UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2006
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
| Commission File Number | Registrants, State of Incorporation, Address, and Telephone Number | I.R.S. Employer Identification No. | ||||
001-09120 | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza, P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com | 22-2625848 | ||||
001-00973 | PUBLIC SERVICE ELECTRIC AND GAS COMPANY (A New Jersey Corporation) 80 Park Plaza, P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000 http://www.pseg.com | 22-1212800 | ||||
000-49614 | PSEG POWER LLC (A Delaware Limited Liability Company) 80 Park Plaza—T25 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com | 22-3663480 | ||||
000-32503 | PSEG ENERGY HOLDINGS L.L.C. (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 456-3581 http://www.pseg.com | 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. Yes S 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):
Public Service Enterprise Group Incorporated | Large accelerated filer S | Accelerated filer £ | Non-accelerated filer £ | |||
Public Service Electric and Gas Company | Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S | |||
PSEG Power LLC | Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S | |||
PSEG Energy Holdings L.L.C. | Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S |
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No S
As of April 30, 2006, Public Service Enterprise Group Incorporated had outstanding 251,469,431 shares of its sole class of Common Stock, without par value.
As of April 30, 2006, 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 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: ii• business conditions, financial market, credit rating, regulatory and other risks resulting from the pending merger with Exelon Corporation; • regulatory issues that significantly impact operations; • operating performance or cash flow from investments falling below projected levels; • credit, commodity, interest rate, counterparty and other financial market risks; • liquidity and the ability to access capital and maintain adequate credit ratings; • adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation; • changes in the electric industry, including changes to power pools; • changes in demand resulting from changes in prices; • changes in the number of market participants and the risk profiles of such participants; • changes in technology that make generation, transmission and/or distribution assets less competitive; • availability of power transmission facilities that impact the ability to deliver output to customers; • growth in costs and expenses; • environmental regulations that significantly impact operations; • 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; • ability to maintain satisfactory regulatory results; • changes in political conditions, recession, acts of war or terrorism; • continued availability of insurance coverage at commercially reasonable rates; • involvement in lawsuits, including liability claims and commercial disputes; • inability to attract and retain management and other key employees, particularly in view of the pending merger with Exelon Corporation; • acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG's, PSE&G's, Power's and Energy Holdings' strategy or structure; • business combinations among competitors and major customers; • general economic conditions, including inflation or deflation; • changes in tax laws and regulations;
PSEG, PSE&G and Energy Holdings PSEG, Power and Energy Holdings PSEG and Power PSEG and Energy Holdings 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• 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; • ability to obtain adequate and timely rate relief; • inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations; • inability to meet generation operating performance expectations; • energy transmission constraints or lack thereof; • adverse changes in the market for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas and power; • surplus of energy capacity and excess supply; • substantial competition in the 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; • effects on competitive position of actions involving competitors or major customers; • changes in product or sourcing mix; • 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; • ability to realize tax benefits; • changes in political regimes in foreign countries; and • international developments negatively impacting business.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense Preferred Stock Dividends INCOME FROM CONTINUING OPERATIONS BEFORE Income Tax Expense INCOME FROM CONTINUING OPERATIONS Income from Discontinued Operations, net of tax expense (benefit) NET INCOME WEIGHTED AVERAGE COMMON SHARES BASIC DILUTED EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS NET INCOME DILUTED INCOME FROM CONTINUING OPERATIONS NET INCOME DIVIDENDS PAID PER SHARE OF COMMON STOCK See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS For the Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 3,521 $ 3,244 2,204 1,849 584 576 204 184 41 43 3,033 2,652 33 31 521 623 49 43 (26 ) (14 ) (201 ) (200 ) (1 ) (1 )
INCOME TAXES 342 451 (143 ) (171 ) 199 280
of $1 and ($3) 4 5 $ 203 $ 285
OUTSTANDING (THOUSANDS): 251,187 238,314 252,065 242,190 $ 0.79 $ 1.18 $ 0.81 $ 1.20 $ 0.79 $ 1.16 $ 0.81 $ 1.18 $ 0.57 $ 0.56
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $54 and $44 in 2006 Unbilled Revenues Fuel Materials and Supplies Energy Trading Contracts Prepayments Restricted Funds Derivative Contracts Assets of Discontinued Operations Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Nuclear Decommissioning Trust (NDT) Funds Other Special Funds Goodwill and Other Intangibles Energy Trading Contracts Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 218 $ 288
and 2005, respectively 1,818 1,938 246 394 400 812 275 277 94 327 90 129 82 76 11 50 522 498 45 41 3,801 4,830 19,111 18,896 (5,700 ) (5,560 ) 13,411 13,336 5,000 5,053 4,117 4,077 1,184 1,133 559 559 595 608 16 42 2 — 171 177 11,644 11,649 $ 28,856 $ 29,815
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Commercial Paper and Loans Accounts Payable Derivative Contracts Energy Trading Contracts Accrued Interest Accrued Taxes Clean Energy Program Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Regulatory Liabilities Asset Retirement Obligations Other Postretirement Benefit (OPEB) Costs Clean Energy Program Environmental Costs Derivative Contracts Energy Trading Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Project Level, Non-Recourse Debt Debt Supporting Trust Preferred Securities Total Long-Term Debt SUBSIDIARIES' PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, COMMON STOCKHOLDERS' EQUITY Common Stock, no par, authorized 500,000,000 shares; issued; Treasury Stock, at cost; 2006—14,137,952 shares; 2005—14,169,560 shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholders' Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 1,041 $ 1,536 154 100 785 1,154 364 425 134 200 205 152 241 141 103 96 441 436 470 517 3,938 4,757 4,344 4,248 614 720 596 585 613 597 210 233 414 420 481 637 13 19 219 218 7,504 7,677 7,732 7,849 1,841 1,879 880 891 660 660 11,113 11,279
$100 par value, 7,500,000 authorized; issued and outstanding,
2006 and 2005—795,234 shares 80 80
2006—265,598,389 shares; 2005—265,332,746 shares 4,620 4,618 (531 ) (532 ) 2,605 2,545 (473 ) (609 ) 6,221 6,022 17,414 17,381 $ 28,856 $ 29,815
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Amortization of Nuclear Fuel Provision for Deferred Income Taxes (Other than Leases) and ITC Non-Cash Employee Benefit Plan Costs Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes Gain on Sale of Investments Undistributed Earnings from Affiliates Foreign Currency Transaction Gain Unrealized Losses (Gains) on Energy Contracts and Other Derivatives Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs Under Recovery of Societal Benefits Charge (SBC) Net Realized Gains and Income from NDT Funds Other Non-Cash Charges Net Change in Certain Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Proceeds from the Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from the Sale of Investments and Return of Capital from Partnerships Proceeds from NDT Funds Sales Investment in NDT Funds Restricted Funds NDT Funds Interest and Dividends Other Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans Issuance of Non-Recourse Debt Issuance of Common Stock Redemptions of Long-Term Debt Repayment of Non-Recourse Debt Redemption of Debt Underlying Trust Securities Cash Dividends Paid on Common Stock Other Net Cash Used In Financing Activities Effect of Exchange Rate Change Net (Decrease) Increase in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For The Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 203 $ 285 205 190 25 22 3 4 57 57 (22 ) (26 ) — (45 ) (29 ) (19 ) (1 ) (3 ) 21 (14 ) 49 29 (8 ) (8 ) (18 ) (21 ) 3 13 524 203 (35 ) (105 ) 1 61 (63 ) 34 915 657 (240 ) (197 ) 2 1 300 1,378 (305 ) (1,383 ) (22 ) (5 ) 10 7 17 39 (238 ) (160 ) 54 (268 ) — 11 17 18 (493 ) (34 ) (12 ) (4 ) (154 ) — (143 ) (134 ) (15 ) (24 ) (746 ) (435 ) (1 ) (1 ) (70 ) 61 288 263 $ 218 $ 324 $ 25 $ 1 $ 134 $ 172
PUBLIC SERVICE ELECTRIC AND GAS COMPANY OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME BEFORE INCOME TAXES Income Tax Expense NET INCOME Preferred Stock Dividends EARNINGS AVAILABLE TO PUBLIC SERVICE See disclosures regarding Public Service Electric and Gas Company 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS For the Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 2,350 $ 2,184 1,631 1,424 301 295 152 135 41 43 2,125 1,897 225 287 4 2 (1 ) (1 ) (85 ) (84 ) 143 204 (65 ) (86 ) 78 118 (1 ) (1 )
ENTERPRISE GROUP INCORPORATED $ 77 $ 117
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $50 in 2006 and $41 in 2005 Unbilled Revenues Materials and Supplies Prepayments Restricted Cash Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Other Special Funds Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding Public Service Electric and Gas Company 6
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 133 $ 159 1,025 959 246 394 49 49 13 49 18 14 37 32 1,521 1,656 10,743 10,636 (3,695 ) (3,627 ) 7,048 7,009 5,000 5,053 145 144 304 315 114 114 5,563 5,626 $ 14,132 $ 14,291
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable Accounts Payable—Affiliated Companies, net Accrued Interest Clean Energy Program Derivative Contracts Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and ITC Other Postretirement Benefit (OPEB) Costs Regulatory Liabilities Clean Energy Program Environmental Costs Asset Retirement Obligations Derivative Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Total Long-Term Debt PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares COMMON STOCKHOLDER'S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholder's Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See disclosures regarding Public Service Electric and Gas Company 7
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 452 $ 485 252 286 512 388 43 59 103 96 12 6 375 373 1,749 1,693 2,581 2,608 573 561 614 720 210 233 359 365 213 210 12 6 27 27 4,589 4,730 2,753 2,866 1,841 1,879 4,594 4,745 80 80
issued and outstanding 892 892 170 170 986 986 1,077 1,000 (5 ) (5 ) 3,120 3,043 7,794 7,868 $ 14,132 $ 14,291
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Depreciation and Amortization Provision for Deferred Income Taxes and ITC Non-Cash Employee Benefit Plan Costs Non-Cash Interest Expense Employee Benefit Plan Funding and Related Payments Over Recovery of Electric Energy Costs (BGS and NTC) Over Recovery of Gas Costs Under Recovery of SBC Other Non-Cash Charges Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues Materials and Supplies Prepayments Accrued Taxes Accrued Interest Accounts Payable Accounts Receivable/Payable—Affiliated Companies, net Other Current Assets and Liabilities Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Restricted Funds Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Redemption of Securitization Debt Redemption of Long-Term Debt Preferred Stock Dividends Net Cash Used In Financing Activities Net (Decrease) Increase In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes (Received) Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding Public Service Electric and Gas Company 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For the Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 78 $ 118
Operating Activities: 152 135 (25 ) (29 ) 41 40 — 2 (13 ) (60 ) 19 16 30 13 (8 ) (8 ) 2 1 82 (144 ) — (8 ) 36 46 22 37 (16 ) (10 ) (34 ) (41 ) (52 ) 8 (21 ) 48 (21 ) 62 272 226 (108 ) (93 ) (5 ) — (113 ) (93 ) — (32 ) (36 ) (34 ) (148 ) — (1 ) (1 ) (185 ) (67 ) (26 ) 66 159 6 $ 133 $ 72 $ (4 ) $ 5 $ 92 $ 87
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax Expense INCOME FROM CONTINUING OPERATIONS Loss from Discontinued Operations, net of tax benefit of $5 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Power LLC 9
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS For the Quarters
Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 1,967 $ 1,730 1,487 1,270 235 227 35 30 1,757 1,527 210 203 41 31 (19 ) (8 ) (40 ) (28 ) 192 198 (80 ) (83 ) 112 115 — (7 ) $ 112 $ 108
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable Accounts Receivable—Affiliated Companies, net Short-Term Loan to Affiliate Fuel Materials and Supplies Energy Trading Contracts Derivative Contracts Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC) Nuclear Decommissioning Trust (NDT) Funds Goodwill and Other Intangibles Other Special Funds Energy Trading Contracts Other Total Noncurrent Assets TOTAL ASSETS LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable Short-Term Loan from Affiliate Energy Trading Contracts Derivative Contracts Accrued Interest Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Asset Retirement Obligations Energy Trading Contracts Derivative Contracts Environmental Costs Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt MEMBER'S EQUITY Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Loss Total Member's Equity TOTAL LIABILITIES AND MEMBER'S EQUITY See disclosures regarding PSEG Power LLC 10
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 5 $ 8 675 862 319 288 380 — 400 812 200 201 94 327 8 50 30 27 2,111 2,575 6,557 6,457 (1,637 ) (1,577 ) 4,920 4,880 — 70 1,184 1,133 62 63 153 143 16 42 42 39 1,457 1,490 $ 8,488 $ 8,945 $ 500 $ 500 428 745 — 202 134 200 336 403 96 41 90 86 1,584 2,177 53 — 381 373 13 19 431 597 55 55 72 70 1,005 1,114 2,817 2,817 2,000 2,000 (986 ) (986 ) 2,422 2,310 (354 ) (487 ) 3,082 2,837 $ 8,488 $ 8,945
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Amortization of Nuclear Fuel Interest Accretion on Asset Retirement Obligations Provision for Deferred Income Taxes and ITC Unrealized Losses (Gains) on Energy Contracts and Other Derivatives Non-Cash Employee Benefit Plan Costs Net Realized Gains and Income from NDT Funds Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies Accounts Receivable Accrued Interest Accounts Payable Accounts Receivable/Payable—Affiliated Companies, net Other Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from NDT Funds Sales NDT Funds Interest and Dividends Investment in NDT Funds Short-Term Loan—Affiliated Company, net Other Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Short-Term Loan—Affiliated Company, net Net Cash Used In Financing Activities Net (Decrease) Increase in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding PSEG Power LLC 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For The Quarters
Ended March 31, 2006 2005 (Millions)
(Unaudited) $ 112 $ 108 35 34 25 22 8 7 24 39 21 (13 ) 11 11 (18 ) (21 ) 413 404 187 171 55 54 (292 ) (385 ) 145 13 18 (10 ) (16 ) (30 ) (46 ) (40 ) 682 364 (118 ) (89 ) 300 1,378 10 7 (305 ) (1,383 ) (380 ) (185 ) 10 10 (483 ) (262 ) (202 ) (98 ) (202 ) (98 ) (3 ) 4 8 10 $ 5 $ 14 $ 18 $ 13 $ 2 $ 2
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. OPERATING REVENUES Electric Generation and Distribution Revenues Income from Leveraged and Operating Leases Other Total Operating Revenues OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax Expense INCOME FROM CONTINUING OPERATIONS Income from Discontinued Operations, net of tax expense of $1 and $2 NET INCOME Preference Units Distributions EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Energy Holdings L.L.C. 12
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS For The Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 263 $ 213 39 47 10 53 312 313 194 138 49 57 12 14 255 209 33 31 90 135 5 9 (5 ) (5 ) (50 ) (58 ) 40 81 (12 ) (14 ) 28 67 4 12 32 79 — (2 ) $ 32 $ 77
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable: Trade—net of allowances of $4 and $3 in 2006 and 2005, respectively Other Accounts Receivable Notes Receivable: Affiliated Companies Other Inventory Restricted Funds Assets of Discontinued Operations Derivative Contracts Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Leveraged Leases, net Corporate Joint Ventures Partnership Interests Goodwill and Other Intangibles Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding PSEG Energy Holdings L.L.C. 13
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 70 $ 68 99 103 18 14 58 409 5 5 25 27 64 62 522 498 2 — 8 7 871 1,193 1,570 1,560 (243 ) (237 ) 1,327 1,323 2,719 2,720 1,012 976 207 204 530 540 2 3 93 98 4,563 4,541 $ 6,761 $ 7,057
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. LIABILITIES AND MEMBER'S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable: Trade Affiliated Companies Derivative Contracts Accrued Interest Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment and Energy Tax Credits Derivative Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) MINORITY INTERESTS LONG-TERM DEBT Project Level, Non-Recourse Debt Senior Notes Total Long-Term Debt MEMBER'S EQUITY Ordinary Unit Retained Earnings Accumulated Other Comprehensive Loss Total Member's Equity TOTAL LIABILITIES AND MEMBER'S EQUITY See disclosures regarding PSEG Energy Holdings L.L.C. 14
CONDENSED CONSOLIDATED BALANCE SHEETS March 31,
2006 December 31,
2005 (Millions)
(Unaudited) $ 40 $ 348 47 50 23 13 11 13 48 42 441 436 54 83 664 985 1,704 1,705 30 27 66 66 1,800 1,798 15 15 880 891 1,448 1,448 2,328 2,339 1,713 1,713 349 317 (108 ) (110 ) 1,954 1,920 $ 6,761 $ 7,057
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Demand Side Management Amortization Deferred Income Taxes (Other than Leases) Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes Undistributed Earnings from Affiliates Gain on Sale of Investments Unrealized Gain on Investments Foreign Currency Transaction Gain Change in Fair Value of Derivative Financial Instruments Other Non-Cash Charges Net Changes in Certain Current Assets and Liabilities: Accounts Receivable Inventory Accounts Payable Other Current Assets and Liabilities Proceeds from Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Sale of Property Proceeds from the Sale of Investments and Return of Capital from Partnerships Short-Term Loan Receivable—Affiliated Company, net Restricted Funds Proceeds from Collection of Notes Receivable Other Net Cash Provided By Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Non-Recourse Long-Term Debt Repayment of Non-Recourse Long-Term Debt Repayment of Senior Notes Return of Capital Contributed Cash Distributions Paid on Preference Units Other Net Cash Used In Financing Activities Effect of Exchange Rate Change Net Increase In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding PSEG Energy Holdings L.L.C. 15
