tax) of gains in 2006. The detail for the variances is discussed below: For the Quarters Increase % For the Nine Months Increase % 2007 2006 2007 2006 (Millions) (Millions) Operating Revenues $ 1,580 $ 1,455 $ 125 9 $ 5,034 $ 4,551 $ 483 11 Energy Costs $ 712 $ 809 $ (97 ) (12 ) $ 2,894 $ 2,965 $ (71 ) (2 ) Operation and Maintenance $ 232 $ 219 $ 13 6 $ 711 $ 713 $ (2 ) — Depreciation and Amortization $ 36 $ 36 $ — — $ 104 $ 103 $ 1 1 Other Income and Deductions $ 14 $ 12 $ 2 17 $ 57 $ 54 $ 3 6 Interest Expense $ (43 ) $ (39 ) $ 4 10 $ (119 ) $ (107 ) $ 12 11 Income Tax Expense $ (233 ) $ (157 ) $ 76 48 $ (519 ) $ (304 ) $ 215 71 Income (Loss) from Discontinued Operations, net of tax benefit $ 1 $ (2 ) $ 3 N/A $ (8 ) $ (19 ) $ (11 ) (58 ) Operating Revenues The $125 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to increases of $116 million in generation revenues and $13 million in gas supply revenues partially offset by a decrease of $4 million in trading revenues. The $483 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was due to increases of $329 million in generation revenues and $180 million in gas supply revenues partially offset by a decrease of $26 million in trading revenues. Generation Generation revenues increased $116 million for the quarter ended September 30, 2007, as compared to the same period in 2006, primarily due to higher revenues of $77 million from higher prices on BGS fixed-price contracts, $92 million from increased sales volumes in the various power pools and $49 million from higher capacity prices mainly due to RPM. These increases were partially offset by a decrease of $100 million due to the roll off of certain wholesale power contracts. Generation revenues increased $329 million for the nine months ended September 30, 2007, as compared to the same period in 2006, principally for the same reasons as the quarter increase. Increases of $222 million from higher prices on BGS fixed-price contracts, partially offset by reduced load being served under the BGS contracts, $299 million from higher sales volumes and prices in the energy pools and $69 million from higher capacity prices were partially offset by the rolloff of $266 million of wholesale power contracts. 62
Ended September 30,
(Decrease)
Ended September 30,
(Decrease)
Gas Supply Gas supply revenues increased $13 million for the quarter ended September 30, 2007, as compared to the same period in 2006, principally due to $4 million in higher sales prices under the BGSS contract, $6 million due to increased sales volumes to third party customers and $3 million of gains on financial transactions. Gas supply revenues increased $180 million for the nine months ended September 30, 2007, as compared to the same period in 2006, principally due to $149 million of higher sales volumes under the BGSS contract, largely due to colder average temperatures in the 2007 winter heating season, partially offset by lower prices of $40 million under the BGSS contract. The increase was also attributable to the recognition of gains of $63 million on financial hedging transactions. In addition, there were $9 million of increased fees for balancing and storage due to higher sales volumes and higher tariff rates that became effective in January 2007. Trading Revenues Trading revenues decreased $4 million for the quarter ended September 30, 2007, as compared to the same period in 2006, due mainly to losses on electric-related contracts. Trading revenues decreased $26 million for the nine months ended September 30, 2007, as compared to the same period in 2006, due primarily to the absence in 2007 of realized gains in 2006 from sales of excess emissions credits. Operating Expenses Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas costs to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $97 million for the quarter ended September 30, 2007, as compared to the same period in 2006, primarily due to a decrease in generation costs of $110 million, reflecting $74 million in lower pool prices and lower load obligations and $37 million in lower congestion and transmission charges, modestly offset by an increase in gas costs of $13 million, principally reflecting a higher volume of gas purchased for sale to third party customers. Energy Costs decreased $71 million for the nine months ended September 30, 2007, as compared to the same period in 2006, primarily due to a decrease in generation costs of $172 million, partially offset by an increase of $101 million in gas costs. The decrease in generation costs reflected decreases of $242 million due to lower pool prices and lower load obligations, $70 million due to lower gas prices and $60 million in lower congestion and transmission costs. These decreases were partially offset by an increase of $168 million due to higher volumes of fossil fuel purchases and a $38 million increase due to losses on financial hedging transactions for energy and fuel. The increase in gas costs reflected a $150 million increase due to a higher volume of gas sold to satisfy Power’s BGSS obligations, partially offset by lower gas inventory prices of $65 million and an increase of $24 million due to the recognition of losses in 2007 coupled with gains in 2006 related to financial hedging transactions. Operation and Maintenance Operation and Maintenance expense increased $13 million for the quarter ended September 30, 2007, as compared to the same period in 2006, primarily due to costs incurred in 2007 related to projects at certain fossil stations, mainly Hudson and Mercer. Operation and Maintenance expense decreased $2 million for the nine months ended September 30, 2007, as compared to the same period in 2006, mainly due to a decrease of $27 million at Nuclear, primarily comprised of a scheduled refueling outage at the Hope Creek nuclear facility in 2006 partially offset by costs in 2007 for the Salem nuclear units. The decrease at Nuclear was largely offset by a $23 million increase at Fossil, primarily comprised of project costs at Hudson and Mercer. 63
Depreciation and Amortization Depreciation and Amortization expense remained level for the quarter ended September 30, 2007, as compared to the same period in 2006. An increase in depreciation expense of $2 million due to a larger depreciable nuclear and fossil asset base in 2007 was offset by a decrease of $2 million due to the extension of the depreciable lives of certain of the coal-fired generation facilities resulting from continuous investment in replacements and upgrades of production equipment. The $1 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to an increase of $9 million from the Linden facility being placed into service in May 2006, largely offset by a decrease of $8 million due to the aforementioned extension of depreciable lives. Other Income and Deductions Other Income and Deductions increased $2 million for the quarter ended September 30, 2007, as compared to the same period in 2006. Major increases included $19 million in higher realized gains, interest and dividend income related to the Nuclear Decommissioning Trust (NDT) Funds, $4 million in interest earned on increased loans to PSEG and the absence of a $14 million environmental reserve in the third quarter of 2006 for a consent decree for planned alternate pollution reduction at the Hudson and Mercer units. These increases were largely offset by $30 million of other-than-temporary impairments, realized losses and management fees associated with the NDT Funds and the reversal of a $4 million contingency liability reserve associated with the Bethlehem Energy Center (BEC) in September 2006. Other Income and Deductions increased $3 million for the nine months ended September 30, 2007, as compared to the same period in 2006, largely as a result of the reasons provided for the quarter. Increases in Other Income of $42 million and $13 million related to the NDT Funds and interest earned on loans to PSEG, respectively, as well as the absence of the $14 million environmental expense incurred in 2006 were nearly offset by expenses of $58 million related to the NDT Funds and the reversal in 2006 of the $4 million contingency reserve for BEC. Interest Expense Interest Expense increased $4 million for the quarter ended September 30, 2007, as compared to the same period in 2006, due primarily to an increase in interest expense of $8 million due to the reclassification of Interest Expense to Discontinued Operations of the Lawrenceburg facility for the nine months ended September 30, 2006 and through the sale of Lawrenceburg in May 2007 partially offset by a decrease of $4 million due to higher Interest Capitalized During Construction (IDC) resulting from an increase in construction projects in 2007. Interest expense increased $12 million for the nine months ended September 30, 2007, as compared to the same period in 2006, due primarily to a $23 million increase due to lower IDC related to commencement of operations of the Linden facility in May 2006 and a $12 million increase due to interest expense that was not reclassified to Discontinued Operations since the sale of Lawrenceburg in May 2007. The increases were partly offset by an increase in IDC of $9 million resulting from an increase in construction projects in 2007 and a reduction of $10 million due to the maturity in April 2006 of $500 million of 6.875% Senior Notes. Income Taxes Income Taxes increased $76 million for the quarter ended September 30, 2007, as compared to the same period in 2006, due to an increase of $85 million on higher pre-tax income partially offset by a decrease of $9 million, principally due to the nondeductible status in 2006 of the aforementioned environmental reserve recognized in the third quarter of 2006 for the Consent Decree related to the Hudson and Mercer units. Income Taxes increased $215 million for the nine months ended September 30, 2007, as compared to the same periods in 2006, primarily due to an increase of $222 million on higher pre-tax income partially offset by a decrease of $7 million, principally due to the nondeductible status in 2006 of the aforementioned environmental reserve recognized in the third quarter of 2006 for the Hudson and Mercer units. Loss from Discontinued Operations, net of tax On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg generation facility for $325 million and recognized an estimated loss on disposal of $208 million, net of tax, in December 2006 for 64