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS For The Quarters Ended
March 31, 2006 2005 (Millions)
(Unaudited) $ 32 $ 79 13 17 1 2 4 (6 ) (22 ) (26 ) (29 ) (19 ) (2 ) (45 ) (1 ) (2 ) (1 ) (3 ) 1 (1 ) — 3 25 2 3 8 (29 ) 11 4 11 1 61 1 — 1 92 (14 ) (13 ) 1 — 2 1 351 13 (17 ) (5 ) — 34 1 (5 ) 324 25 — 11 (12 ) (4 ) (309 ) — — (100 ) — (2 ) (1 ) — (322 ) (95 ) (1 ) (1 ) 2 21 68 183 $ 70 $ 204 $ 2 $ 1 $ 26 $ 52
included in the 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). As previously disclosed, on December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company headquartered in Chicago, Illinois, whereby PSEG will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock. The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger. The Merger Agreement provides that if the Merger is not consummated by June 20, 2006, either party may terminate the Merger Agreement. 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 right to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represents the irrevocable right 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 Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC). 16
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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, including power production facilities and electric distribution companies, 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 services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial services, investor relations, stockholder services, real estate, environmental, health and safety, insurance, risk management, tax, library, records and information services, security, corporate secretarial and certain planning, budgeting and forecasting 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. 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, 2005. 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, 2005. Certain reclassifications of prior period data have been made to conform with the current presentation. 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 17
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS federal subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. Components of Net Periodic Benefit Costs: Service Cost Interest Cost Expected Return on Plan Assets Amortization of Net Transition Obligation Prior Service Cost Loss Net Periodic Benefit Cost Effect of Regulatory Asset Total Benefit Costs PSE&G, Power, Energy Holdings and Services Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows: PSE&G Power Energy Holdings Services Total Benefit Costs Note 2. Recent Accounting Standards The following accounting standard was issued, but has not yet been adopted by PSEG as of March 31, 2006. Emerging Issues Task Force (EITF) Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty” (EITF 04-13) PSEG, PSE&G, Power and Energy Holdings EITF 04-13 concludes that inventory purchases and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined and treated as nonmonetary exchanges involving inventory. The consensus includes indicators that should be considered in determining whether transactions were entered into in contemplation of one another. The EITF also concludes that exchanges of finished goods for raw materials or work-in-process within the same line of business should be recognized at fair value if the transaction has commercial substance and fair value is determinable within reasonable limits. All other inventory exchanges should be recognized at carrying value. The provisions of EITF 04-13 are effective for new inventory arrangements entered into, or 18
(UNAUDITED) Pension Benefits OPEB Quarters Ended
March 31, Quarters Ended
March 31, 2006 2005 2006 2005 (Millions) $ 21 $ 23 $ 5 $ 5 53 52 17 14 (67 ) (63 ) (3 ) (2 ) — — 7 7 3 4 3 — 13 11 2 1 23 27 31 25 — — 5 5 $ 23 $ 27 $ 36 $ 30 Pension Benefits OPEB Quarters Ended
March 31, Quarters Ended
March 31, 2006 2005 2006 2005 (Millions) $ 12 $ 14 $ 30 $ 26 7 8 4 3 — — — — 4 5 2 1 $ 23 $ 27 $ 36 $ 30
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS modifications or renewals of existing inventory arrangements occurring in financial periods beginning after March 15, 2006. PSEG, PSE&G, Power and Energy Holdings do not believe that adoption of EITF 04-13 will have a material effect on their respective financial statements. The following accounting standards have been proposed by the Financial Accounting Standards Board (FASB). PSEG and Energy Holdings In July 2005, the FASB issued proposed guidance concerning the accounting for uncertain tax positions and the accounting for a change in the timing of cash flows relating to income taxes generated by leveraged lease transactions. The proposal concerning uncertain tax positions would require that an uncertain tax position meet a more likely-than-not recognition threshold based on the merits of the position in order for the benefit to be recognized in the financial statements. The proposal also addresses the accrual of interest and penalties related to tax uncertainties and the classification of liabilities on the balance sheet. If implemented in its present form, PSEG and Energy Holdings do not believe the impact of this proposal would be material. The proposal concerning leveraged leases would require a lessor to perform a recalculation of leveraged lease income when there is a change in the timing of the realization of tax benefits generated by the lease. If implemented in its present form, the proposal could have an impact on earnings of PSEG and Energy Holdings, which could be material. PSEG, PSE&G, Power and Energy Holdings On March 31, 2006, the FASB issued an exposure draft that would require recognition of the overfunded or underfunded positions of defined benefit pension and OPEB plans on the balance sheet. For an underfunded plan, the incremental liability to be recorded would be equal to the difference between the projected benefit obligation and the fair value of plan assets. Statement of Financial Accounting Standard (SFAS) No. 87, “Employers' Accounting for Pensions” (SFAS 87) and SFAS No. 106, “Employers' Accounting for Postretirement Benefits Other Than Pensions” (SFAS 106) allow for deferred recognition of this liability through amortization of this difference over time. Under this exposure draft, actuarial gains and losses and prior service costs and credits that arise during the period but, pursuant to SFAS 87 and SFAS 106 are not yet recognized as components of net periodic benefit cost, would be recognized as a component of Other Comprehensive Income, net of tax. For PSE&G, management believes the amounts not yet recognized would be recorded as a Regulatory Asset because the amortization of these costs is reflected in current rates. This would represent more than 50% of PSEG's unrecognized pension and OPEB costs. Such amounts would be adjusted as they are subsequently amortized as a component of net periodic benefit cost. The exposure draft also would require an adjustment to the beginning balance of retained earnings, net of tax, for any transition obligation remaining from the initial application of SFAS 87 and 106. Such amounts would then not subsequently be amortized as a component of net periodic benefit cost. PSEG, PSE&G, Power and Energy Holdings are currently evaluating the potential impact on their respective financial statements, which could be material, if the exposure draft is adopted as proposed. The following new accounting standards were adopted by PSEG during the first quarter of 2006. SFAS No. 123R, “Share-Based Payment, revised 2004” (SFAS 123R) PSEG Effective January 1, 2006, PSEG adopted SFAS No. 123R, which replaces SFAS 123, “Accounting for Stock-Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion No. 25, “ 19
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Accounting for Stock Issued to Employees” (APB 25). SFAS 123R focuses primarily on accounting for share-based awards to employees in exchange for services, and it requires entities to recognize compensation expense for these awards. The cost for equity-based awards is expensed based on their grant date fair value, and liability awards are expensed based on their fair value, which is re-measured each reporting period. The pro forma disclosure previously permitted under SFAS 123 is no longer an alternative to financial statement recognition. Prior to January 1, 2006, PSEG accounted for stock-based awards under the intrinsic value method of APB 25. In accordance with APB 25, PSEG did not record compensation expense related to its stock option grants because the strike price was equal to the fair value of the underlying stock on the grant date; however, it did record compensation expense over the requisite service period for restricted stock grants and performance unit awards. SFAS 123R is applicable to all of PSEG's outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective method. Accordingly, the financial results for prior periods were not retroactively adjusted to reflect the effects of SFAS 123R. The compensation expense recorded as a result of adopting SFAS 123R was not material. For additional information, see Note 12. Stock-Based Compensation. SFAS No. 151, “Inventory Costs” (SFAS 151) PSEG, PSE&G, Power and Energy Holdings In November 2004, the FASB issued SFAS 151, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material. This statement requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be recognized as current-period charges. In addition, this statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS 151 was effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The adoption of SFAS 151 did not have a material impact on the respective financial statements of PSEG, PSE&G, Power and Energy Holdings. FASB Staff Position (FSP) 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (FSP 115-1 and 124-1) PSEG, PSE&G, Power and Energy Holdings This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of the impairment loss. It also requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. This guidance applies to equity securities that have a readily determinable fair value and all debt securities. It does not apply to investments accounted for under the equity method. An investment is impaired if its fair value is less than its cost, as assessed at the individual security level. When an investment is impaired, the investor is required to evaluate whether the impairment is other-than-temporary. If other-than-temporary, the unrealized loss must be recognized. For all investments in an unrealized loss position for which other-than-temporary impairments have not been recognized, the investor should disclose by category of investment the amount of unrealized losses and the fair value of investments with unrealized losses and related narrative disclosures. FSP 115-1 and 124-1 was effective for reporting periods beginning after December 15, 2005. The adoption of this FSP did not have a material effect on PSEG's, PSE&G's, Power's or Energy Holdings' respective financial statements. 20
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 3. Discontinued Operations and Dispositions Discontinued Operations Power Waterford Generation Facility (Waterford) In September 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. Waterford's operating results for the quarter ended March 31, 2005, which have been reclassified to Discontinued Operations, are summarized below: Operating Revenues Loss Before Income Taxes Net Loss Energy Holdings Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina) On January 31, 2006, Global entered into an agreement with CEZ a.s. to sell its interest in two coal-fired plants in Poland, Elcho and Skawina, consistent with its strategy of monetizing assets on an opportunistic basis. The sale is expected to close in the second quarter of 2006 and is expected to yield cash proceeds in excess of $300 million after taxes and transaction costs, which is in excess of the book value of the facilities as of March 31, 2006. The agreement is subject to customary conditions, including government consents. The 2005 results for Global's assets in Poland have been reclassified to Discontinued Operations to reflect Energy Holdings' intention to sell these facilities. Elcho's and Skawina's operating results for the quarters ended March 31, 2006 and 2005 are summarized below: Operating Revenues Income Before Income Taxes Net Income The carrying amounts of the assets of Elcho and Skawina as of March 31, 2006 and December 31, 2005 are summarized in the following table: Current Assets Noncurrent Assets Total Assets of Discontinued Operations Current Liabilities Noncurrent Liabilities Total Liabilities of Discontinued Operations 21
(UNAUDITED) Quarter Ended
March 31,
2005 $ — $ 12 $ 7 Quarters Ended March 31, 2006 2005 Elcho Skawina Elcho Skawina $ 30 $ 33 $ 29 $ 36 $ 3 $ 2 $ 11 $ 3 $ 3 $ 1 $ 10 $ 2 As of
March 31,
2006 As of
December 31,
2005 Elcho Skawina Elcho Skawina (Millions) $ 55 $ 26 $ 41 $ 27 325 116 319 111 $ 380 $ 142 $ 360 $ 138 $ 34 $ 22 $ 27 $ 24 335 50 336 49 $ 369 $ 72 $ 363 $ 73
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Elcho's and Skawina's total non-recourse debt amounted to $288 million and $23 million as of March 31, 2006, respectively, and $287 million and $26 million as of December 31, 2005, respectively. Dispositions Energy Holdings Solar Electric Generating Systems (SEGS) Projects In January 2005, Resources and Global sold their minority limited partner interests in three SEGS projects for proceeds of approximately $7 million, resulting in an after-tax gain of $4 million. Dhofar Power Company S.A.O.C. (Dhofar Power) In April 2005, Global sold a 35% interest in Dhofar Power through a public offering on the Omani stock exchange as required under the Concession Agreement, reducing Global's ownership in Dhofar Power from 81% to 46%. Net proceeds from the sale approximated $25 million, resulting in an after-tax gain of approximately $1 million. As a result, Global's investment in Dhofar Power has been accounted for under the equity method following the sale. Meiya Power Company Limited (MPC) In January and April 2005, Global received payments of approximately $38 million and $99 million, respectively, representing the full payment of the receivable relating to the sale of its 50% equity interest in MPC in December 2004. Resources In January 2005, a KKR Fund, in which Resources had invested, sold its investment in KinderCare Learning Centers, Inc. and Resources received proceeds of approximately $17 million, resulting in an after-tax gain of approximately $1 million. 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, upon payment of performance units and upon conversion of Participating Units. The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS: 22
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS EPS Numerator: Earnings (Millions) Continuing Operations Discontinued Operations Net Income EPS Denominator (Thousands): Weighted Average Common Shares Outstanding Effect of Stock Options Effect of Stock Performance Units Effect of Participating Units Total Shares EPS: Continuing Operations Discontinued Operations Net Income Dividend payments on common stock for the quarter ended March 31, 2006 were $0.57 per share and totaled approximately $143 million. Dividend payments on common stock for the quarter ended March 31, 2005 were $0.56 per share and totaled approximately $134 million. Note 5. Commitments and Contingent Liabilities Guaranteed Obligations Power Power has unconditionally guaranteed payments by its subsidiary, ER&T, in certain commodity-related transactions in the ordinary course of business. These payment guarantees were provided to counterparties in order to obtain credit under physical and financial agreements for gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing 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 March 31, 2006 and December 31, 2005 was approximately $1.6 billion. In order for Power to incur a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T'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 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. The 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 $536 million and $549 million as of March 31, 2006 and December 31, 2005, respectively. Power is subject to collateral calls related to commodity contracts that are bilateral and is subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T's agreements. Changes in commodity prices, including fuel, emission allowances and electricity, can have an impact on 23
(UNAUDITED) Quarters Ended March 31, 2006 2005 Basic Diluted Basic Diluted $ 199 $ 199 $ 280 $ 280 4 4 5 5 $ 203 $ 203 $ 285 $ 285 251,187 251,187 238,314 238,314 — 787 — 1,028 — 91 — 111 — — — 2,737 251,187 252,065 238,314 242,190 $ 0.79 $ 0.79 $ 1.18 $ 1.16 0.02 0.02 0.02 0.02 $ 0.81 $ 0.81 $ 1.20 $ 1.18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS contract terms and conditions, as margin calls on contracts entered into in the normal course of business will change as commodity prices change. As of March 31, 2006, Power had paid cash margin of approximately $145 million and received cash margin of approximately $10 million. In addition, as of March 31, 2006, letters of credit issued by Power were outstanding in the amount of approximately $556 million (including $195 million issued to PSE&G) to satisfy trading collateral obligations and support various contractual and environmental obligations. Assuming no changes in forward energy prices and positions, Power's collateral requirements can be expected to decline over time as its contracts expire. 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 further performance assurance, generally in the form of a letter of credit or cash. As of March 31, 2006, if Power were to lose its investment grade rating and, assuming all counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to approximately $776 million. Power believes that it has sufficient access to liquidity to post such collateral, if necessary. Due to an increase in commodity prices subsequent to March 31, 2006, the amount of collateral posting requirements increased by approximately 35% as of April 28, 2006. 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. The guaranteed obligations as of March 31, 2006 and December 31, 2005 are as follows: Skawina (a) PSEG Global Funding II LLC Elcho (a) Prisma 2000 S.p.A. (Prisma) PSEG Energy Technologies Asset Management Company LLC Other Total Contingent Obligations 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 shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of March 31, 2006, there were $22 million of such bonds outstanding related to uncompleted construction projects and other obligations. These performance bonds are not included in the $127 million of guaranteed obligations above. 24
(UNAUDITED) As of Subsidiaries/Affiliates Location Description Expiration
Date March 31,
2006 December 31,