the initial write-down of the carrying amount of Lawrenceburg to its fair value less cost to sell. The transaction closed in May 2007. Income from Discontinued Operations was $1 million in the third quarter of 2007, as compared to a Loss of $2 million in the same quarter of the prior year. Losses from Discontinued Operations were $8 million and $19 million for the nine months ended September 30, 2007 and 2006, respectively. Energy Holdings For the quarter ended September 30, 2007, Energy Holdings had Income from Continuing Operations of $66 million, as compared to $97 million for the same period in 2006. The decrease of $31 million for the quarter ended September 30, 2007 was primarily due to lower MTM gains on contracts at Global’s Texas generating facilities. MTM gains for the quarter ended September 30, 2007 were $20 million ($13 million, after-tax), as compared to $45 million ($29 million, after-tax) in the same period in 2006. Also contributing to the decrease was lower spark margin at Global’s Texas generation facilities and a $7 million after-tax impairment of Global’s investments in Venezuela. The decrease at Global was partially offset by income recorded at Resources for a $7 million stock distribution received in July 2007 related to a settlement of Resources’ claims regarding its amended leases with Northwest. For the nine months ended September 30, 2007, Energy Holdings had Income from Continuing Operations of $127 million, as compared to $15 million in the same period in 2006. The increase for the nine months ended September 30, 2007 as compared to the same period in 2006 was primarily due to the absence of a $263 million write-down of project investments and the associated tax benefit of $85 million ($178 million, net) related to the sale of Global’s indirect ownership interest in Rio Grande Energia (RGE) in June 2006. Excluding the write-down and the associated tax benefit, Income from Continuing Operations decreased $66 million for the nine months ended September 30, 2007, as compared to the same period in 2006. Similar to the quarter, the decrease was primarily due to lower earnings from Global’s Texas generation facilities. MTM gains for the nine months ended September 30, 2007 were $16 million ($11 million, after-tax), as compared to $58 million ($38 million, after-tax) in the same period in 2006. Earnings from the Texas facilities were also reduced as a result of lower spark margin in the summer of 2007 relative to the prior year and a scheduled maintenance outage at the Texas generation facilities’ Guadalupe plant. Also contributing to the decrease was the shut-down and maintenance costs of the San Marco facility at Bioenergie, which became fully operational in the third quarter of 2007, the absence of equity earnings from RGE, the impairment of Global’s investments in Venezuela and lower leveraged lease income primarily due to the adoption of certain accounting pronouncements in 2007. These decreases were partially offset by improved operations at Sociedad Austral de Electricidad S.A. (SAESA) combined with gains on certain sales and various settlements recorded in 2007. See Note 5. Commitments and Contingent Liabilities of the Notes for additional information regarding Bioenergie. The variances are discussed in detail below: For the Quarters Increase % For the Nine Months Increase % 2007 2006 2007 2006 (Millions) (Millions) Operating Revenues $ 380 $ 385 $ (5 ) (1 ) $ 962 $ 1,036 $ (74 ) (7 ) Energy Costs $ 212 $ 192 $ 20 10 $ 570 $ 578 $ (8 ) (1 ) Operation and Maintenance $ 44 $ 45 $ (1 ) (2 ) $ 137 $ 136 $ 1 1 Write-down of Assets $ 12 $ — $ 12 100 $ 12 $ 263 $ (251 ) (95 ) Depreciation and Amortization. $ 12 $ 13 $ (1 ) (8 ) $ 40 $ 35 $ 5 14 Income from Equity Method Investments $ 33 $ 30 $ 3 10 $ 86 $ 93 $ (7 ) (8 ) Other Income and Deductions $ (6 ) $ (1 ) $ 5 N/A $ 8 $ 9 $ (1 ) (11 ) Interest Expense $ (44 ) $ (49 ) $ (5 ) (10 ) $ (124 ) $ (146 ) $ (22 ) (15 ) Income Tax (Expense) Benefit $ (17 ) $ (18 ) $ 1 6 $ (48 ) $ 36 $ 84 N/A Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax $ 5 $ 4 $ 1 25 $ (9 ) $ 236 $ (245 ) N/A The classification of the results of Global’s investments on Energy Holdings’ Condensed Consolidated Financial Statements is dependent upon Global’s ownership percentage in the underlying investment which determines whether the investment is consolidated into Energy Holdings’ Condensed Consolidated Financial 65
Ended September 30,
(Decrease)
Ended September 30,
(Decrease)
Statements or if it is accounted for under the equity method of accounting. Global’s investments in Texas generation facilities, SAESA and Bioenergie are consolidated. As a result, the revenues, expenses, assets and liabilities of those investments are reflected on Energy Holdings’ Condensed Consolidated Financial Statements. Global’s investments in Chilquinta Energia S.A. (Chilquinta), Luz del Sur S.A.A. (LDS), GWF Power Systems, L.P., GWF Energy LLC, Kalaeloa Partners, L.P. (Kalaeloa) and several other smaller investments are accounted for under the equity method or cost method of accounting, as appropriate. Therefore, Energy Holdings only records its share of the net income from these projects as Income from Equity Method Investments on its Condensed Consolidated Statements of Operations. Operating Revenues The $5 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to lower revenues at Global which was primarily due to a $44 million decrease at the Texas generation facilities, mainly due to lower unrealized MTM gains on contracts and reduced demand in the summer of 2007 as compared to the same period in 2006. The decreases at the Texas facilities were partially offset by a $39 million increase at SAESA due to increased energy sales volumes. The change in Resources’ revenues for the quarter ended September 30, 2007, as compared to the same period in 2006, was immaterial because the decreased leveraged lease income resulting from the adoption of FIN 48 and FSP 13-2 was substantially offset by the gain recorded for the stock distribution received from Northwest. The $74 million decrease for the nine months ended September 30, 2007, as compared to the same period in 2006, was due to lower revenues at Global of $59 million, which was primarily the net result of a $132 million decrease at the Texas generation facilities mainly due to a reduction in sales due to lower demand and lower unrealized MTM gains on contracts in 2007 as compared to 2006; and a $7 million decrease at Bioenergie due to the shut-down of the San Marco facility during the first half of 2007. These decreases were partially offset by a $69 million increase at SAESA primarily due to higher generation, higher customer base and higher consumption and a $7 million gain on the sale of Global’s interest in Tracy Biomass. In addition, there were lower revenues at Resources of $15 million, primarily due to an $18 million decrease in leveraged lease income due to the adoption of FIN 48 and FSP 13-2, a $5 million decrease in investment distributions and a $4 million decrease in DSM revenue due to contract expirations. These decreases at Resources were partially offset by $7 million of income recorded for a stock distribution received from Northwest and a $6 million gain on settlement of Resources’ investment in a collateralized bond fund. Operating Expenses Energy Costs The $20 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due to a $33 million increase at SAESA due to higher energy purchase prices and volumes and a $1 million increase at Bioenergie, partially offset by a $14 million decrease at the Texas generation facilities primarily due to a reduction in fuel consumption. The $8 million decrease for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to a $68 million decrease at the Texas generation facilities primarily due to lower MTM unrealized gains on gas contracts in 2007 as compared to 2006 and a reduction in fuel consumption, and a $1 million decrease at Bioenergie due to the shut-down of the San Marco facility, partially offset by a $63 million increase at SAESA due to higher energy purchase prices and volumes. Operation and Maintenance The $1 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, is comprised of a $2 million increase at Global, primarily due to the shut down of Bioenergie’s San Marco Facility, which was more than offset by lower costs at Resources and Energy Holdings’ parent level. The $1 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to a $9 million increase due to a scheduled maintenance outage at the Texas generation facilities’ Guadalupe plant, which was partially offset by a $7 million decrease at SAESA due to repairs of 66