2005 (Millions) Poland Equity commitment August 2007 $ 9 $ 9 Delaware Contingent guarantee related to debt service obligations associated with Chilquinta April 2011 25 25 Poland Contingent guarantee related to debt service obligations October 2009 32 32 Italy Leasing agreement guarantee N/A 20 20 New Jersey Performance guarantee N/A 6 6 Various Various N/A 35 46 $ 127 $ 138 (a) Expected to be sold in 2006. For further information, see Note 3. Discontinued Operations and Dispositions.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In addition to the amounts discussed above, certain subsidiaries of Energy Holdings also have contingent obligations related to their respective projects, which are non-recourse to Energy Holdings. Environmental Matters PSEG, PSE&G and Power Hazardous Substances The New Jersey Department of Environmental Protection (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. These regulations may substantially increase the costs of environmental investigations and necessary remediation, particularly at sites situated on surface water bodies. PSE&G, Power and respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations is not currently estimable. However, neither PSE&G nor Power anticipates that compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows. The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a ‘facility' within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating electric generating station (Essex Site), one former generating station and four former manufactured gas plants (MGPs). PSE&G's costs to clean up former MGPs are recoverable from utility customers through the societal benefits clause (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric generating stations that PSE&G transferred to it, including the Essex Site. In 2003, the EPA notified 41 potentially responsible parties (PRPs), including 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. Power is evaluating recoverability of any disbursed amounts from its insurance carriers. Also, 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 New Jersey Spill Compensation and Control 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. PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 43 other PRPs, have executed an agreement with the EPA that provides for sharing the costs of the study between the government organizations and the PRPs. PSEG, PSE&G and Power cannot predict what further 25
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River or natural resource damages. 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 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 ten most significant sites for cleanup. One of the sites identified is a former MGP facility located in Camden, New Jersey. 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 March 31, 2006, PSE&G had expenditures of approximately $349 million. During the fourth quarter of 2005, PSE&G refined the detailed site 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 former MGP sites, could range between $751 million and $796 million. No amount within the range was considered to be most likely. Therefore, $402 million was accrued as of March 31, 2006, which represents the difference between the low end of the total program cost estimate of $751 million and the total incurred costs through March 31, 2006 of $349 million. Of this amount, approximately $43 million was recorded in Other Current Liabilities and $359 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 $402 million Regulatory Asset was recorded. PSE&G anticipates spending $44 million in 2006, $45 million in 2007 and an average of $35 million per year through 2016 to remediate MGP-related environmental conditions. New Jersey Clean Energy Program The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The liability for the funding requirement has been recorded at the discounted present value. The costs associated with this program will be recovered from PSE&G ratepayers over the four years and, therefore, a Regulatory Asset was also recorded. The liability for the funding requirement as of March 31, 2006 and December 31, 2005 was $313 million and $329 million, respectively. 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 is seeking to order companies allegedly 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 approximately $27,500 for each day of continued violation. The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the 26
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, 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. The cost of the program was approximately $110 million for installation of selective catalytic reduction systems (SCRs) at Mercer, as well as additional expenditures of approximately $400 million to $500 million at Hudson and $150 million to $250 million at Mercer for other pollution control equipment to be installed by December 31, 2006 and December 31, 2012, respectively. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence. Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution control equipment and other necessary modifications to the unit. Power will be unable to complete the installation of the pollution control equipment at Hudson by the December 31, 2006 deadline. Power has proposed to the NJDEP and the EPA an alternative pollution reduction plan to permit Hudson to continue to operate on coal beyond December 31, 2006. Discussions relating to this issue are ongoing. Power believes that system reliability concerns that PJM previously identified in the area may result in the unit continuing to operate after December 31, 2006, however no assurances can be given regarding the outcome of these discussions. Power cannot accurately determine all costs, including any penalties and limitations on operations, that may be associated with the continued operation of the Hudson unit beyond December 31, 2006, but such costs could be material. The costs associated with the pollution control modifications for the Hudson unit have not been included in Power's forecasted capital expenditures. Mercury Legislation New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires 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 effective in July 2008. The regulations in New Jersey require coal-fired electric generating units in New Jersey to meet certain emission limits or reduce emissions by 90% by December 15, 2007. 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. Power has a multi-pollutant reduction agreement with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. Substantial uncertainty exists regarding the feasibility of achieving the reductions in mercury emissions required by the New Jersey regulations and Connecticut statute; however, the estimated costs of technology believed to be capable of meeting these emissions limits at Power's coal-fired unit in Connecticut and at its Mercer Station are included in Power's capital expenditure forecast. Total estimated costs for the project are estimated between $300 million and $360 million. 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 applies to the sale of certain assets. Power had a $51 million liability as of March 31, 2006 and December 31, 2005 related 27
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS to these obligations, which is included in Other Noncurrent Liabilities on Power's Consolidated Balance Sheets and Environmental Costs on PSEG's 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 system. A renewal application prepared in accordance with the new Phase II 316(b) rule was filed with the NJDEP that allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power believes that its application to renew Salem's NJPDES permit demonstrates that the station 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. Power believes that the application further demonstrates that the station meets the Phase II 316(b) rule's site-specific determination standards without the benefits of restoration. If NJDEP were to require the installation of structures at the Salem facility to reduce cooling water intake flow commensurate with closed-cycle cooling as a result of an unfavorable decision in the Phase II litigation or otherwise, Power's application estimates that the costs associated with cooling towers for Salem are approximately $1 billion, of which Power's share would be approximately $575 million. These costs are not included in Power's currently forecasted capital expenditures. New Generation and Development Power Power completed construction of a natural gas-fired generation plant in Linden, New Jersey, which commenced commercial operation on May 1, 2006. Total costs, including interest capitalized during construction (IDC) of $214 million, were approximately $1.0 billion. Power also has contracts with outside parties to purchase upgraded turbines for Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to modestly increase its generating capacity. Phase II of the Salem Unit 2 turbine replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Phase II of the Hope Creek turbine replacement is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 120 MW. Power's expenditures to date approximate $209 million (including IDC of $18 million) with an aggregate estimated share of total costs for these projects of $247 million (including IDC of $27 million). Timing, costs and results of these projects are dependent on timely completion of work, timely approval from the NRC and various other factors. Completion of the projects discussed above within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete. Energy Holdings Electroandes S.A. (Electroandes) There is a 35 MW expansion project on an existing hydro station under development at Electroandes, a generating facility in Peru. Construction is expected to be completed in 2007 at a total cost of approximately $30 million. The project is expected to be financed by a Global subsidiary with cash and non-recourse debt. 28
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Basic Generation Service (BGS) Basic Gas Supply Service (BGSS) Power 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 below. In addition to the BGS-related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania and Connecticut, as well as other firm sales and trading positions and commitments. PSE&G and Power PSE&G is required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. The BGS auction process is a statewide process in which all of the New Jersey EDCs participate. The BGS auctions are “declining clock” auctions, where the EDCs accept offers for the amount of electric supply bidders are willing to offer with higher prices at the beginning of the auction. The auction proceeds when the amount of supply bid exceeds what is needed. The offer price is subsequently lowered and the process continues in a series of steps. When the amount of supply bid by the prospective suppliers matches an EDC's electric supply needs, the auction ends. The BPU renders a decision whether or not to accept the auction results within two business days of its conclusion. PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days of 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 Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any 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: Load (MW) $per kWh PSE&G entered into a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G's gas customers. Power has entered into hedges for a portion of its 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. 29
(UNAUDITED) Term Ending May 2006(a) May 2007(b) May 2008(c) May 2009(d) Term 34 months 36 months 36 months 36 months 2,900 2,840 2,840 2,882 $ 0.05560 $ 0.05515 $ 0.06541 $ 0.10251 (a) Prices set in the February 2003 BGS auction. (b) Prices set in the February 2004 BGS auction. (c) Prices set in the February 2005 BGS auction. (d) Prices set in the February 2006 BGS auction, which become effective on June 1, 2006.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Minimum Fuel Purchase Requirements Power Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to approximately $726 million through 2012. Power has various multi-year requirements-based purchase commitments that average approximately $89 million per year to meet Salem's and Hope Creek's nuclear fuel needs, of which Power's share is approximately $64 million per year through 2010. Power has been advised by the co-owner and operator of Peach Bottom, Exelon Generation LLC (Exelon Generation), that it has similar purchase contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power's share is approximately $29 million per year. 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. As of March 31, 2006, the total minimum requirements under these contracts were approximately $1.2 billion through 2016. These purchase obligations are aligned with Power's strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Energy Holdings The Guadalupe and Odessa plants of Texas Independent Energy, L.P. (TIE) have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. As of March 31, 2006, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sales contracts in place for approximately 50% of their expected output for the balance of 2006 and the sale of approximately 18% of their aggregate capacity for 2007 through 2010. The plants had fuel purchase commitments totaling $123 million to fully support such contracts. Operating Services Contract (OSC) Power Nuclear has entered into an OSC with Exelon Generation, which commenced on January 17, 2005, relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon Generation to provide a chief nuclear officer and other key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement the Exelon Generation operating model, which defines practices that Exelon Generation has used to manage its own nuclear performance program. 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 Generation 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. The OSC has a term of two years, subject to earlier termination in certain circumstances. In the event of termination, Exelon Generation will continue to provide services under the OSC for a transition period of at least 180 days and up to two years at the election of Nuclear. This period may be further extended by Nuclear for up to an additional 12 months if Nuclear determines that additional time is necessary to complete required activities during the transition period. 30
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 fossil generating units at market rates. The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered. Nuclear Fuel Disposal Power Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for such purpose to be available earlier than 2010. Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach Bottom's spent fuel storage requirements until at least 2014. Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred resulting from the DOE's delay in accepting spent nuclear fuel for permanent storage. Under this agreement, Power's portion of Peach Bottom's Nuclear Waste Fund fees was reduced by approximately $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon Generation's on-site storage facility. In September 2002, the U.S. Court of Appeals for the Eleventh Circuit issued an opinion upholding a petition seeking to set aside the receipt of these credits by Exelon Generation. On August 14, 2003, Exelon Generation received a letter from the DOE demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest. In August 2004, Exelon Generation advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation would be reimbursed for costs associated with the storage of spent nuclear fuel at the Peach Bottom facility, a portion of which would be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by DOE in 2005 for costs incurred between October 1, 2003 and June 30, 2005. 31
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. On October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims has jurisdiction over the matter. Power responded to this order in November 2004. On January 31, 2005, the Judge dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration in the U.S. Court of Federal Claims and jointly petitioned for permission to appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility. Spent Fuel Pool Power The spent fuel pool at each Salem unit has an installed leakage collection system. This system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. The NRC issued Information Notice 2004-05 in March 2004 concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter. Elevated concentrations of tritium in the shallow groundwater at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address the contamination in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. The costs necessary to address this onsite groundwater contamination issue are not expected to be material. 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 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. 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, which is still pending. On December 21, 2005, the Treasury proposed new regulations for comment addressing the normalization of ITC replacing regulations originally proposed in 2003. The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS's conclusions in the above referenced PLRs would continue to remain in effect for all industry deregulations prior to December 21, 2005. The BPU initiated generic proceedings on the ITC issue and requested all utilities to submit comments on the issue by February 21, 2006 with reply comments to be submitted by March 7, 2006. These comments were solicited even though the IRS has issued new proposed regulations for comment 32
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS and public hearing. PSE&G filed a letter response on February 15, 2006 requesting the BPU to take no further action until the IRS issues its final rule or PSE&G receives its PLR. On April 6, 2006, a conference was held between the IRS, PSEG and the BPU concerning PSE&G's private letter ruling request. At that conference, the IRS informed the participants that it had reached the tentative conclusion that no portion of the generation-related ITC in question may be passed on to utility customers without violating the normalization rules. The IRS provided a 21-day comment period in which the parties may provide additional information to be considered in the ruling process. On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue. PSE&G plans to aggressively contest the BPU's order to withdraw the request, as it is an important step in determining the appropriate application of federal tax law to PSE&G's specific facts. PSE&G cannot predict the outcome of the BPU order to withdraw the private letter ruling request. On April 27, 2006, the IRS extended the comment period deadline through May 8, 2006 and the BPU stayed its order to withdraw the PLR request through the same date. While it is expected that the IRS will issue the PLR sometime after the deadline, provided the request for the ruling is not withdrawn, the exact date of issuance cannot be predicted. PSE&G and the BPU are continuing to discuss the matter. While PSE&G cannot predict the outcome of these matters, a requirement to refund such amounts to customers would have a material adverse impact on PSEG's and PSE&G's financial condition, results of operations and net cash flows. BPU Deferral Audit PSEG and PSE&G The BPU Energy and Audit Division conducts audits of deferred balances. 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 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 $118 million. PSE&G and the BPU Staff are continuing discussions to resolve these questions and, if a resolution cannot be achieved, a BPU proceeding may be instituted to consider the issues raised. While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order on April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the outcome of any such proceeding. Leveraged Lease Investments PSEG and Energy Holdings Resources faces risks with regard to the creditworthiness of certain lessees that collectively comprise a substantial portion of Resources' investment portfolio. Resources also faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. 33