a gas turbine in 2006. The increases were further offset by reduced costs at Resources and Energy Holdings’ parent level. Write-down of Assets In January 2007, the Venezuelan government announced its intention to nationalize certain sectors of Venezuelan industry and commerce, including certain foreign-owned energy and communications companies. Global has entered into valuation discussions with the government of Venezuela as part of the nationalization efforts which are ongoing. Based upon a recent review of the circumstances, an impairment charge of $12 million was recorded in September 2007 to further write down Global’s Venezuelan investments. The $263 million write-down of assets for the nine months ended September 30, 2006, relates to Global’s sale of its 32% indirect ownership interest in RGE to its partner in May 2006. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes for additional information. Depreciation and Amortization The $1 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, was due to a reduction at Bioenergie. The $5 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to the consolidation of Bioenergie in May 2006, combined with slightly higher depreciation at the Texas generation facilities. Income from Equity Method Investments The $3 million increase for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due to improved results at Chilquinta and LDS. The $7 million decrease for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to the absence of equity earnings from RGE, which was sold in June 2006, partially offset by improved results at Chilquinta and LDS. Other Income and Deductions The $5 million increase in net Other Deductions for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due the absence of a loss recorded on the extinguishment of debt in 2006, which was more than offset by higher foreign currency transaction losses and lower interest and dividend income. The $1 million decrease in net Other Income for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to increased foreign currency transaction losses of $6 million and lower interest and dividend income partially offset by the absence of the loss on extinguishment of debt recorded in 2006 and a $9 million pre-tax gain in 2007 from an arbitration award received relating to the Konya-Ilgin dispute. Interest Expense The $5 million and $22 million decreases for the quarter and nine months ended September 30, 2007, respectively, as compared to the same periods in 2006, was primarily due to a decrease in debt outstanding. Income Taxes The $1 million decrease for the quarter ended September 30, 2007, as compared to the same period in 2006, was primarily due to a lower effective tax rate in 2007 resulting from a tax benefit related to the write-down of Global’s Venezuelan investments offset by the impact of the adoption of FIN 48. The $84 million increase for the nine months ended September 30, 2007, as compared to the same period in 2006, was primarily due to the absence of an $86 million tax benefit related to the sale of Global’s interest in RGE in June 2006, asset sales, an arbitration award received relating to the Konya-Ilgin dispute and the fact that interest and penalties are expensed under FIN 48 guidance. 67
Income from Discontinued Operations, including Gain on Disposal, net of tax 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 is no longer expected to be indefinitely reinvested. Income from Discontinued Operations related to Electroandes for the quarters ended September 30, 2007 and 2006 was $5 million and $4 million, respectively. (Loss) Income from Discontinued Operations for the nine months ended September 30, 2007 and 2006 was $(9) million and $9 million, respectively. In May 2006, Energy Holdings completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale resulted in an after-tax gain of $228 million. Loss from Discontinued Operations related to Elcho and Skawina for the nine months ended September 30, 2006 was $1 million, net of tax. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes for additional information. LIQUIDITY AND CAPITAL RESOURCES PSEG, PSE&G, Power and Energy Holdings 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, PSE&G, Power and Energy Holdings. Operating Cash Flows PSEG PSEG’s operating cash flow increased by $106 million from $1.433 billion for the nine months ended September 30, 2006 to $1.539 billion for the nine months ended September 30, 2007 due to changes from its subsidiaries as discussed below. PSE&G PSE&G’s operating cash flow decreased $179 million from $423 million to $244 million for the nine months ended September 30, 2007, as compared to the same period in 2006, primarily due to a ($352) million change in customer receivables. The September 2007 receivable balance was 11% higher than the prior year primarily due to commodity and base rate increases. The December 2006 receivable balance was 16% lower than the prior year due to warmer than normal conditions late in 2006 and a post-Katrina peak in gas prices in late 2005. Offsetting the change in receivables was a positive $136 million change in Accounts Payable-Affiliated Companies. The primary reason for the change was a large decrease in the gas payable in the first nine months of 2006 ($372) compared to a smaller decline in the same period in 2007 ($236 million). The unit cost of gas declined significantly in 2006 from the post-Katrina peak in gas prices in late 2005. Power Power’s operating cash flow increased $128 million from $920 million to $1.048 billion for the nine months ended September 30, 2007, as compared to the same period in 2006. The major reasons were an increase in net income of $342 million partially offset by an increase of $179 million in margin receivables related to higher collateral requirements. For the first nine months of 2007, cash margin requirements increased $33 million as compared to a decrease of $146 million in the comparable period of the prior year. Energy Holdings Energy Holdings’ operating cash flow increased $127 million from $138 million to $265 million for the nine months ended September 30, 2007, as compared to the same period in 2006. The increase was mainly attributable to the timing of tax payments related to Global’s sales of Elcho, Skawina and RGE in 2006. 68
Excess Cash Available PSEG, PSE&G, Power and Energy Holdings Excess cash is currently being used to reduce debt and beginning in mid-2008, it is expected that excess cash will be available for new investments, increasing dividends and/or repurchasing shares of PSEG common stock. Such actions could be accelerated depending on the timing of any potential asset sales. Common Stock Dividends PSEG Dividend payments on common stock for the quarters ended September 30, 2007 and 2006 were $149 million ($0.585 per share) and $144 million ($0.57 per share), respectively. Dividend payments on common stock for the nine months ended September 30, 2007 and 2006 were $445 million ($1.755 per share) and $430 million ($1.71 per share), respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, new investment opportunities and other factors. Improved earnings would cause PSEG’s dividend payout ratio to decline, providing PSEG the flexibility to raise its dividend at a rate higher than its prior dividend increases. On October 16, 2007, PSEG’s Board of Directors approved a common stock dividend of $0.585 per share for the fourth quarter of 2007. Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings As of September 30, 2007, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.2 billion of available liquidity under these facilities. In addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted as to availability and use to the specific companies as listed below. PSEG, PSE&G, Power and Energy Holdings believe sufficient liquidity exists to fund their respective short-term cash requirements. Company Expiration Total Primary Usage Available (Millions) PSEG: 5-year Credit Facility Dec 2011 $ 1,000 CP Support/Funding/ Letters of Credit $ 1 $ 999 Uncommitted Bilateral Agreement N/A N/A Funding $ — N/A PSE&G: 5-year Credit Facility June 2011 $ 600 CP Support/Funding/ Letters of Credit $ 195 $ 405 Uncommitted Bilateral Agreement N/A N/A Funding $ 9 N/A Power: 5-year Credit Facility Dec 2011 $ 1,600 Funding/Letters of Credit $ 141 (B) $ 1,459 Bilateral Credit Facility March 2010 $ 100 Funding/Letters of Credit $ 20 (B) $ 80 Bilateral Credit Facility March 2008 $ 200 Funding/Letters of Credit $ 33 (B) $ 167 Energy Holdings: 5-year Credit Facility (A) June 2010 $ 150 Funding/Letters of Credit $ 18 (B) $ 132 69
Date
Facility
Purpose
as of
September 30,
2007
Liquidity
as of
September 30, 2007
| ||||||||||||||||||||
(A) |
| Energy Holdings/Global/Resources joint and several co-borrower facility. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| These amounts relate to letters of credit outstanding. | ||||||||||||||||||
Power
As of September 30, 2007, Power had loaned $37 million to PSEG in the form of an intercompany loan.