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of those transactions are similar to a type that the IRS subsequently announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of review and challenge by the IRS. As of each of March 31, 2006 and December 31, 2005, Resources' total gross investment in such transactions was approximately $1.4 billion. The IRS is presently reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2000, years when Resources entered into some of these transactions. On September 27, 2005, the IRS proposed to disallow PSEG's deductions associated with certain of these leveraged leases which have been designated by the IRS as “listed transactions”. Other lease transactions within the audit period are still under IRS review. The IRS may propose additional disallowances in the future. If deductions associated with these lease transactions entered into by PSEG are successfully challenged by the IRS, it could 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 proper based on applicable statutes, regulations and case law and believes that it should prevail with respect to any IRS challenge, although no assurances can be given. If the tax benefits associated with the above referenced lease transactions were completely disallowed by the IRS, approximately $693 million of PSEG's deferred tax liabilities that have been recorded under leveraged lease accounting through March 31, 2006 could become currently payable. In addition, interest expense of approximately $97 million, after-tax, and penalties could be assessed. Management assessed the probability of various outcomes to this matter and recorded appropriate reserves in accordance with SFAS No. 5 “Accounting for Contingencies.” Energy Holdings believes that such an outcome is unlikely. However, in the event that such a payment is required, Energy Holdings believes that, assuming certain asset monetizations of its investment portfolio, it has the financial capacity to meet this potential obligation. The FASB is currently considering a modification to GAAP for leveraged leases. Under present GAAP, a tax settlement with the IRS that results in a change in the timing of tax liabilities would not require an accounting repricing of the lease investment. As such, income from the lease would continue to accrue at the original economic yield computed for the lease and there would be no write-down of the lease investment. See Note 2. Recent Accounting Standards for additional information. Restructuring Charge Power In June 2005, Power implemented a plan to reduce its Nuclear workforce by approximately 200 positions. The plan included voluntary and involuntary separations offered to both represented and non-represented employees. The major cost associated with the restructuring relates to payments to the employees who are terminated. Power's $14 million share of the estimated total cost was recorded in 2005, approximately $7 million of which had been paid as of March 31, 2006. Retention Program PSEG The Retention Program, effective as of December 20, 2004, provides for payments to be made to certain key employees of PSEG who remain employed from the date of execution of the Merger Agreement through the date that is 90 days after the consummation of the Merger. The amount of a participant's retention payment may not be less than 40% or more than 150% of the participant's annual base salary. Retention payments under the Retention Program were not to exceed $10 million in the aggregate. 34
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG paid the first installment, equal to half of a participant's total retention payment, in December 2005, the first anniversary of the date of execution of the Merger Agreement. PSEG will pay the participants' remaining retention payments within 90 days after the consummation of the Merger. In April 2006, the Retention Program was amended to change maximum aggregate payments from $10 million to $15 million. Awards granted after March 31, 2006 are to be paid in one installment. No participant whose employment terminates for any reason other than involuntary termination without “cause” will receive any retention payment. A participant whose employment is terminated without “cause” on or prior to the payment of the final installment of the retention payment will be treated as if he or she remained employed through the date that is 90 days after consummation of the Merger for all purposes under the Retention Program. Severance Plan PSEG The Severance Plan provides change in control severance benefits to certain elected officers of PSEG whose employment is terminated without “cause” or who resign their employment for “good reason” within two years after a change in control, which would include the consummation of the Merger. Under the Severance Plan, the majority of the participants, if they are terminated without “cause” or resign employment for “good reason”, under the terms of the plan, will receive (1) a pro rata bonus based on the participant's target annual incentive compensation, (2) two times the sum of the participant's salary and target incentive bonus, (3) accelerated vesting of equity-based awards, (4) a lump sum payment equal to the actuarial equivalent of the participant's benefits under all of PSEG's retirement plans in which the participant participates calculated as though the participant remained employed for two years beyond the date his or her employment terminates less the actuarial equivalent of such benefits on the date his or her employment terminates, (5) two years continued welfare benefits (the first 18 months of which will be provided through PSEG-paid COBRA continuation coverage), (6) one year of PSEG-paid outplacement services and (7) vesting of any compensation previously deferred. Under the Severance Plan, five participants will receive the same benefits as the other participants, except that the applicable multiplier for salary and target incentive bonus, retirement plan accruals and continuation of welfare benefits is three years instead of two. Other Energy Holdings Rio Grande Energia S.A. (RGE) The governing tax authority in Brazil has claimed past due taxes from RGE plus penalties and interest for the periods 1998 to 2004 primarily related to claims that certain deductions were improper, certain changes in average depreciation rates made by RGE were not allowable and that the goodwill tax amortization period used by RGE for several years resulted in higher-than-allowed tax deductions. Global's share of the maximum claim amount related to these tax issues is approximately $27 million. RGE believes it has valid legal defenses to these claims. The court of first instance has ruled against RGE and RGE has appealed the lower court ruling, which remains pending. Although RGE believes its defenses to these claims are valid and will continue to vigorously contest this matter, no assurances can be given regarding the outcome. Between 1998 and September 2005, Sul Geradora Participacoes Ltda. (SGP) was a wholly owned subsidiary of RGE. Following new regulations issued by the national regulatory authority, 33.34% of SGP was sold to an indirect subsidiary of Global and the remainder was sold to a subsidiary of the majority owner of RGE in September 2005. In 2004, the Brazilian tax authority filed a tax assessment against SGP relating to a loan entered into between SGP and BankBoston N.A. denying the characterization of the loan as a withholding-free transaction for 2000, 2001 and 2002. The original 35
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS amount of the assessment is $15 million, including tax, penalty and interest. Global's indirect share of the claim is approximately $5 million. SGP believes it has valid defenses to these claims and has filed an appeal of the assessment, and it remains pending, although no assurances can be given regarding the outcome. Electroandes In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claiming past due taxes for 2002 totaling approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative estimated potential amount for past due taxes, including associated interest and penalties, is approximately $7 million through March 31, 2006. Electroandes believes it has valid legal defenses to these claims, and has filed for an appeal with SUNAT to which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter. Dhofar Power Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of unplanned service interruptions, including four in the first half of 2004, which resulted from a combination of force majeure events and breaches of general warranties of the contractors that installed equipment at Dhofar Power. Dhofar Power and the Government of Oman have been in a dispute regarding the applicability and extent of any penalties under Dhofar Power's Concession Agreement arising from these service interruptions. On July 14, 2005, the expert engaged by the parties recommended no penalties be assessed for the 2003 service interruptions and agreed with Dhofar Power's interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. The Government of Oman has exercised its right to appeal the expert's determination to a full arbitration panel. While Dhofar Power believes this matter will be favorably resolved in 2006, no assurances can be given. Dhofar Power and the Government of Oman are also in disagreement on the basis of the calculation of certain monthly allowances to be paid to compensate Dhofar Power for the capital investment costs associated with the enhancements and extensions of the transmission and distribution system in Salalah. On August 24, 2005, the expert engaged by the parties found in favor of Dhofar Power with respect to the criteria to be used in determining the monthly allowances. The Government has failed to properly exercise its right to appeal the expert's determination to a full arbitration panel but has not yet agreed to pay the sums awarded by the expert. Dhofar Power will seek to enforce the expert's determination that it is entitled to approximately $1 million annually for 15 years retroactive to December 2003 and believes that this matter will be favorably resolved in 2006, although no assurances can be given. 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 36
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. Derivative Instruments and Hedging Activities Power Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures. Energy Trading Contracts (ETCs) Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward and futures markets, primarily in PJM, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region. Power marks to market its derivative ETCs 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. 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. Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of March 31, 2006, Power had deposited margin of approximately $246 million related to such transactions. 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 conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs. Cash Flow Hedges Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of March 31, 2006, the fair value of these hedges was $(759) million. These hedges resulted in a $(443) million after-tax impact on Accumulated Other Comprehensive Loss (OCL). As of December 31, 2005, the fair value of these hedges was $(951) million. These hedges, along with realized gains on hedges of $11 million retained in OCL, resulted in a $(558) million after-tax impact on OCL. During the next 12 37
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS months, $194 million (after-tax) of net unrealized and realized losses on these commodity derivatives is expected to be reclassified to earnings. Approximately $174 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ended March 31, 2008. Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(10) million. The expiration date of the longest-dated cash flow hedge is in 2009. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as appropriate, on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of March 31, 2006 was $(16) million. The net fair value of these instruments as of December 31, 2005 was not material. Energy Holdings Other Derivatives TIE, an indirect, wholly owned subsidiary of Energy Holdings and Global, enters into electricity forward and capacity sale contracts to sell up to 1,500 MW of its 2,000 MW capacity for portions of the current calendar year, with the balance sold into the daily spot market. TIE also enters 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 TIE, 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 approximately $(12) million and $(7) million as of March 31, 2006 and December 31, 2005, respectively. Certain fixed price contracts that hedge a portion of TIE's output resulted in an unrealized loss, or opportunity cost for the quarter ended March 31, 2006, relative to current market prices. Such contracts can lead to significant earnings volatility in the future as these fixed price contracts that are supported by TIE's physical plant capacity are marked to market each period against current prices. 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 March 31, 2006 and December 31, 2005, the fair value of the hedge was $(12) million and $(10) million, respectively. 38
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 March 31, 2006, the fair value of these cash flow hedges was $(8) million, including $(6) million and $(2) million at PSE&G and Energy Holdings, respectively. As of December 31, 2005, the fair value of these cash flow hedges was $(17) million, including $(11) million and $(6) million at PSE&G and Energy Holdings, respectively. The $(6) million and $(11) million at PSE&G as of March 31, 2006 and December 31, 2005, 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 next 12 months, $(18) million of unrealized losses (net of taxes) on interest rate derivatives in OCL is expected to be reclassified to earnings, including $(1) million and $(17) million at PSEG and Energy Holdings, respectively. As of March 31, 2006, hedge ineffectiveness associated with these hedges was $(3) million. The fair value amounts above do not include approximately $(56) million and $(60) million as of March 31, 2006 and December 31, 2005, respectively, for the cash flow hedges at Elcho, which have been reclassified into Discontinued Operations. Other Derivatives Energy Holdings Energy Holdings has cross currency interest rate swaps whose changes in fair value were recorded in Income from Equity Method Investments on the Condensed Consolidated Statements of Operations. The fair value of these swaps was approximately $(2) million as of March 31, 2006 and December 31, 2005. Foreign Currencies Energy Holdings Global is exposed to foreign currency risk and other foreign operations risk 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 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 Brazilian Real, the Euro, the Peruvian Nuevo Sol and the Chilean Peso. Changes in valuation of these currencies can impact the value of Global's investments. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations. As of March 31, 2006, the net cumulative foreign currency devaluations have reduced the total amount of Global's Member's Equity by $29 million. In November and December 2005, Energy Holdings purchased foreign currency options in order to hedge the majority of its 2006 expected earnings denominated in Brazilian Real, Chilean Pesos and Peruvian Nuevo Soles. These options are not considered hedges for accounting purposes under SFAS 133 and, as a result, changes in their fair value are recorded directly to earnings. The fair value of these options was approximately $1 million and $2 million as of March 31, 2006 and December 31, 2005, respectively. On January 31, 2006, in connection with the sale of Elcho and Skawina, Energy Holdings 39
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS purchased options to sell Euros and receive U.S. Dollars at a rate of 1.17 Euros to the Dollar. These nine-month options will hedge more than 90% of the expected sale proceeds from a devaluation of the Euro relative to the U.S. Dollar prior to the closing of the sale. The fair value of these options, which are classified within Discontinued Operations, was approximately $4 million as of March 31, 2006. Hedges of Net Investments in Foreign Operations Energy Holdings In March 2004 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 to the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross currency swaps was $(29) million and $(33) million as of March 31, 2006 and December 31, 2005, respectively. The change in fair value is recorded net of tax in Cumulative Translation Adjustment within OCL. As a result, Energy Holdings' Member's Equity was reduced by $23 million as of March 31, 2006. Note 7. Comprehensive Income, Net of Tax For the Quarter Ended March 31, 2006: Net Income (Loss) Other Comprehensive Income Comprehensive Income (Loss) For the Quarter Ended March 31, 2005: Net Income (Loss) Other Comprehensive (Loss) Income Comprehensive Income (Loss) Note 8. Changes in Capitalization PSEG During the quarter ended March 31, 2006, PSEG issued approximately 266,000 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program for approximately $17 million. In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust. PSE&G On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds. In March 2006, Transition Funding repaid approximately $36 million of its transition bonds. 40
(UNAUDITED) PSE&G Power (A) Energy
Holdings (B) Other (C) Consolidated
Total (Millions) $ 78 $ 112 $ 32 $ (19 ) $ 203 — 133 2 1 136 $ 78 $ 245 $ 34 $ (18 ) $ 339 $ 118 $ 108 $ 79 $ (20 ) $ 285 — (110 ) (51 ) 2 (159 ) $ 118 $ (2 ) $ 28 $ (18 ) $ 126 (A) Changes at Power primarily relate to changes in SFAS 133 unrealized losses on derivative contracts that qualify for hedge accounting and unrealized gains and losses on Nuclear Decommissioning Trust (NDT) Funds. (B) Changes at Energy Holdings primarily relate to foreign currency translation adjustments and unrealized gains and losses on various derivative transactions. (C) Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes. Energy Holdings In January 2006, Energy Holdings redeemed $309 million of its 7.75% Senior Notes due in 2007. On February 17, 2006, the maturity of the Odessa–Ector Power Partners, L.P (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above LIBOR. As of September 29, 2006, Odessa's interest rate will be swapped to a fixed rate of 5.4275%. Note 9. Other Income and Deductions Other Income: For the Quarter Ended March 31, 2006: Interest Income NDT Fund Realized Gains NDT Interest and Dividend Income Foreign Currency Gains Other Total Other Income For the Quarter Ended March 31, 2005: Interest Income Gain on Disposition of Investments NDT Fund Realized Gains NDT Interest and Dividend Income Foreign Currency Gains Other Total Other Income Other Deductions: For the Quarter Ended March 31, 2006: Donations NDT Fund Realized Losses Foreign Currency Losses Change in Derivative Fair Value Other Total Other Deductions For the Quarter Ended March 31, 2005: Donations NDT Fund Realized Losses Foreign Currency Loss Other Total Other Deductions 41
(UNAUDITED) PSE&G Power Energy
Holdings Other (A) Consolidated
Total (Millions) $ 4 $ 2 $ — $ — $ 6 — 28 — — 28 — 10 — — 10 — — 2 — 2 — 1 3 (1 ) 3 $ 4 $ 41 $ 5 $ (1 ) $ 49 $ 2 $ 1 $ 6 $ — $ 9 — — 1 — 1 — 22 — — 22 — 7 — — 7 — — 1 — 1 — 1 1 1 3 $ 2 $ 31 $ 9 $ 1 $ 43 PSE&G Power Energy
Holdings Other (A) Consolidated
Total (Millions) $ 1 $ — $ — $ — $ 1 — 17 — — 17 — — 1 — 1 — — 1 — 1 — 2 3 1 6 $ 1 $ 19 $ 5 $ 1 $ 26 $ 1 $ — $ — $ — $ 1 — 7 — — 7 — — 5 — 5 — 1 — — 1 $ 1 $ 8 $ 5 $ — $ 14 (A) Other consists of reclassifications for minority interests in PSEG's consolidated results of operations and intercompany eliminations at PSEG (as parent company).
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS An analysis of the tax provision expense is as follows: For the Quarter Ended March 31, 2006: Income (Loss) before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit Plant Related Items Other Total Income Tax Expense (Benefit) Effective income tax rate For the Quarter Ended March 31, 2005: Income (Loss) before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit Rate Differential of Foreign Operations Plant Related Items Lease Rate Differential Other Total Income Tax Expense (Benefit) Effective Income Tax Rate 42
(UNAUDITED) PSE&G Power Energy
Holdings Other (A) Consolidated
Total (Millions) $ 143 $ 192 $ 40 $ (33 ) $ 342 $ 50 $ 67 $ 14 $ (12 ) $ 119 11 11 (2 ) (2 ) 18 3 — — — 3 1 2 — — 3 $ 65 $ 80 $ 12 $ (14 ) $ 143 45.5 % 41.7 % 30.0 % 42.4 % 41.8 % $ 204 $ 198 $ 81 $ (32 ) $ 451 $ 72 $ 69 $ 28 $ (11 ) $ 158 14 11 (2 ) (1 ) 22 — — (14 ) — (14 ) 1 — — — 1 — — 1 — 1 (1 ) 3 1 — 3 $ 86 $ 83 $ 14 $ (12 ) $ 171 42.2 % 41.9 % 17.3 % 37.5 % 37.9 % (A) PSEG's other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 11. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below: For the Quarter Ended March 31, 2006: Total Operating Revenues Income (Loss) From Continuing Operations Income from Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets As of March 31, 2006: Total Assets Investments in Equity Method Subsidiaries For the Quarter Ended March 31, 2005: Total Operating Revenues Income (Loss) From Continuing Operations Income (Loss) from Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets As of December 31, 2005: Total Assets Investments in Equity Method Subsidiaries Note 12. Stock-Based Compensation PSEG As approved at the Annual Meeting of Stockholders in 2004, PSEG's 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004 LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance shares, restricted stock, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase shares of PSEG's common stock, restricted stock awards and performance unit awards. However, since 2004, only restricted stock has been granted. 43
(UNAUDITED) Energy Holdings PSE&G Power Resources Global Other (A) Other (B) Consolidated
Total (Millions) $ 2,350 $ 1,967 $ 47 $ 263 $ 2 $ (1,108 ) $ 3,521 78 112 20 9 (1 ) (19 ) 199 — — — 4 — — 4 78 112 20 13 (1 ) (19 ) 203 (1 ) — — — — 1 — 77 112 20 13 (1 ) (18 ) 203 108 118 — 14 — — 240 $ 14,132 $ 8,488 $ 2,890 $ 3,764 $ 107 $ (525 ) $ 28,856 $ — $ — $ 16 $ 1,164 $ — $ — $ 1,180 $ 2,184 $ 1,730 $ 61 $ 250 $ 2 $ (983 ) $ 3,244 118 115 23 45 (1 ) (20 ) 280 — (7 ) — 12 — — 5 118 108 23 57 (1 ) (20 ) 285 (1 ) — — (2 ) — 3 — 117 108 23 55 (1 ) (17 ) 285 93 89 1 12 — 2 197 $ 14,291 $ 8,945 $ 2,874 $ 3,799 $ 384 $ (478 ) $ 29,815 $ — $ — $ 15 $ 1,128 $ — $ — $ 1,143 (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.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 13.0 million shares of common stock. As of March 31, 2006, there were 11.8 million shares available for future awards under the 2004 LTIP. Stock Options Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees of PSEG and its subsidiaries selected by the Organization and Compensation Committee of PSEG's Board of Directors, the plan's administrative committee (Committee). Option awards are granted with an exercise price equal to the market price of PSEG's common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control, retirement, death or disability. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG common stock. PSEG purchases shares on the open market to meet the exercise requirements of stock options. Restricted Stock Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted stock generally vests annually over three years, but are considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain events, such as change in control (unless substituted with an equity award of equal value), retirement, death or disability. In addition, from 1998 to 2001, PSEG granted 210,000 shares of restricted stock to a key executive, which are subject to risk of forfeiture until vested by continued employment. The shares vest on a staggered schedule through March 2007. PSEG issues restricted stock from treasury stock. Performance Units Under the 2004 LTIP, performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over the 2004 through 2006 three-year period. The payout varies from 0% to 200% of performance units depending on PSEG's performance compared to the performance of other companies in the Dow Jones Utilities Index. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. Vesting may be accelerated upon certain events such as change in control, retirement, death or disability. Stock-Based Compensation Effective January 1, 2006, PSEG adopted SFAS 123R. See Note 2. Recent Accounting Standards for a description of the adoption of SFAS 123R. As a result, all outstanding unvested stock options as of January 1, 2006 are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. Prior to the adoption of SFAS 123R, PSEG recognized compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to recognize compensation expense over the vesting term. 44
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Also prior to the adoption of SFAS 123R, PSEG recognized compensation expense for performance units. The fair value of each performance unit was based on the grant date fair value of PSEG stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is estimated at 100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome. Compensation cost from options, restricted stock and performance units is included in Operation and Maintenance Expense in PSEG's Condensed Consolidated Statements of Operations and amounted to approximately $3.3 million and $1.5 million for the quarters ended March 31, 2006 and 2005, respectively. The total income tax benefit recognized in PSEG's Condensed Consolidated Statements of Operations was approximately $1.4 million and $0.6 million for the quarters ended March 31, 2006 and 2005, respectively. Compensation cost capitalized as part of property, plant and equipment was less than $0.1 million for each of the quarters ended March 31, 2006 and 2005. Of the total compensation cost for the quarter ended March 31, 2006, approximately $0.3 million, or $0.2 million after-tax, related to the adoption of SFAS 123R, which was primarily due to expensing stock options for the first time. There was no impact on basic and diluted earnings per share from the implementation of SFAS 123R because there were a relatively small number of outstanding unvested stock options as of the implementation date. Prior to the adoption of SFAS 123R, PSEG presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows in the Condensed Consolidated Statement of Cash Flows. SFAS 123R requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. There was approximately $12.1 million of excess tax benefits included as a financing cash inflow in the March 31, 2006 Condensed Consolidated Statements of Cash Flow. Total cash flow will remain unchanged from what would have been reported under prior accounting rules. The following table illustrates the effect on net income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS 123R for the quarter ended March 31, 2005. Net Income, as reported Add: Total stock-based compensation expensed during Deduct: Total stock-based employee compensation Pro forma Net Income Earnings per share: Basic—as reported Basic—pro forma Diluted—as reported Diluted—pro forma Prior to the adoption of SFAS 123R, PSEG recognized the compensation cost of stock based awards issued to retirement eligible employees that fully or partially vest upon an employee's retirement over the nominal vesting period of performance, and recognized any remaining compensation cost at the date of retirement. In accordance with SFAS 123R, PSEG recognizes compensation cost of awards issued after January 1, 2006 over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is retirement eligible and the award vests. 45
(UNAUDITED) Quarter Ended
March 31, 2005 (Millions, except Share Data) $ 285
the period, net of tax 1
expense determined under fair value based method
for all awards, net of related tax effects (1 ) $ 285 $ 1.20 $ 1.20 $ 1.18 $ 1.18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Stock Option Information There were no options granted during 2005 or 2006. Changes in stock options for the quarter ended March 31, 2006 are summarized as follows: Outstanding at January 1, 2006 Granted Exercised Canceled Outstanding at March 31, 2006 Exercisable at March 31, 2006 The intrinsic value of options is the difference between the current market price and the exercise price. The total intrinsic value of options exercised during the quarters ended March 31, 2006 and 2005 was approximately $29.5 million and $24.6 million, respectively. During the quarters ended March 31, 2006 and 2005, cash received from stock options exercised was approximately $39.8 million and $59.6 million, respectively. The tax benefit realized from stock options exercised was approximately $12.1 million and $10.1 million, respectively. As of March 31, 2006, there was approximately $0.9 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of eight months. Restricted Stock Information Changes in restricted stock for the quarter ended March 31, 2006 are summarized as follows: Outstanding at January 1, 2006 Granted Vested Canceled Outstanding at March 31, 2006 The weighted average grant date fair value per share was $51.87 for restricted stock awards granted during the first quarter of 2005. The total intrinsic value of restricted stock vested during the quarter ended March 31, 2006 was approximately $6.1 million. No restricted shares vested during the quarter ended March 31, 2005. As of March 31, 2006, there was approximately $22.2 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 2.3 years. Performance Units Information As of January 1, 2006 and March 31, 2006, 83,600 performance units were outstanding and unvested, and approximately 7,200 dividend equivalents had accrued on these performance units. The grant date fair value of the performance units is $42.75 per unit. 46
(UNAUDITED) Options Shares Weighted
Average
Exercise
Price Weighted
Average
Remaining
Contractual
Term Aggregate
Intrinsic
Value 3,981,555 $ 41.07 — — (1,020,822 ) 38.96 — — 2,960,733 $ 41.80 5.9 years $ 65,851,600 2,521,952 $ 41.64 5.6 years $ 56,501,200 Options Shares Weighted
Average
Exercise
Price Weighted
Average
Remaining
Contractual
Term Aggregate
Intrinsic
Value 466,744 $ 56.69 43,800 66.53 (87,047 ) 51.90 (1,068 ) 55.96 422,429 $ 58.70 2.2 years $ 27,052,353
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Assuming performance units are paid out at the 100% performance level, the total intrinsic value of performance units outstanding at March 31, 2006 is approximately $5.8 million. As of March 31, 2006, there was approximately $1.1 million of unrecognized compensation cost related to performance units, which is expected to be recognized over the next nine months. Outside Directors During 2006, each director who was not an officer of PSEG or its subsidiaries and affiliates will be paid an annual retainer of $50,000. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently 50%, of the annual retainer is paid in PSEG common stock. PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as compensation expense in the Condensed Consolidated Statements of Operations. Compensation expense for the Outside Directors stock plan was less than $0.2 million for each of the quarters ended March 31, 2006 and 2005. Employee Stock Purchase Plan PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During the quarters ended March 31, 2006, and 2005, employees purchased 15,615 and 19,862 shares at an average price of $60.60 and $51.65 per share, respectively. As of March 31, 2006, 1,863,722 shares were available for future issuance under this plan. Note 13. Related-Party Transactions The majority of the following discussion relates to intercompany transactions, which are eliminated during the consolidation process in accordance with GAAP. BGS and BGSS Contracts PSE&G and Power PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G's BGSS and other contractual requirements through March 2007. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The amounts which Power charged to PSE&G for BGS and BGSS are presented below: BGS BGSS 47
(UNAUDITED) Power's Billings for
the Quarters Ended
March 31, 2006 2005 (Millions) $ 101 $ 113 $ 1,003 $ 862
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of March 31, 2006 and December 31, 2005, Power had net receivables from PSE&G of approximately $336 million and $454 million, respectively, primarily related to the BGS and BGSS contracts. These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements. In addition, as of March 31, 2006 and December 31, 2005, PSE&G had a payable to Power of approximately $23 million and a receivable of approximately $152 million, respectively, related to gas supply hedges Power entered into for BGSS. 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: PSE&G Power Energy Holdings These transactions were properly recognized on each company's stand-alone financial statements and were eliminated when preparing PSEG's Condensed Consolidated Financial Statements. 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) receivables from PSEG related to taxes as follows: PSE&G Power Energy Holdings Affiliate Loans and Advances PSEG and Power As of March 31, 2006, Power had a note receivable due from PSEG of approximately $380 million, reflecting the investment of its excess cash with PSEG. As of December 31, 2005, Power had a payable to PSEG of approximately $202 million for short-term funding needs. Interest Income and Interest Expense relating to these short-term funding activities was immaterial. 48
(UNAUDITED) Services' Billings for the
Quarters Ended
March 31, Payable to Services as of 2006 2005 March 31,
2006 December 31,
2005 (Millions) $ 55 $ 50 $ 32 $ 34 $ 37 $ 38 $ 18 $ 21 $ 5 $ 4 $ 2 $ 2 (Payable to) Receivable from PSEG
As of March 31,
2006 December 31,
2005 (Millions) $ (130 ) $ (59 ) $ (26 ) $ 4 $ (21 ) $ (12 )
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSEG and Energy Holdings As of March 31, 2006 and December 31, 2005, Energy Holdings had a note receivable due from PSEG of $58 million and $409 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings was immaterial. PSE&G and Services As of March 31, 2006 and December 31, 2005, PSE&G had advanced working capital to Services of approximately $33 million. This amount is included in Other Noncurrent Assets on PSE&G's Condensed Consolidated Balance Sheets. Power and Services As of March 31, 2006 and December 31, 2005, Power had advanced working capital to Services of approximately $18 million. This amount is included in Other Noncurrent Assets on Power's Condensed Consolidated Balance Sheets. Other PSEG and PSE&G As of March 31, 2006 and December 31, 2005, PSE&G had receivables from PSEG of approximately $9 million and $6 million, respectively, related to amounts that PSEG had collected on PSE&G's behalf. PSEG and Power As of March 31, 2006 and December 31, 2005, Power had receivables from PSEG of approximately $4 million and $2 million, respectively, related to amounts that PSEG had collected on Power's behalf. Energy Holdings Global had loans of approximately $61 million and $60 million due from Prisma, a joint venture that is 50%-owned by Global and operates several biomass generation plants in Italy, as of March 31, 2006 and December 31, 2005, respectively. Included in the loan balances were $25 million and $24 million of accrued interest as of March 31, 2006 and December 31, 2005, respectively. These loans are guaranteed by an affiliate of Global's partner. Due to insufficient funds at the project level, total payments of $12 million due to Global on June 30, 2005, September 30, 2005 and December 31, 2005 were not made. In August 2005, Global began seeking to enforce its rights under the guarantee by filing a legal action. In January 2006, Global and its partner entered into an agreement under which Global agreed to forgive the guarantee of the project's loans and convert a portion of the loans into an equity interest. Global expects to close on the agreement in the second quarter of 2006. As a result, Global expects to increase its ownership percentage in Prisma to 85% and obtain voting control of the project through proportionate representation on Prisma's Board of Directors. Once the transaction is completed, Global will begin consolidating Prisma. 49
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. For the Quarter Ended March 31, 2006: Operating Revenues Operating Expenses Operating Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Net Income (Loss) For the Quarter Ended March 31, 2006: Net Cash Provided By (Used In) Operating Activities Net Cash (Used In) Provided By Investing Activities Net Cash Provided By (Used In) Financing Activities For the Quarter Ended March 31, 2005: Operating Revenues Operating Expenses Operating Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Loss from Discontinued Operations, net of tax benefit Net Income (Loss) For the Quarter Ended March 31, 2005: Net Cash (Used In) Provided By Operating Activities Net Cash Provided By (Used In) Investing Activities Net Cash (Used In) Provided By Financing Activities 50
(UNAUDITED) Power Guarantor
Subsidiaries Other
Subsidiaries Consolidating
Adjustments Consolidated