On June 25, 2007, Power refinanced the $200 million PSEG/Power joint and several co-borrower bilateral credit facility. The maturity was extended to March 2008 and terms were modified so that Power is the sole borrower under this facility.
During the quarter ending September 30, 2007, Power’s required margin postings for sales contracts entered into in the normal course of business increased slightly. The required margin postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract obligations are fulfilled, liquidity requirements are reduced.
In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral likely to result from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for further information.
Energy Holdings
Energy Holdings and its subsidiaries had $83 million in cash, including $23 million invested offshore as of September 30, 2007. In addition, as of September 30, 2007, Energy Holdings had an outstanding demand loan receivable from PSEG of $257 million.
External Financings
PSEG, PSE&G, Power and Energy Holdings
During September 2007, PSEG stopped issuing new and treasury shares of common stock for its shareholder dividend reinvestment plans. Future requirements under these plans are now being satisfied through open market purchases.
For additional information related to External Financings, see Note 8. Changes in Capitalization of the Notes.
Debt Covenants
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements may contain maximum debt to equity ratios, minimum cash flow tests 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, PSE&G, Power and Energy Holdings, 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. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46 “Consolidation of Variable Interest Entities,” is not included as debt when calculating these ratios, as provided for in the various credit agreements.
70
Energy Holdings’ credit agreement also contains customary provisions under which the lender could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition. 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 September 30, 2007, PSEG’s ratio of debt to capitalization (as defined above) was 50.3%. PSEG’s credit facility contains a similar but less restrictive financial covenant where total debt excludes letters of credit related to collateral postings and total capitalization excludes any impacts for Accumulated Other Comprehensive Income/Loss adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions or benefit plans associated with SFAS 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 September 30, 2007, PSEG’s ratio of debt to capitalization (as defined above) was 48.6%. PSE&G Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total capitalization covenant. This covenant requires that such ratio will not be more than 65.0%. As of September 30, 2007, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 49.7%. In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding 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 September 30, 2007, PSE&G’s Mortgage coverage ratio was 4.6 to 1 and the Mortgage would permit up to approximately $2.2 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. Power Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. The Power ratio is the same debt to total capitalization calculation as set forth above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Condensed Consolidated Balance Sheets). This covenant requires that such ratio will not exceed 65.0%. As of September 30, 2007, Power’s ratio of debt to total capitalization (as defined above) was 38.4%. Energy Holdings Energy Holdings’ bank revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or equal to 1.75. As of September 30, 2007, Energy Holdings’ coverage under this covenant was 3.34. Additionally, the bank revolving credit agreement has a covenant requiring that Energy Holdings maintain a ratio of net debt (recourse debt offset by funds loaned to PSEG) to EBITDA of less than 5.25. As of September 30, 2007, Energy Holdings’ ratio under this covenant was 2.55. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources. 71
Energy Holdings’ indenture with respect to its senior notes does not permit liens securing indebtedness in excess of 10% of consolidated net tangible assets as calculated under the terms of the indenture. The terms of Energy Holdings’ Senior Notes allow the holders to demand repayment if a transaction or series of related transactions causes the assets of Resources to be reduced by 20% or more and as a direct result there is a downgrade of ratings. Credit Ratings PSEG, PSE&G, Power and Energy Holdings If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. The credit ratings of PSEG and its subsidiaries are shown in the table below. Moody’s (A) S&P (B) Fitch (C) PSEG: Outlook Neg Stable Pos Senior Unsecured Debt Baa2 BBB– BBB Preferred Securities Baa3 BB+ BBB– Commercial Paper. P2 A2 F2 PSE&G: Outlook Neg Stable Stable Mortgage Bonds A3 A– A Preferred Securities Baa3 BB+ BBB+ Commercial Paper P2 A2 F2 Power: Outlook Stable Stable Pos Senior Notes Baa1 BBB BBB Energy Holdings: Outlook Neg Neg Neg Senior Notes Ba3 BB– BB
| ||||||||||||||||||||
(A) |
| Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (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/Loss
PSEG, PSE&G, Power and Energy Holdings
For information related to Other Comprehensive Income/Loss, see Note 7. Comprehensive Income (Loss), net of tax.
72
PSEG, PSE&G, Power and Energy Holdings It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings 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, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings. Projected construction and investment expenditures for PSEG, PSE&G, Power and Energy Holdings are materially consistent with amounts disclosed in the Quarterly Reports on Form 10-Q of PSEG, PSE&G, Power and Energy Holdings for the quarter ended June 30, 2007. PSE&G During the nine months ended September 30, 2007, PSE&G made $421 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $421 million does not include expenditures for cost of removal, net of salvage, of $28 million, which are included in operating cash flows. Power During the nine months ended September 30, 2007, Power made $369 million of capital expenditures (excluding $132 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. Energy Holdings During the nine months ended September 30, 2007, Energy Holdings made $34 million of capital expenditures, primarily related to upgrades and expansions of SAESA’s transmission and distribution systems and expenditures at Electroandes. PSEG, PSE&G, Power and Energy Holdings For information related to recent accounting matters, see Note 2. Recent Accounting Standards of the Notes. ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK PSEG, PSE&G, Power and Energy Holdings The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ 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. It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Additionally, PSEG, PSE&G, Power and Energy Holdings 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 and its subsidiaries’ financial condition, results of operations or net cash flows. Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2006 or Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007. 73
Commodity Contracts Power 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 rules and other events. As part of its overall risk management strategy to reduce price risk due to 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, Hedging and Trading 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 133, changes in the fair value of qualifying cash flow hedge transactions are recorded in Accumulated Other Comprehensive Income/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. In addition, Power has non-asset based trading activities. These contracts involve financial transactions, including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in earnings. Value-at-Risk (VaR) Models Power Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses. Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR. The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non- trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively manages its portfolio. Reduced trading activities by Power during 2006 and 2007 have resulted in less trading risk. As of each of September 30, 2007 and December 31, 2006, trading VaR was less than $1 million. 74
Trading VaR Non-Trading (Millions) For the Quarter Ended September 30, 2007 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End $ — $ 34 Average for the Period $ — $ 39 High $ 1 $ 47 Low $ — $ 29 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End $ — $ 53 Average for the Period $ — $ 60 High $ — $ 73 Low $ — $ 45 Other Supplemental Information Regarding Market Risk Power The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. For additional information, see Note 6. Financial Risk Management Activities of the Notes. The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and nine months ended September 30, 2007. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in this table highlights, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. Operating Revenues Normal Trading Total (Millions) MTM Activities: Unrealized MTM Gains (Losses) Changes in Fair Value of Open Positions $ 3 $ (3 ) $ — Realization at Settlement of Contracts — 2 2 Total Change in Unrealized Fair Value 3 (1 ) 2 Realized Net Settlement of Transactions Subject to MTM — (2 ) (2 ) Net MTM Gains (Losses). 3 (3 ) — Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications 1,580 — 1,580 Total Operating Revenues $ 1,583 $ (3 ) $ 1,580
MTM VaR
For the Quarter Ended September 30, 2007
Operations and
Hedging (A)
| ||||||||||||||||||||
(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. | ||||||||||||||||||
75
Operating Revenues
For the Nine Months Ended September 30, 2007
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
MTM Activities:
Unrealized MTM Gains (Losses)
Changes in Fair Value of Open Positions
$
(6
)
$
(2
)
$
(8
)
Origination Unrealized Gain at Inception
—
—
—
Changes in Valuation Techniques and Assumptions
—
—
—
Realization at Settlement of Contracts
(12
)
2
(10
)
Total Change in Unrealized Fair Value.