Total (Millions) $ — $ 2,194 $ 33 $ (260 ) $ 1,967 — 1,984 33 (260 ) 1,757 — 210 — — 210 113 (11 ) — (102 ) — 40 45 — (44 ) 41 — (19 ) — — (19 ) (43 ) (22 ) (19 ) 44 (40 ) 2 (89 ) 7 — (80 ) $ 112 $ 114 $ (12 ) $ (102 ) $ 112 $ 810 $ (605 ) $ (3 ) $ 480 $ 682 $ (810 ) $ 588 $ 3 $ (264 ) $ (483 ) $ — $ 13 $ — $ (215 ) $ (202 ) $ — $ 1,949 $ 34 $ (253 ) $ 1,730 — 1,753 26 (252 ) 1,527 — 196 8 (1 ) 203 108 (9 ) — (99 ) — 31 31 — (31 ) 31 — (8 ) — — (8 ) (32 ) (17 ) (11 ) 32 (28 ) 1 (85 ) 1 — (83 ) — — (7 ) — (7 ) $ 108 $ 108 $ (9 ) $ (99 ) $ 108 $ (48 ) $ 141 $ (12 ) $ 283 $ 364 $ 48 $ (17 ) $ (21 ) $ (272 ) $ (262 ) $ — $ (121 ) $ 34 $ (11 ) $ (98 )
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of March 31, 2006: Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Long-Term Debt Member's Equity Total Liabilities and Member's Equity As of December 31, 2005: Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Long-Term Debt Member's Equity Total Liabilities and Member's Equity 51
(UNAUDITED) Power Guarantor
Subsidiaries Other
Subsidiaries Consolidating
Adjustments Consolidated
Total (Millions) $ 3,139 $ 2,922 $ 251 $ (4,201 ) $ 2,111 151 3,302 1,467 — 4,920 3,753 442 — (4,195 ) — 189 1,554 15 (301 ) 1,457 $ 7,232 $ 8,220 $ 1,733 $ (8,697 ) $ 8,488 $ 1,261 $ 3,366 $ 1,153 $ (4,196 ) $ 1,584 71 1,139 100 (305 ) 1,005 2,817 — — — 2,817 3,083 3,715 480 (4,196 ) 3,082 $ 7,232 $ 8,220 $ 1,733 $ (8,697 ) $ 8,488 $ 2,584 $ 2,616 $ 251 $ (2,876 ) $ 2,575 143 3,271 1,466 — 4,880 3,507 453 — (3,960 ) — 179 1,609 17 (315 ) 1,490 $ 6,413 $ 7,949 $ 1,734 $ (7,151 ) $ 8,945 $ 695 $ 3,213 $ 1,146 $ (2,877 ) $ 2,177 63 1,268 96 (313 ) 1,114 2,817 — — — 2,817 2,838 3,468 492 (3,961 ) 2,837 $ 6,413 $ 7,949 $ 1,734 $ (7,151 ) $ 8,945
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL Following are the significant changes in or additions to information reported in the 2005 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 representations as to any other company. PSEG, PSE&G, Power and Energy Holdings On December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon), a public utility holding company headquartered in Chicago, Illinois, whereby PSEG and its subsidiaries will be merged with and into Exelon (Merger). Under the Merger Agreement, each share of PSEG Common Stock will be converted into 1.225 shares of Exelon Common Stock. The Merger Agreement has been unanimously approved by both companies' Boards of Directors. On July 19, 2005, shareholders of PSEG voted to approve the Merger and on July 22, 2005, shareholders of Exelon voted to approve the issuance of common shares to PSEG shareholders to effect the Merger. Completion of the Merger is subject to approval by a number of governmental authorities. PSEG and Exelon have obtained all regulatory approvals from the principal agencies involved except the Nuclear Regulatory Commission (NRC), U.S. Department of Justice (DOJ) and the New Jersey Board of Public Utilities (BPU). The NRC proceeding is essentially complete, and an order is pending. The DOJ is reviewing the Merger for competitive issues. It is anticipated that divestiture of some generating facilities will be required by the DOJ. Settlement discussions are being conducted in an effort to complete the DOJ process consistent with the mitigation proposal approved by the Federal Energy Regulatory Commission (FERC) and prior to an issuance of an order by the BPU. In New Jersey, the BPU issued an order on June 20, 2005, requiring Exelon and PSEG to prove that positive benefits flow to PSE&G's customers and the State of New Jersey as a result of the Merger, and that, at a minimum, there be no adverse impact to competition, employees or reliability due to the Merger. In late November 2005, the BPU concluded five public hearings at which representatives from business, environmental coalitions, non-profit organizations and consumer groups offered opinions about the Merger. Representatives of the four unions representing workers at PSEG testified in support of the Merger upon reaching an agreement with PSEG and Exelon that there will be no layoffs of union workers in New Jersey through the expiration of the current collective bargaining agreement on April 30, 2011. The hearings related to the BPU review of the Merger commenced on January 4, 2006 at the New Jersey Office of Administrative Law and, in accordance with a schedule approved by the ALJ, concluded on March 31, 2006. The PJM Market Monitor submitted his analysis of the adequacy of the proposal by PSEG and Exelon to mitigate market power of the new company through the sale of 4,000 MW of fossil generation and the virtual divestiture of 2,600 MW of nuclear generation, which is the market mitigation package that was approved by the FERC in its order on July 1, 2005. During the hearings, other parties proposed additional divestiture and opposed the use of virtual divestiture to 52
CONDITION AND RESULTS OF OPERATIONS (MD&A)
address market power issues. During the hearings, PSEG and Exelon also committed to provide rate credits to PSE&G's customers of $120 million over three or four years, to maintain PSE&G's capital expenditure program and to implement certain governance procedures. The ALJ's most recent schedule provides for initial briefs by April 26, 2006 and for reply briefs by May 10, 2006. Settlement discussions have resumed. Unless extended, New Jersey rules provide for an ALJ decision on June 26, 2006 and a BPU decision on August 9, 2006. Commonwealth Edison Co. (ComEd), a wholly owned subsidiary of Exelon providing retail electric service in Illinois, is involved in regulatory proceedings in Illinois pertaining to the restructuring of the Illinois electric markets, which began in 1997. Since that time, the rates of ComEd have been reduced and capped, and ComEd transferred or sold its generation assets to third parties or to its affiliate, Exelon Generation LLC (Exelon Generation). Currently, the rate freeze for ComEd and contractual power supply obligations of Exelon Generation to ComEd expire December 31, 2006. In January 2006, the Illinois Commerce Commission (ICC) approved, with certain modifications, a proposal by ComEd to procure power commencing January 1, 2007 through an auction designed to reflect market rates. Various parties to the proceeding, including the Illinois Attorney General and the Citizens Utility Board have requested the ICC to reconsider its decision, and have filed appeals to the courts for review of portions of the order. In addition, legislation has been introduced in the Illinois General Assembly to continue ComEd's rate freeze for an additional three years. ComEd has indicated that it believes that enactment of such legislation would violate Federal law and the U.S. Constitution. Nevertheless, ComEd has indicated that it cannot predict the outcome of these regulatory proceedings and legislative actions and that a rate freeze extension or other significant constraint on its ability to recover its power supply costs would have materially adverse financial and operating effects and would likely cause ComEd to resort to protection of the bankruptcy courts to continue as a going concern. ComEd has also filed an electric distribution rate case with the ICC to reset its electric distribution rates effective January 1, 2007 and to recover the purchase power costs incurred through the procurement auction discussed above. The results in this rate proceeding are not expected to be known until at least the third quarter of 2006 and an ICC Order in July 2006. The regulatory and political developments in Illinois could also have an effect on the timing or closing conditions of the Merger. Exelon and PSEG presently expect to complete all of the regulatory reviews and close the Merger in the third quarter of 2006. The Merger Agreement provides that if the Merger is not consummated by June 20, 2006, either party may terminate the Merger Agreement. Although Exelon and PSEG believe that the expectations as to timing for the closing of the Merger described above are reasonable, no assurances can be given as to the timing of the receipt of any remaining regulatory approvals, that all required approvals will be received, or that conditions in future regulatory orders will be acceptable to the parties or not have materially adverse conditions. PSEG is committed to maintaining a viable stand-alone business strategy in the event the Merger does not close. Management believes PSEG will continue to operate successfully; however, inability to close the Merger could have an adverse impact on PSEG's and Power's credit ratings and could materially impact the financial condition, results of operations and cash flows of PSEG, PSE&G, Power and Energy Holdings. OVERVIEW OF 2006 AND FUTURE OUTLOOK PSEG 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 is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG's businesses within these markets and significant events that have occurred during the first quarter of 2006 and expectations for the full year 2006 and beyond. PSEG develops a long-range growth target by building business plans and financial forecasts for each major business (PSE&G, Power, Global and Resources). These plans and forecasts incorporate detailed estimates of revenues, operating and maintenance expenses, capital expenditures, financing costs and other material factors for each business. Key factors that may influence the performance of each business, such as fuel costs and forward power prices, are also incorporated. Sensitivity analyses 53
are performed on the key variables that drive the businesses' financial results in order to understand the impact of these assumptions on PSEG's projections. Once plans are in place, PSEG management monitors actual results and key variables and updates financial projections to reflect changes in the energy markets, the economy and regional and global conditions. PSEG management believes this monitoring and forecasting process enables it to alter operating and investment plans as conditions change. For the quarter ended March 31, 2006, PSEG had Income from Continuing Operations of $199 million, or $0.79 diluted per share, discussed below in Results of Operations. PSEG continues to project Income from Continuing Operations to range from $3.45 to $3.75 per share, excluding Merger-related costs and any potential impacts from mark-to-market (MTM) accounting although the range of expected earnings from each of PSE&G, Power and Energy Holdings has been revised. Projected earnings as compared to the $3.64 per share in 2005 reflect higher earnings at Power, offset by modest reductions at PSE&G and Energy Holdings and are based on a higher weighted average number of shares outstanding. The projections for 2006 also include $60 million to $70 million of expenses at the PSEG parent level, primarily for financing costs. In addition, PSEG anticipates earnings per share growth to be in excess of 10% per year for 2007 and 2008, which assumes continued improved operations at Power and reasonable outcomes in PSE&G's regulatory proceedings. PSEG expects operating cash flows in 2006 and beyond to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses, increase dividends or, in the longer term, repurchase shares. On January 17, 2006, PSEG announced an increase in its quarterly dividend from $0.56 to $0.57 per share for the first quarter of 2006. On April 18, 2006, PSEG's Board of Directors approved a common stock dividend of $0.57 per share for the second quarter of 2006. These increases reflect an indicated annual dividend rate of $2.28 per share. Several key factors that will drive PSEG's future success are energy, capacity and fuel prices, performance of Power's generating facilities, PSE&G's ability to maintain a reasonable rate of return under its regulated rate structure and the stability of international economies for Energy Holdings. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the BPU for its distribution operations and by the 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. In February 2006, 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. BGS-FP and BGS-CIEP represent approximately 84% and 16%, respectively, of PSE&G's BGS-eligible load. The February 2006 BGS-FP auction sought approximately one-third of PSE&G's BGS-FP eligible load (2,882 MW), since contracts for the other two-thirds were procured through the 2005 and 2004 auctions. The 2006 clearing price for PSE&G's BGS-FP load was 10.251 cents per kWh, an increase of approximately 57% over the 2005 auction price. The term of the supply period is from June 2006 through May 2009. Due to the stabilizing effect of the portfolio approach (blending this year's price with the prices set in the auctions in 2005 and 2004), residential customers' bills are expected to increase by approximately 14% beginning June 1, 2006. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to appropriately recover the cost of gas delivery and to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates. The balance of the request will cover the return on increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002. The current schedule provides for a decision on the gas base rate case from the BPU in December 2006, with the new rates effective immediately. PSE&G cannot predict the timing and amount of any rate relief. 54
In addition, as part of the settlement of PSE&G's electric base rate case in 2003, a $64 million annual depreciation rate credit was established. The excess depreciation reserve related to this credit was fully amortized as of December 31, 2005. As part of the settlement, PSE&G was required to make a financial filing with the BPU in November 2005 to support the elimination of the depreciation rate credit. The BPU issued an order on February 7, 2006 and found that insufficient information had been provided to support the elimination of the credit at this time. The order permits PSE&G to file, no later than June 15, 2006, actual data through March 31, 2006. The BPU will determine, based on the additional information, if the elimination of the depreciation rate credit is warranted. The impact of not eliminating the depreciation rate credit reduces PSE&G's earnings and cash flows by more than $5 million (pre-tax) per month. The timing and amount of an increase cannot be predicted with certainty. PSE&G expects that final resolution of this case will likely be determined by the fall of 2006. Action on PSE&G's recent filings, including the excess depreciation rate credit and the gas base rate case, has been subject to ongoing delays. It appears that until the merger is resolved with the BPU, decisions on PSE&G's requests may be difficult to achieve. For the quarter ended March 31, 2006, PSE&G had Net Income of $78 million. Based on these results and the delayed decisions for the current Gas Base Rate Case and the elimination of the $64 million electric distribution rate credit (approximately $68 million based on current sales volumes), PSE&G has lowered its previous guidance range for Income from Continuing Operations of $315 million to $335 million to a revised guidance range of $270 million to $290 million for 2006. These ranges exclude any merger-related costs. The risks from this 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. In 2006 and beyond, PSE&G's success will depend, in part, on its ability to maintain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continue to recover with an adequate return the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. 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. Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana. 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. Through its subsidiaries, Power seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear operations and pursue modest growth based on market conditions. 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. In addition to the electric generation business described above, 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 prices of commodities, such as electricity, gas, coal and emissions, as well as the availability of Power's diverse fleet of generation units to produce these products can have a material effect on Power's profitability. Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output 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. 55
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, a significant portion of Power's existing contractual obligations, entered into during lower-priced periods, resulted 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. For Power's BGSS contracts, commodity costs are passed on to residential customers. Any differences from the BGSS contract prices are deferred by PSE&G for future recovery. For commercial and industrial customers, a tariff structure is applied that is adjusted monthly based on the current New York Mercantile Exchange (NYMEX) prices. During the first quarter of 2006, market prices for natural gas were declining while the cost of gas in inventory was relatively stable, which reduced Power's margins as compared to 2005. For the quarter ended March 31, 2006, Power had Net Income of $112 million. Power has increased its previous guidance for Income from Continuing Operations of $475 million to $525 million to a revised guidance range of $500 million to $550 million for 2006, reflecting current results and anticipated continued improvements in the operating performance of its nuclear and fossil stations, strong energy markets and increased contracting opportunities. These increases will be partially offset by increases in depreciation and interest expense associated with the new Linden plant, which commenced commercial operation on May 1, 2006 and a full year for the Bethlehem Energy Center (BEC), increased Operation and Maintenance costs and lower earnings from the Nuclear Decommissioning Trust (NDT) Funds. The guidance range does not include merger-related costs and does not contemplate any potential earnings fluctuations that could occur due to MTM accounting being applied to Power's operations pursuant to Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133). See Note 6. Risk Management of the Notes for additional information. A key factor in Power's ability to achieve its objectives is its capability 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 benefit from any future increases in market prices will depend, to a large extent, on efficient power plant operations, especially for its low-cost nuclear and coal-fired facilities. 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. In addition, forward prices are constantly changing and therefore there is no assurance that Power will be able to contract its output at attractive prices. 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 merchant generation companies, and Resources, which primarily invests in energy-related leveraged leases. For the quarter ended March 31, 2006, Energy Holdings had Income from Continuing Operations of $28 million. For the full year 2006, Energy Holdings has increased its previous guidance range for Income from Continuing Operations of $155 million to $175 million to a revised guidance range of $165 million to $185 million. The change from the original guidance is primarily due to improvements at the facilities operated by Texas Independent Energy, L.P. (TIE). The expected 2006 range is less than the 2005 Income from Continuing Operations of $199 million primarily due to a $43 million after-tax gain recognized in 2005 from Resources' sale of its interest in Seminole Generation Station Unit 2 (Seminole). The earnings range for 2006 excludes the expected gain on the sale of Global's two generating facilities in Poland, Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina), and any gain or loss on other potential asset sales as well as any potential finance costs associated with use of the proceeds. The guidance range also does not contemplate the potential earnings fluctuations that could occur due to MTM accounting being applied to Global's 56
operations at TIE in Texas as the energy and gas contracts, which are backed by the physical capacity of the plants and sold in the normal course of business, must be marked to market pursuant to SFAS 133. See Note 6. Risk Management of the Notes for additional information related to this contract. Included in the results for the quarter as compared to the same period in 2005 is an increase in the overall tax rate resulting from a change in the mix of domestic and foreign earnings. With a larger portion of the earnings coming from domestic sources, the full U.S. tax rate is applied to the earnings as compared to foreign earnings being taxed at a foreign tax rate for each country, which is generally lower. Energy Holdings expects its overall tax rate to increase as it continues to selectively monetize investments that no longer have a strategic fit. Global Although Global continues to produce significant earnings and operating cash flow, the returns on several of the investments in its international portfolio have not been commensurate with the level of risk associated with international investments in developing energy markets. As a result, since 2003, Energy Holdings has refocused its strategy from one of growth to one that places emphasis on increasing the efficiency and returns of its existing assets. Accordingly, Global continues to limit its capital spending, while focusing on operations and improved performance of existing businesses and is seeking to opportunistically monetize investments that may no longer have a strategic fit. On January 31, 2006, Global entered into an agreement with CEZ a.s., the former Czech national utility company and the largest electric power company in central and eastern Europe, to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale is expected to close in the second quarter of 2006. Net proceeds from the sale are subject to various purchase price adjustments, foreign currency fluctuations and contingencies and are currently expected to be in excess of $300 million after taxes and transaction costs, which is in excess of the book value of the facilities as of December 31, 2005. Global's success will depend, in part, upon its ability to mitigate risks of its international strategy. The economic and political conditions in certain countries where Global has investments present risks that may be different or more significant than those found in the U.S. including: renegotiation or nullification of existing contracts, changes in law or tax policy, interruption of business, nationalization, expropriation, war and other factors. Operations in foreign countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. In some countries in which Global has interests, economic and monetary conditions and other factors could affect its ability to convert its cash distributions to U.S. Dollars or other freely convertible currencies. Furthermore, the central bank of any such country may have the authority to suspend, restrict or otherwise impose conditions on foreign exchange transactions or to limit distributions to foreign investors. The capital requirements of Global's consolidated subsidiaries are primarily financed from internally generated cash flow within the projects and from locally sourced debt on a basis that is non-recourse to Global or limited discretionary investments by Energy Holdings. 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' ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources' earnings and cash flows are expected to decrease in the future as the investment portfolio matures. Resources faces risks with regard to the creditworthiness of its counterparties, specifically certain lessees that collectively comprise a substantial portion of Resources' investment portfolio. Resources also faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. The manifestation of either of these risks could cause a materially adverse effect on Resources' strategy and its forecasted results of operations, financial position and net cash flows. In December 2005, Resources sold its interest in the Seminole leveraged lease to Seminole Electric Cooperative Inc. for $287 million. The sale resulted in a $43 million after-tax gain. Net proceeds of $235 57
million together with other funds were used on January 30, 2006 to redeem Energy Holdings' $309 million 7.75% Senior Notes due in 2007. The results for PSEG, PSE&G, Power and Energy Holdings for the quarters ended March 31, 2006 and 2005 are presented below: PSE&G Power Energy Holdings: Global Resources Other (A) Total Energy Holdings Other (B) PSEG Income from Continuing Operations Income from Discontinued Operations (C) PSEG Net Income The $81 million or $0.37 per share decrease in Income from Continuing Operations was primarily due to decreases at PSE&G and Energy Holdings. The decrease at PSE&G was due to a reduction in gas sales volumes due to milder weather in 2006 and reduced demand due to higher pricing. Also contributing to the decrease at PSE&G was the full amortization of the excess depreciation reserve as of December 31, 2005. The decrease at Energy Holdings was primarily due to the absence of income from withdrawal from the Eagle Point cogeneration partnership interest in January 2005, partially offset by improved operations at Energy Holdings' facilities in Texas and South America. Power's earnings were relatively flat as compared to the same period in 2005 as increased revenues from higher sales in the various power pools supported by improved nuclear operations were substantially offset by higher natural gas costs and unrealized losses on asset-backed transactions. 58 Earnings (Losses)
Quarters Ended March 31, Contribution to Earnings
Per Share
(Diluted) (D)
Quarters Ended March 31, 2006 2005 2006 2005 (Millions) $ 78 $ 118 $ 0.31 $ 0.49 112 115 0.44 0.48 9 45 0.04 0.19 20 23 0.08 0.09 (1 ) (1 ) — — 28 67 0.12 0.28 (19 ) (20 ) (0.08 ) (0.09 ) 199 280 0.79 1.16 4 5 0.02 0.02 $ 203 $ 285 $ 0.81 $ 1.18 (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/preference unit distributions for PSE&G in 2006 and 2005 and Energy Holdings in 2005, interest on certain financing transactions, Merger expenses and certain other administrative and general expenses at PSEG (as parent company). (C) Includes Discontinued Operations of Waterford, an electric generation facility in Waterford, Ohio that was sold in September 2005, in 2005 and Skawina and Elcho in 2006 and 2005. See Note 3. Discontinued Operations and Dispositions of the Notes. (D) Earnings Per Share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in PSEG's assets and liabilities as a whole.
PSEG Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense Income from Discontinued Operations 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 Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Expense Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM spot market; delivery revenues from the transmission and distribution of energy through its system; and other operating revenues from the provision of various services. The $166 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005 was due to increases of $178 million in commodity revenues, described below, and $2 million in other operating revenues, primarily related to appliance service contracts, partially offset by a $14 million decrease in delivery revenues. Commodity PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between gas costs and the amount provided by customers in revenues is deferred and collected from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for C&I customers and annually through the BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G 59 For the
Quarters Ended
March 31, 2006 2005 Increase
(Decrease) % (Millions) $ 3,521 $ 3,244 $ 277 9 $ 2,204 $ 1,849 $ 355 19 $ 584 $ 576 $ 8 1 $ 204 $ 184 $ 20 11 $ 33 $ 31 $ 2 6 $ 49 $ 43 $ 6 14 $ (26 ) $ (14 ) $ 12 86 $ (201 ) $ (200 ) $ 1 1 $ (143 ) $ (171 ) $ (28 ) (16 ) $ 4 $ 5 $ (1 ) (20 ) For the
Quarters Ended
March 31, 2006 2005 Increase
(Decrease) % (Millions) $ 2,350 $ 2,184 $ 166 8 $ 1,631 $ 1,424 $ 207 15 $ 301 $ 295 $ 6 2 $ 152 $ 135 $ 17 13 $ 4 $ 2 $ 2 100 $ (1 ) $ (1 ) $ — — $ (85 ) $ (84 ) $ 1 1 $ (65 ) $ (86 ) $ (21 ) (24 )
has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual BGSS proceedings. Electric commodity prices are set at the annual BGS auctions. The $178 million increase in commodity revenues for the quarter ended March 31, 2006, as compared to the same period in 2005, was due to increases of $127 million in gas commodity revenues, primarily due to $287 million in higher BGSS prices offset by $114 million in lower volumes due to weather and a decrease of $46 million due to the expiration of the Third Party Shopping Incentive in July 2005. There is a corresponding $46 million increase in delivery revenues. Also contributing to the increase was $51 million in electric commodity revenues, primarily due to $43 million in higher BGS and Non-Utility Generation (NUG) prices and $8 million in higher NUG volumes due to operations. Delivery The $14 million decrease in delivery revenues for the quarter ended March 31, 2006, as compared to the same period in 2005, was due to an $11 million decrease in electric revenues and a $3 million decrease in gas revenues. The $11 million decrease in electric delivery revenues was due primarily to $7 million in lower volumes due to weather and decreased prices of $4 million due to lower demand revenues. The $3 million decrease in gas delivery revenues was primarily due to $47 million in lower volumes due to weather and $6 million due to the impacts of price elasticity related to residential customers. These decreases were offset by $50 million in increased prices, $46 million of which was due primarily to the expiration of the Third Party Shopping Incentive in July 2005 and the Gas Cost Underrecovery Adjustment (GCUA) in January 2005. Operating Expenses Energy Costs The $207 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was comprised of increases of $168 million in gas costs and $38 million in electric costs. The increase in gas costs was caused by a $291 million or 34% increase in gas prices offset by a $9 million decrease due to the expiration of the GCUA clause in January 2005, described above, and a $114 million decrease in sales volumes due primarily to weather. The electric increase is due to $25 million in higher prices for BGS and NUG purchases and $13 million in higher NUG volumes. Operation and Maintenance The $6 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was due primarily to $6 million in increased labor and fringe benefits. Depreciation and Amortization The $17 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was due primarily to the absence of amortization of an excess electric distribution depreciation reserve regulatory liability which ended December 31, 2005. Income Taxes The $21 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to lower pre-tax income. 60
Power Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income Other Deductions Interest Expense Income Tax Expense Loss from Discontinued Operations Operating Revenues The $237 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was due to increases of $151 million in generation revenues, $84 million in gas supply revenues and $2 million in trading revenues. Generation Generation revenues increased $151 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to higher revenues of approximately $143 million from higher prices and increased sales volumes in the various power pools supported by improved nuclear operations, largely due to Hope Creek's higher capacity factor, and the commencement of the commercial operations of BEC in July 2005. This increase was partially offset by reduced load being served under the BGS contracts. Also, contributing to the increase was approximately $23 million from Reliability Must-Run (RMR) revenues. Gas Supply Gas supply revenues increased $84 million for the quarter ended March 31, 2006, as compared to the same period in 2005, principally due to higher prices under the BGSS contract for gas and pipeline capacity partially offset by lower demand, largely resulting from customer conservation and a warmer winter heating season in 2006. 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 purchases to meet Power's obligation under its BGSS contract with PSE&G. Energy Costs increased approximately $217 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to an increase of $130 million from higher prices on a reduced volume of gas purchased to satisfy Power's BGSS obligations and increased generation costs of $87 million, reflecting higher prices and volumes of fossil fuel and unrealized losses on asset-backed transactions. Operation and Maintenance Operation and Maintenance expense increased $8 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to higher maintenance expense of $20 million related to outages in 2006 at certain of the fossil plants that satisfy peaking requirements partially offset 61 For the
Quarters Ended
March 31, 2006 2005 Increase
(Decrease) % (Millions) $ 1,967 $ 1,730 $ 237 14 $ 1,487 $ 1,270 $ 217 17 $ 235 $ 227 $ 8 4 $ 35 $ 30 $ 5 17 $ 41 $ 31 $ 10 32 $ (19 ) $ (8 ) $ 11 N/A $ (40 ) $ (28 ) $ 12 43 $ (80 ) $ (83 ) $ (3 ) (4 ) $ — $ (7 ) $ (7 ) (100 )
by a $12 million decrease in labor costs due to a reduction in personnel at the nuclear generating facilities and other Power locations. Depreciation and Amortization The $5 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to the BEC facility being placed into service in July 2005 and a higher depreciable asset base in 2006 at Nuclear. Other Income Other Income increased $10 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to increased realized gains and income related to the NDT Funds and higher interest on margin call deposits. Other Deductions Other Deductions increased $11 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to increased realized losses and miscellaneous expenses related to the NDT Funds. Interest Expense Interest Expense increased $12 million for the quarter ended March 31, 2006, as compared to the same period in 2005, due primarily to lower capitalized interest costs in 2006 related to commencement of operations of the BEC facility in July 2005. Income Taxes Income Taxes decreased $3 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to lower pre-tax income. Loss from Discontinued Operations, net of tax The Loss from Discontinued Operations of $7 million for the quarter ended March 31, 2005 represents the operating results of Waterford. Energy Holdings Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Income from Equity Method Investments Other Income Other Deductions Interest Expense Income Tax Expense Income from Discontinued Operations Operating Revenues The $1 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was due to lower revenues at Resources of $14 million primarily due to a reduction in income due 62 For the
Quarters Ended
March 31, 2006 2005 Increase
(Decrease) % (Millions) $ 312 $ 313 $ (1 ) — $ 194 $ 138 $ 56 41 $ 49 $ 57 $ (8 ) (14 ) $ 12 $ 14 $ (2 ) (14 ) $ 33 $ 31 $ 2 6 $ 5 $ 9 $ (4 ) (44 ) $ (5 ) $ (5 ) $ — — $ (50 ) $ (58 ) $ (8 ) (14 ) $ (12 ) $ (14 ) $ (2 ) (14 ) $ 4 $ 12 $ (8 ) (67 )