(18
)
—
(18
)
Realized Net Settlement of Transactions Subject to MTM
12
(2
)
10
Net MTM Losses
(6
)
(2
)
(8
)
Accrual Activities:
Accrual Activities—Revenue, Including Hedge Reclassifications
5,042
—
5,042
Total Operating Revenues
$
5,036
$
(2
)
$
5,034
The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to ABTs and derivative instruments that qualify for hedge accounting under SFAS 133. This table presents amounts segregated by portfolio which 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 since balances with many counterparties are subject to offset and are shown net on the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included.
Energy Contract Net Liabilities
As of September 30, 2007
|
|
|
|
|
|
| |||||||||||||||
| Normal | Trading | Total | ||||||||||||||||||
| (Millions) | ||||||||||||||||||||
MTM Energy Assets |
|
|
|
|
|
| |||||||||||||||
Current Assets |
| $ |
| 23 |
| $ |
| 16 |
| $ |
| 39 | |||||||||
Noncurrent Assets |
| 6 |
| 4 |
| 10 | |||||||||||||||
|
|
|
|
|
|
| |||||||||||||||
Total MTM Energy Assets |
| $ |
| 29 |
| $ |
| 20 |
| $ |
| 49 | |||||||||
|
|
|
|
|
|
| |||||||||||||||
MTM Energy Liabilities |
|
|
|
|
|
| |||||||||||||||
Current Liabilities |
| $ |
| (365 | ) |
|
| $ |
| (26 | ) |
|
| $ |
| (391 | ) |
| |||
Noncurrent Liabilities |
| (109 | ) |
|
| (4 | ) |
|
| (113 | ) |
| |||||||||
|
|
|
|
|
|
| |||||||||||||||
Total MTM Current Liabilities |
| $ |
| (474 | ) |
|
| $ |
| (30 | ) |
|
| $ |
| (504 | ) |
| |||
|
|
|
|
|
|
| |||||||||||||||
Total MTM Energy Contract Net Liabilities |
| $ |
| (445 | ) |
|
| $ |
| (10 | ) |
|
| $ |
| (455 | ) |
| |||
|
|
|
|
|
|
| |||||||||||||||
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 September 30, 2007
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
| Maturities within | |||||||||||||||||||||||||||
2007 | 2008 | 2009-2011 | Total | |||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||
Trading |
| $ |
| (8 | ) |
|
| $ |
| (2 | ) |
|
| $ |
| — |
| $ |
| (10 | ) |
| ||||||
Normal Operations and Hedging |
| (75 | ) |
|
| (295 | ) |
|
| (75 | ) |
|
| (445 | ) |
| ||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
Total Net Unrealized Losses on MTM Contracts |
| $ |
| (83 | ) |
|
| $ |
| (297 | ) |
|
| $ |
| (75 | ) |
|
| $ |
| (455 | ) |
| ||||
|
|
|
|
|
|
|
|
| ||||||||||||||||||||
76
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. Energy Holdings The following table describes the drivers of Global’s marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter and nine months ended September 30, 2007. Normal operations and hedging activities represent the marketing of electricity available from Global’s owned generation sold into the market. Activities accounted for under the accrual method account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. Operating Revenues Normal (Millions) MTM Activities: Unrealized MTM Gains Changes in Fair Value of Open Position $ 22 Realization at Settlement of Contracts (3 ) Total Change in Unrealized Fair Value 19 Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications 319 Total Operating Revenues $ 338 Operating Revenues Normal (Millions) MTM Activities: Unrealized MTM (Losses) Gains 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 820 Total Operating Revenues $ 837
For the Quarter Ended September 30, 2007
Operations and
Hedging(A)
For the Nine Months Ended September 30, 2007
Operations and
Hedging(A)
| ||||||||||||||||||||
(A) |
| Includes derivative contracts that Global enters into to hedge anticipated exposures related to its owned and contracted generation supply. | ||||||||||||||||||
The following table indicates Global’s energy contract net assets.
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Energy Contract Net Assets
As of September 30, 2007
Normal
Operations and
Hedging
(Millions)
MTM Energy Assets
Current Assets
$
13
Noncurrent Assets
42
Total MTM Energy Assets
$
55
MTM Energy Liabilities
Current Liabilities
$
—
Noncurrent Liabilities
—
Total MTM Energy Liabilities
$
—
Total MTM Energy Contract Net Assets
$
55
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 September 30, 2007
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| Maturities within | |||||||||||||||||||||||||||
2007 | 2008 | 2009-2010 | Total | |||||||||||||||||||||||||
| (Millions) | |||||||||||||||||||||||||||
Total Net Unrealized Losses on MTM Contracts |
| $ |
| 8 |
| $ |
| 14 |
| $ |
| 33 |
| $ |
| 55 | ||||||||||||
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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, Power and Energy Holdings
The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss (OCL), a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (FTRs) 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, Power and Energy Holdings 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 that are expected to be reclassified out of OCL and into earnings over the next 12 months.
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
As of September 30, 2007
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|
|
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| Accumulated | Portion Expected | ||||||||||||
| (Millions) | |||||||||||||
Commodities |
| $ |
| (201 | ) |
|
| $ |
| (144 | ) |
| ||
Interest Rates |
| (6 | ) |
|
| (1 | ) |
| ||||||
Foreign Currency |
| — |
| — | ||||||||||
|
|
|
|
| ||||||||||
Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss |
| $ |
| (207 | ) |
|
| $ |
| (145 | ) |
| ||
|
|
|
|
| ||||||||||
78
Power Credit Risk The following table provides information on Power’s credit exposure, net of collateral, as of September 30, 2007. 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 Credit Securities Net Number of Net (Millions) (Millions) Investment Grade—External Rating $ 376 $ 49 $ 375 2 (A) $ 292 Non-Investment Grade—External Rating 2 1 2 — — Investment Grade—No External Rating — — — — — Non-Investment Grade—No External Rating 80 — 80 1 (B) 69 Total $ 458 $ 50 $ 457 3 $ 361
As of September 30, 2007
Exposure
Held as
Collateral
Exposure
Counterparties
>10%
Exposure of
Counterparties
>10%
| ||||||||||||||||||||
(A) |
| PSE&G is a counterparty with net exposure of $240 million. | ||||||||||||||||||
| ||||||||||||||||||||
(B) |
| Major supplier of low sulphur coal | ||||||||||||||||||
The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. When letters of credit are posted, exposure is not reduced; it is shifted to a more creditworthy entity. As of September 30, 2007, Power had 125 active counterparties.
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that information required to be disclosed is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that material information relating to each company, including their respective consolidated subsidiaries, is accumulated and communicated to the respective company’s management, including the Chief Executive Officer and Chief Financial Officer of each company by others within those entities to allow timely decisions regarding required disclosure. PSEG, PSE&G, Power and Energy Holdings have established a disclosure committee (the “committee”) which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures.
The Chief Financial Officer and Chief Executive Officer for PSEG, PSE&G, Power and Energy Holdings evaluated the effectiveness of the disclosure controls and procedures as of the end of the period covered by the quarterly report and, based on this evaluation, have concluded that disclosure controls and procedures were effective in providing reasonable assurance during the period covered in this quarterly report on Form 10-Q.
Changes in Internal Controls
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings 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 third quarter for PSEG,
79
PSE&G and Power that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting. Energy Holdings During the third quarter, significant changes to internal control over financial reporting at Energy Holdings were made. Specifically, Energy Holdings enhanced the controls around reconciliation processes within the accounting and treasury functions relative to the classification of Long-Term Debt on the Condensed Consolidated Balance Sheet. These controls will be evaluated as part of the overall assessment of internal controls over financial reporting to be included in Energy Holdings’ 2007 Annual Report. 80
Certain information reported under Item 3 of Part I of the 2006 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Report on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007 is updated below. PSE&G Electric Discount and Energy Competition Act (Competition Act) March 31, 2007 Form 10-Q, page 66 and June 30, 2007 Form 10-Q, page 77. On April 23, 2007, PSE&G and Transition Funding were served with a copy of a purported class action complaint (Complaint) challenging the constitutional validity of certain provisions of New Jersey’s Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the transition bond charge (TBC) of PSE&G Transition Funding, as well as recovery of TBC amounts previously collected. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional. On July 9, 2007, the same plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected and also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same charges. PSE&G and Transition Funding filed a motion to dismiss the amended Complaint (or in the alternative for summary judgment) on July 30, 2007 and PSE&G filed on September 30, 2007 a motion with the BPU to dismiss the petition. On October 10, 2007, PSE&G and Transition Funding’s motion to dismiss was granted. PSE&G’s motion to dismiss the BPU petition is pending. Con Edison 2006 Form 10-K, Page 46 and March 31, 2007 Form 10-Q, page 66 and June 30, 2007 Form 10-Q, page 77.In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G, PJM and NYISO with FERC asserting a failure to comply with agreements between PSE&G and Con Edison covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002 upheld PSE&G’s claim in part but also accepted Con Edison’s contentions in part. In December 2002, FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for additional hearings, including issues related to the development of protocols to implement the findings of the order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on the Phase II issues in June 2003 and in August 2004, FERC issued its decision on Phase II issues. While those decisions were largely favorable to PSE&G, PSE&G sought rehearing as to certain issues, as did Con Edison. On April 19, 2007, the FERC rejected the rehearing requests of both Con Edison and PSE&G, while granting PSE&G’s requested clarification that 400 MW of the 1000 MW at issue will have higher priority over other non-firm transactions only if Con Ed agrees to pay congestion costs. Both Con Edison and PSE&G have appealed the FERC’s rulings on both Phase I and Phase II issues to the Court of Appeals; thus, it is difficult to predict the final outcome of this proceeding at this time. The August 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement FERC’s directives. On February 18, 2005, NYISO, PJM and PSE&G submitted a joint compliance filing pursuant to FERC’s August 2004 decision. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. In subsequent filings to FERC regarding the efficacy of these protocols, Con Edison continued to claim that the obligations under the agreements as interpreted by the FERC’s orders were not being met. In December 30, 2005 and January 19, 2007 filings with FERC, Con Edison claimed to have incurred $111 million in damages, and requested FERC to require refunds of this amount. On April 19, 2007, however, the FERC issued an order rejecting Con Edison’s claim for a refund. FERC also rejected Con Edison’s request for interim remedies and directed that no further informational filings regarding the protocols would be required. On May 21, 2007, Con Edison sought rehearing of the April 19, 2007 order, which rehearing request was denied by the FERC on August 15, 2007. This matter is still subject to appeal and therefore, a final outcome of this proceeding cannot be 81
predicted. It is anticipated, nonetheless, that additional meetings will be held for the purpose of attempting to resolve issues associated with the operating protocols. PSEG, PSE&G, Power and Energy Holdings See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted: (1) Page 26. (Power) Prevention of Significant Deterioration (PSD)/New Source Review (NSR). Completed Docket No. Civil Action 02-CV-340. (2) Page 27. (PSE&G and Power) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. NJDEP Docket No. EX93060255; EPA CERCLA Docket No. 02-2007-2009. (3) Page 28. (PSE&G and Power) EPA notice with respect to contamination in the Newark Bay Study Area requesting participation and funding of EPA-approved study. (4) Page 29. (PSE&G and Power) New Jersey Department of Environmental Protection v. BFI Waste Systems of New Jersey, Inc. et al., filed with New Jersey Superior Court on June 29, 2007. (5) Page 29. (PSE&G and Power) New Jersey Department of Environmental Protection v. Public Service Electric and Gas Co., et al., filed with New Jersey Superior Court on June 29, 2007. Docket No. L-3337-07. (6) Page 29. (PSE&G) PSE&G’s MGP Remediation Program instituted by NJDEP’s Coal Gasification Facility Sites letter dated March 25, 1988. (7) Page 29. (Power) Power’s Petition for Review filed in the United States Court of Appeals for the District of Columbia Circuit on July 30, 2004 challenging the final rule of the United States Environmental Protection Agency entitled National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake Structures at Phase II Existing Facilities, now transferred to and venued in the United States Court of Appeals for the Second Circuit with Docket No. 04-6696-ag. (8) Page 30. (Energy Holdings) Italian government investigation regarding allegations of violations of Bioenergie S.p.A’s air permit for the San Marco facility. (9) Page 34. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002, Docket No.EX02060363, and Deferral Audit beginning on October 2, 2002 at the BPU, Docket No. EA02060366. Transferred to the OAL on February 7, 2007, Docket No. PUC 03127-07. (10) Page 84. (PSE&G) FERC proceeding related to PJM Reliability Pricing Model. Docket ER05-1410-002, EL05-148-002, ER05-1410-003, EL05-148-003, ER05-1410-000, et al. (11) Page 85. (PSE&G) PSE&G’s BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390. (12) Page 86. (PSE&G) Remediation Adjustment Clause filing with the BPU on February 13, 2007, Docket No. ER07020104. (13) Page 86. (PSE&G) BPU issued RFP to solicit bids proposals in preparation for the gas purchasing strategies audit. Docket No. GA05121062. There are no additional risk factors to be added to the Risk Factors disclosed beginning on page 34 of the 2006 Form 10-K, as updated on page 78 of the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007. Certain information reported under the 2006 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007 is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2006 Annual Report on Form 10-K and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2007 and June 30, 2007. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed. Federal Regulation Transmission Rates and Cost Allocation FERC Order 888/890 March 31, 2007 Form 10-Q, Page 71 and June 30, 2007 Form 10-Q, page 80. On May 18, 2006, FERC issued a NOPR seeking comments from the industry on whether reforms are needed to the protections that 82
FERC established in its previously-issued Order 888 to prevent undue discrimination and preference in the provision of transmission service. These reforms would be reflected in revisions to FERC’s pro forma Open Access Transmission Tariff, which has been incorporated into the tariffs of Transmission Providers and governs the terms and conditions under which transmission owners must provide transmission service to all eligible customers. On February 16, 2007, FERC issued Final Rule 890 in this proceeding. The Final Rule covers many transmission-related topics and emphasizes the issues of transmission planning and cost allocation associated with the construction of transmission projects. On March 19, 2007, PSE&G filed a Request for Rehearing and Clarification of the Final Rule, arguing that FERC, among other things, erred in appearing to mandate Transmission Provider planning for economic transmission projects and in establishing cost allocation principles for these projects. Order 890 remains subject to rehearing. The Final Rule requires Transmission Providers, including PJM and the NYISO, to demonstrate compliance with open access principles, including having a transparent transmission planning process. PSE&G and Power are actively working with PJM and the NYISO to develop appropriate Order 890 compliance proposals in the area of transmission planning and cost allocation; these proposals will be filed with FERC on December 7, 2007. The final outcome of this proceeding and the resulting impact on PSEG, PSE&G and Power cannot be determined at this time. Market Power, Market Design and Capacity Issues PSEG, PSE&G, Power and Energy Holdings Market Power 2006 Form 10-K, Page 17 and March 31, 2007 Form 10-Q, page 71 and June 30, 2007 Form 10-Q, page 80. Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). FERC requires that holders of MBR tariffs file an update every 3 years demonstrating that they continue to lack market power. On June 21, 2007, the FERC issued a Final Rule codifying new market-based rate regulations and announcing changes to its market power test. Specifically, the regulations adopt a revised, two-pronged horizontal and vertical market power analysis. Moreover, with respect to the use of a relevant geographic market for evaluating whether an entity possesses horizontal market power, the FERC has now established that, in circumstances where there has been a specific finding of a relevant sub-market within an RTO, the sub-market may become the geographic market. PJM-East (Eastern MAAC), PSEG North and southwestern Connecticut are all mentioned in the Final Rule as submarkets in PJM and the ISO-New England. While the use of these markets for the market power analysis is rebuttable–one can demonstrate that their use is not appropriate–the possibility exists that a small sub-market of Eastern MAAC, PSEG North or southwestern Connecticut, in which Power holds a concentration of generation assets, could be used in evaluating whether the Power generation assets possess market power. In this case, Power would likely be required to file mitigation measures with FERC. The Final Rule provides for certain categories of cost-based, behavioral mitigation measures but also allows an applicant to propose an alternate mitigation plan. Under the schedule set forth in the Final MBR Rule, PSE&G and ER&T (with respect to the PJM assets) will be required to file an updated market power study with FERC in December 2007, with Power Connecticut filing an updated market power study in June 2008. Energy Holdings’ subsidiary GWF Energy LLC, which sells power at market-based rates, will also be required to file an updated market power study. On July 23, 2007, PSE&G and Power filed a request for rehearing with FERC, which request is still pending. The outcome of these proceedings cannot be predicted. On September 20, 2007, the FERC issued an order on two complaints filed against PJM in April 2007 regarding PJM’s alleged interference with the activities of its Market Monitoring Unit (MMU). In this Order, which is currently on rehearing, the FERC made a preliminary finding that the MMU had effectively discharged its duties under the Tariff. However, the FERC also found that the Tariff should be revised so that the MMU no longer reports to PJM management but instead reports to either the PJM Board of Managers or an independent committee of the PJM Board. The FERC also established settlement procedures to address issues concerning the MMU’s structure and functionality. The settlement process has commenced and must be completed in 90 days. PSE&G and Power were parties to the underlying complaint proceeding at FERC and are actively participating in the settlement proceeding. Power and PSE&G cannot predict the outcome of this proceeding at this time. 83
PJM Reliability Pricing Model (RPM) 2006 Form 10-K, Page 18 and March 31, 2007 Form 10-Q, page 72and June 30, 2007 Form 10-Q, page 79. On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve and a transitional implementation of the market design. Parties to the FERC proceeding reached a settlement, which was filed with FERC on September 29, 2006. On December 22, 2006, FERC issued an order approving the September 29 settlement, with certain conditions. The final revenue impact on Power of the settlement approved in the December 22, 2006 FERC order could result in incremental margin of $125 million to $175 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. On January 22, 2007, PSEG as well as other parties to the proceeding filed for rehearing of the December 22, 2006 order and on June 25, 2007, the FERC issued an order denying rehearing with respect to both the April 20, 2006 order and the December 22, 2006 order while granting limited clarifications. On August 23, 2007, PSEG filed an appeal with the U.S. Court of Appeals of the underlying FERC orders and thus is unable to predict the outcome of this proceeding. In a related matter, on September 13, 2007, Duquesne Light Company (Duquesne) filed a complaint against PJM, requesting that the FERC order PJM to exclude load in the Duquesne zone from upcoming RPM auctions establishing future capacity obligations. Power and PSE&G protested Duquesne’s complaint, arguing that Duquesne should not be allowed to have its load excluded from RPM until (i) it officially withdraws as a member from PJM through a FERC proceeding and (ii) FERC accepts such withdrawal. On September 28, 2007, the FERC dismissed Duquesne’s complaint against PJM. Thus, the Duquesne zone will remain part of the RPM auction process until such time as the FERC authorizes Duquesne’s withdrawal from PJM. For additional information, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Power—Overview and Future Outlook. DOE Congestion Study 2006 Form 10-K, Page 19, March 31, 2007 Form 10-Q, page 72 and June 30, 2007 Form 10-Q, page 81. On August 8, 2006, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the Energy Policy Act. This Congestion Study identified two areas in the U.S. as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the statutory ability to designate transmission corridors in these “critical congestion areas,” to which FERC back-stop eminent domain authority will attach in the event that the relevant State siting agency denies a siting application, does not have the authority to act or fails to act on the siting application within one (1) year. Thus, corridor designation may facilitate the construction of transmission projects to address congestion in these corridors. On October 2, 2007, the DOE issued a report designating the Mid-Atlantic Area National Corridor as a final corridor designation covering most of PJM. Specifically, the final corridor encompasses all of New Jersey, as well as portions of West Virginia, Pennsylvania, Maryland, Virginia, the District of Columbia, Delaware, Ohio and New York. This corridor designation has a duration of twelve (12) years. The DOE report is subject to rehearing; thus the final outcome of this proceeding cannot be predicted at this time. Should the Mid-Atlantic Area corridor designation remain intact, entities seeking to build transmission within its geographic scope, which includes New Jersey, most of Pennsylvania and New York, will be able to use FERC’s back-stop eminent domain authority in the future, if necessary. State Regulation PSEG, PSE&G, Power and Energy Holdings New Jersey Energy Master Plan 2006 Form 10-K, Page 22 and March 31, 2007 Form 10-Q, page 73 and June 30, 2007 Form 10-Q, page 82. The Governor of New Jersey has directed the BPU, in partnership with other New Jersey agencies, to develop an Energy Master Plan (EMP). 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. In the Governor’s directive regarding the 84
EMP, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s electricity needs with certain renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand without increasing New Jersey’s reliance on non- renewable resources. In November 2006, PSE&G submitted a number of strategies designed to improve efficiencies in customer use and increase the level of renewable generation. During January and February 2007, PSE&G has been actively involved in the broad-based constituent working groups created to develop specific strategies to achieve the goals and objectives. In September 2007, the BPU held a stakeholder meeting on energy efficiency issues, and PSE&G submitted comments advocating a strong role for gas and electric utilities in meeting the State’s energy efficiency goals. A draft EMP is expected to be released in November of 2007, and a final plan is expected to be completed early in 2008. The outcome of this proceeding and its impact on PSEG, PSE&G and Power cannot be predicted at this time. On April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. Under the plan, PSE&G would invest approximately $100 million over two years following BPU approval of the plan to help finance the installation of solar systems throughout its service area. If approved by the BPU, the initiative could begin by the end of 2007 and support 30 MW of solar power in the following two years, fulfilling approximately 50% of the BPU’s Renewable Portfolio Standard (RPS) requirements in PSE&G’s service area for 2009 and 2010. On July 12, 2007, the BPU established a schedule for consideration of this proposal. PSE&G has held a series of stakeholder meetings to discuss program details with interested parties. Evidentiary hearings, if necessary, are scheduled for December 2007. The outcome of this proceeding cannot be predicted at this time. PSE&G BGSS Filings 2006 Form 10-K, Page 23 and March 31, 2007 Form 10-Q, page 73 and June 30, 2007 Form 10-Q, page 82. PSE&G made its 2006/2007 BGSS filing on May 26, 2006. The parties entered into a Stipulation to make the filed BGSS rate effective October 1, 2006 on a provisional basis. However, since the time of the filing, prices of gas futures have dropped significantly and as a result, additional BGSS data has been requested by and provided to the BPU. Settlement discussions with the BPU Staff were completed and a new Stipulation, dated October 27, 2006, was executed by the parties. This new Stipulation was approved by the BPU and resulted in a decrease in annual BGSS revenues of approximately $120 million, which is approximately a 6% reduction in a typical residential gas customer’s bill. The new BGSS rate became effective on November 9, 2006. The Stipulation did not include any change in the Balancing Charge, which is a charge for the difference between the amount of gas delivered to customers and the amount of gas used. The parties entered into a second Stipulation, which addresses the Balancing Charge only. The BPU Staff recommended a lower Balancing Charge than proposed by PSE&G and received agreement from Rate Counsel. The parties executed the Stipulation for the lower rate and BPU approval was received on January 17, 2007. The parties entered into a third Stipulation to make both the BGSS rate and the Balancing Charge, which were previously approved on a provisional basis, final. In addition, the Stipulation included agreement between the parties on the following two items: 1) PSE&G agreed to consider, on a prospective basis, some suggested changes to the gas hedging program; and 2) PSE&G agreed to increase the gas reservation charge from 27.4 cents per dekatherm (DTh) to 42.5 cents per DTh to be effective the first month after final BPU approval. This Stipulation was approved by the Administrative Law Judge on May 21, 2007 and then by the BPU at its Agenda Meeting of June 14, 2007. PSE&G made its 2007/2008 BGSS filing on June 1, 2007. In the filing, PSE&G requested an increase in annual BGSS revenues of $39 million, excluding Sales and Use Tax, to be effective October 1, 2007. This increase amounts to approximately 2% for a typical residential customer. No other changes were included in the filing. On July 2, 2007, the BPU transferred the case to the Office of Administrative Law (OAL) for its initial decision. PSE&G has received and responded to discovery from both BPU staff and Rate Counsel and 3 Public Hearings have been held. PSE&G has the ability to put in place two self-implementing BGSS increases on December 1, 2007 and February 1, 2008 of up to 5% and also may reduce the BGSS rate at any time. 85
Remediation Adjustment Clause (RAC) Filing 2006 Form 10-K, Page 23 and March 31, 2007 Form 10-Q, page 74 and June 30, 2007 Form 10-Q, page 83. In February 2007, PSE&G submitted its RAC-13 and RAC-14 filings with the BPU, seeking recovery of $71 million of RAC program costs incurred during the two-year period, August 1, 2004 through July 31, 2006, were reasonable and are available for recovery. On April 18, 2007, the BPU transferred the case to the OAL for its initial decision. On October 12, 2007, PSE&G filed a settlement agreement with the ALJ, resolving this matter. On October 25, 2007, the BPU issued an Order approving settlement of the matter and affirming recovery of PSE&G’s RAC 13 and 14 costs of $43 million and $28 million, respectively. Amortization of the program costs is equal to revenues with no impact on Net Income. Societal Benefits Clause (SBC) Filing 2006 Form 10-K, Page 24 v and March 31, 2007 Form 10-Q, page 74 and June 30, 2007 Form 10-Q, page 83. On May 7, 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 transition charge (NGC) rates. For electric customers, the rates proposed were designed to recover approximately $270 million in SBC/NGC revenues beginning January 1, 2008. For gas, the rates proposed were designed to recover approximately $75 million in SBC/NGC revenues. On June 7, 2007, the BPU transferred this matter to the OAL for its initial decision and the discovery process has begun. On October 17, 2007, PSE&G filed an updated motion with the BPU. This revision sought to recover approximately $310 million and $75 million in SBC/NGC revenues for electric and gas customers, respectively. Hearings are scheduled for the first quarter of 2008. SBC costs are deferred when incurred and amortized to expense when recovered in revenues, resulting in no impact on Net Income. Gas Purchasing Strategies Audit PSE&G and Power 2006 Form 10-K, Page 2 and March 31, 2007 Form 10-Q, page 74 and June 30, 2007 Form 10-Q, page 83. In January 2007, the BPU issued an RFP to solicit bid proposals to engage a contractor to perform an analysis of the gas purchasing practices and hedging strategies of the four New Jersey gas distribution companies (GDCs), including PSE&G. The primary focus of the audit is to examine and compare the financial and physical hedging policies and practices of each GDC and to provide recommendations for improvements to these policies and practices. Over the past few months, the audit has proceeded with discovery and the conducting of interviews. The goal of the consultants is to issue a report of major recommendations by the end of the year. PSE&G cannot predict the outcome of this process. Universal Service Fund (USF) Filing June 30, 2007 Form 10-Q, page 83. The USF is an energy assistance program mandated by the BPU under the Competition Act to provide payment assistance to low-income customers. The Lifeline program is also a mandated energy assistance program to provide payment assistance to elderly and disabled customers. On June 29, 2007, PSE&G filed a compliance filing on behalf of all of the State’s electric and gas public utilities to reset statewide rates for the Permanent Universal Service Fund and the Lifeline program. The filed rates were set to recover $172 million on a statewide basis. Of this amount, the revised electric rates would recover $95 million while the revised gas rates would recover $77 million. As part of this filing, the proposed rates for the Lifeline program are expected to recover a total of $77 million, $50 million for the electric program and $27 million for the gas program. On October 4, 2007, the New Jersey BPU issued an order allowing the utilities to recover $174 million ($96 million electric and $78 million gas) on a statewide basis. This exceeds the requested amount and is based on updates reflecting 10 months of actual data. The proposed rates for the Lifeline program were adopted as filed. The new rates became effective on October 4, 2007. PSE&G earns no margin on the collection of the USF and Lifeline programs, resulting in no impact on Net Income. 86
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 Exhibit 31.1: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 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. PSE&G: Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements Exhibit 31.2: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.3: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 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. Power: Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.4: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.5: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 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 d. Energy Holdings: Exhibit 10: Purchase and Sale Agreement between SN Power Peru Holding S.R.L. and PSEG Americas Ltd. dated September 17, 2007 Exhibit 12.4: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.6: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.7: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 32.6: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.7: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 87
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: November 1, 2007 88
(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
(Registrant)By:
/s/ DEREK M. DIRISIO
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2007
89
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
(Registrant)By:
/s/ DEREK M. DIRISIO
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2007
90
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 ENERGY HOLDINGS L.L.C.
(Registrant)By:
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2007
91