to the December 2005 sale of Resources' interest in Seminole and the absence of a $6 million pre-tax gain on the sale of Resources' limited partnership interest in three Solar Electric Generating Systems projects recognized in 2005. Offsetting the decrease was higher revenues at Global of $13 million, which was the net result of increased revenues consisting of a $46 million increase at TIE due to an increase in the average price of megawatt hours, a $15 million increase at Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to increased tariffs and gigawatt hours and a $2 million increase at Electroandes due to higher energy sales, partially offset by decreased revenues due to the absence of $37 million of income received in 2005 from the withdrawal from the Eagle Point cogeneration partnership interest and a $14 million decrease related to Global's sale of a 35% interest in Dhofar Power Company S.A.O.C. (Dhofar Power) through a public offering on the Omani Stock Exchange in April 2005, reducing its ownership interest to 46% and thus accounting for the investment under the equity method of accounting following the sale. Operating Expenses Energy Costs The $56 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to a $47 million increase at TIE resulting from an increase in production gas prices, a $10 million increase related to SAESA due to increased volume and increases in energy costs due to higher spot price offset by a $3 million decrease related to the deconsolidation of Dhofar Power. Operation and Maintenance The $8 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to a $10 million decrease at TIE resulting from a scheduled hot gas path inspection outage that occurred in the first quarter of 2005, and a $2 million decrease related to the deconsolidation of Dhofar Power partially offset by other operation and maintenance items. Depreciation and Amortization The $2 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was due to a $3 million decrease related to the deconsolidation of Dhofar Power offset by a $1 million increase related to depreciation expense on completed projects at SAESA. Income from Equity Method Investments The $2 million increase for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to stronger results from Chilquinta Energia S.A. and Rio Grande Energia S.A. due to stronger foreign currency rates. Other Income The $4 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to the absence of $6 million of interest income received in 2005 from asset sales, partially offset by foreign currency transaction gains. Interest Expense The $8 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to a decrease in debt outstanding. 63
Income Taxes The $2 million decrease for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to a higher effective rate for Global due to a change in mix of domestic and international earnings. Income from Discontinued Operations, net of tax In January 2006, Energy Holdings entered into an agreement to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. Income from Discontinued Operations related to Elcho and Skawina for the quarters ended March 31, 2006 and 2005 was $4 million and $12 million, respectively, net of tax. See Note 3. Discontinued Operations and Dispositions of the Notes for additional information. Other To supplement the Condensed Consolidated Financial Statements presented in accordance with accounting principles generally accepted in the U.S. (GAAP), PSEG and Energy Holdings use the non-GAAP measure of Earnings Before Interest and Taxes (EBIT). PSEG's and Energy Holdings' Management each reviews EBIT internally to evaluate performance and manage operations and believes that the inclusion of this non-GAAP financial measure provides consistent and comparable measures to help shareholders understand current and future operating results. PSEG and Energy Holdings urge shareholders to carefully review the GAAP financial information included as part of this Quarterly Report. Global The following table summarizes Global's capital at risk as of March 31, 2006 and December 31, 2005 and net contributions to EBIT and non-recourse interest for the quarters ended March 31, 2006 and 2005 in the following regions. Region: North America South America Europe (D) India, Oman and Other Global G&A—Unallocated Total Total Global EBIT Interest Expense Income Taxes Income from Continuing Operations 64 For the Quarters Ended
March 31, Total Capital
at Risk (A)
As of EBIT (B) Non-Recourse
Interest (C) March 31,
2006 December 31,
2005 2006 2005 2006 2005 (Millions) $ 436 $ 481 $ 16 $ 47 $ 6 $ 5 1,694 1,655 36 38 8 10 187 179 2 (3 ) — — 70 67 2 9 — 3 — — (7 ) (6 ) — — $ 2,387 $ 2,382 $ 49 $ 85 $ 14 $ 18 $ 49 $ 85 (36 ) (37 ) (4 ) (3 ) $ 9 $ 45 (A) Total Capital at Risk includes Global's gross investments less non-recourse debt at the project level. (B) For investments accounted for under the equity method of accounting, includes Global's share of net earnings, including Interest Expense and Income Tax Expense. The $31 million decrease in EBIT in North America for the quarter ended March 31, 2006, as compared to the same period in 2005, was primarily due to $37 million of income from the withdrawal from the Eagle Point cogeneration partnership interest in 2005. (C) Non-recourse interest is Interest Expense on debt that is non-recourse to Global.
LIQUIDITY AND CAPITAL RESOURCES The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG's three direct operating subsidiaries, PSE&G, Power and Energy Holdings. Operating Cash Flows PSEG For the quarter ended March 31, 2006, PSEG's operating cash flow increased by approximately $258 million from $657 million to $915 million, as compared to the same period in 2005, due to net increases from its subsidiaries as discussed below. PSE&G PSE&G's operating cash flow increased approximately $46 million from $226 million to $272 million for the quarter ended March 31, 2006, as compared to the same period in 2005, primarily due to change in working capital requirements and higher recovery of regulatory assets. Power Power's operating cash flow increased approximately $318 million from $364 million to $682 million for the quarter ended March 31, 2006, as compared to the same period in 2005, due to decreased margin requirements and a decrease in fuel inventory due to decreased commodity prices and a reduction in natural gas inventory following the winter heating season. Energy Holdings Energy Holdings' operating cash flow decreased approximately $91 million from $92 million to $1 million for the quarter ended March 31, 2006, as compared to the same period in 2005, due primarily to the timing of tax benefits and payments and the absence of proceeds from the sale of investments and investment distributions. Common Stock Dividends PSEG Dividend payments on common stock for the quarters ended March 31, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $143 million and $134 million, respectively. Future dividends declared will be dependent upon PSEG's future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings As of March 31, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3 billion of available liquidity under these facilities. In 65(D) The Total Capital at Risk includes amounts relating to Elcho and Skawina as the sale has not been completed and therefore there is still Capital at Risk in Poland. EBIT and Non-Recourse Interest exclude amounts relating to Elcho and Skawina. EBIT was $15 million and $25 million for the quarters ended March 31, 2006 and 2005, respectively. Non-Recourse Interest was $9 million for the quarters ended March 31, 2006 and 2005. See Note 3. Discontinued Operations and Dispositions of the Notes.
addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below. PSEG: 4-year Credit Facility 5-year Credit Facility Bilateral Term Loan (A) Uncommitted Bilateral PSE&G: 5-year Credit Facility Uncommitted Bilateral PSEG and Power: (B) 3-year Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Power: Bilateral Credit Facility Energy Holdings: 5-year Credit Facility (C) 66Company Expiration
Date Total
Facility Primary
Purpose Usage as of
March 31,
2006 Available
Liquidity as of
March 31,
2006 (Millions) April 2008 $ 450 CP Support/
Funding/Letters
of Credit $ 47 $ 403 May 2010 $ 650 CP Support/
Funding/Letters
of Credit $ 1 $ 649 May 2006 $ 100 Funding $ 100 $ —
Agreement N/A N/A Funding $ 8 N/A June 2009 $ 600 CP Support/
Funding/Letters
of Credit $ — $ 600
Agreement N/A N/A Funding $ — N/A April 2007 $ 600 CP Support/
Funding/Letters
of Credit $ 24 (D) $ 576 October 2006 $ 100 Funding/Letters
of Credit $ — $ 100 June 2006 $ 100 Funding/Letters
of Credit $ — $ 100 June 2006 $ 150 Funding/Letters
of Credit $ 30 (D) $ 120 July 2006 $ 150 Funding/Letters
of Credit $ — $ 150 July 2006 $ 100 Funding/Letters
of Credit $ 100 (D) $ — Sept 2006 $ 100 Funding/Letters
of Credit $ 100 (D) $ — Dec 2006 $ 50 Funding/Letters
of Credit $ — $ 50 Dec 2006 $ 275 Letters of Credit $ 210 (D) $ 65 March 2010 $ 100 Funding/Letters
of Credit $ 53 (D) $ 47 June 2010 $ 150 Funding/Letters
of Credit $ 48 (D) $ 102 (A) Expected to be renewed with expiration in April 2007. (B) PSEG/Power joint and several co-borrower facility. (C) Energy Holdings/Global/Resources joint and several co-borrower facility. (D) These amounts relate to letters of credit outstanding.
PSEG and PSE&G PSEG and PSE&G believes it has sufficient liquidity to fund its short-term cash needs. Power As of March 31, 2006, Power had loaned $380 million to PSEG in the form of an intercompany loan. During the first quarter of 2006, Power's required margin postings decreased for sales contracts entered into in the normal course of business as commodity prices declined. 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. Power believes that it has sufficient liquidity to fund its short-term cash needs. 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, 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 resulting from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for further information. Energy Holdings As of March 31, 2006, Energy Holdings had loaned $58 million of excess cash to PSEG. In addition, Energy Holdings and its subsidiaries had $70 million in cash, including $3 million invested offshore as of March 31, 2006. External Financings PSEG During the quarter ended March 31, 2006, PSEG issued approximately 266,000 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program for approximately $17 million. In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity investment in the trust. PSE&G On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds. In March 2006, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $36 million of its transition bonds. 67
Power In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes. Energy Holdings In January 2006, Energy Holdings redeemed its $309 million of its 7.75% Senior Notes due in 2007. On February 17, 2006, the maturity of the Odessa–Ector Power Partners, L.P (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above LIBOR. As of September 29, 2006, Odessa's interest rate will be swapped to a fixed rate of 5.4275%. Debt Covenants PSEG, PSE&G, Power and Energy Holdings PSEG's, PSE&G's, Power's and Energy Holdings' respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower's business or financial condition. As explained in more detail below, these credit agreements may also 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 a financial performance or liquidity measure. PSEG Financial covenants contained in PSEG's credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of March 31, 2006, PSEG's ratio of debt to capitalization (as defined above) was 57.5%. 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 at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of March 31, 2006, PSE&G's ratio of long-term debt to total capitalization (as defined above) was 46.2%. 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 March 31, 2006, PSE&G's Mortgage coverage ratio was 4.66 to 1 and the Mortgage would permit up to approximately $1.7 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. PSEG and Power Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. This facility has a 70.0% debt to total capitalization covenant for PSEG (calculated as set forth above) and a 65% debt to total capitalization covenant for Power. 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 68
Condensed Consolidated Balance Sheets). This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of March 31, 2006, Power's ratio of debt to capitalization (as defined above) was 48.8%. Energy Holdings Energy Holdings entered into a $150 million five-year bank revolving credit agreement in June 2005 with 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 March 31, 2006, Energy Holdings' coverage of this covenant was 2.76. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of March 31, 2006, Energy Holdings' ratio under this covenant was 3.55. 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. Credit Ratings PSEG, PSE&G, Power and Energy Holdings The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies. Any downward revision or withdrawal 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. All ratings have a stable outlook unless otherwise noted. (N) denotes a negative outlook, (P) denotes a positive outlook and (WD) denotes a credit watch developing, indicating that ratings could be raised or lowered. 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. PSEG: Preferred Securities Commercial Paper Senior Unsecured Debt PSE&G: Mortgage Bonds Preferred Securities Commercial Paper Power: Senior Notes Energy Holdings: Senior Notes 69 Moody’s (A) S&P (B) Fitch (C) Baa3 BB+(WD) BBB–(P) P2 A3(WD) F2 Baa2 BBB–(WD) BBB(P) A3 A–(WD) A Baa3 BB+(WD) BBB+ P2 A3(WD) F2 Baa1 BBB(WD) BBB(P) Ba3(N) BB–(N) BB(N) (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 Loss (OCL) PSEG, Power and Energy Holdings For the quarter ended March 31, 2006, PSEG, Power and Energy Holdings had OCL of $136 million, $133 million and $2 million, respectively, due primarily to a reduction in the net unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133, and unrealized gains and losses in the NDT Funds at Power and foreign currency translation adjustments at Energy Holdings. During the quarter ended March 31, 2006, Power's OCL decreased from $487 million to $354 million. The primary cause was a decrease of approximately $115 million related to the change in market value of energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the quarter ended March 31, 2006, the decrease in gas and electric prices has resulted in a reduction in unrealized losses on many of those contracts, which are recorded in OCL. 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 consistent with amounts disclosed in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31, 2005. PSE&G During the quarter ended March 31, 2006, PSE&G made approximately $108 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $108 million excludes approximately $8 million spent on cost of removal. Power During the quarter ended March 31, 2006, Power made approximately $67 million of capital expenditures (excluding $51 million for nuclear fuel), primarily related to various projects at Fossil and Nuclear. Energy Holdings During the quarter ended March 31, 2006, Energy Holdings incurred approximately $14 million of capital expenditures, primarily related to SAESA. PSEG, PSE&G, Power and Energy Holdings For information related to recent accounting matters, see Note 2. Recent Accounting Standards of the Notes. 70
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES 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 to Condensed Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives to manage risk consistent with its respective business plans and prudent practices. PSEG, 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, 2005. Commodity Contracts 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. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity. Normal Operations and Hedging Activities Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors. Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in OCL, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings. Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement. Trading Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. In addition, Power has non-asset based trading activities, which have significantly decreased over the past year. These contracts also involve financial transactions including swaps, options and futures. These 71
ABOUT MARKET RISK
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. For the Quarter Ended March 31, 2006 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End Average for the Period High Low 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End Average for the Period High Low 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. Risk Management 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 ended March 31, 2006. 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. 72 Trading VaR Non-Trading
MTM VaR (Millions) $ 1 $ 35 $ 1 $ 47 $ 2 $ 59 $ — $ 35 $ 2 $ 56 $ 1 $ 73 $ 2 $ 93 $ — $ 56
Operating Revenues MTM Activities: Unrealized MTM Gains Changes in Fair Value of Open Positions Origination Unrealized Gain at Inception Changes in Valuation Techniques and Assumptions Realization at Settlement of Contracts Total Change in Unrealized Fair Value Realized Net Settlement of Transactions Subject to MTM Broker Fees and Other Related Expenses Net MTM Gains Accrual Activities Accrual Activities—Revenue, Including Hedge Reclassifications Total Operating Revenues The following table indicates Power's energy trading assets and liabilities, as well as Power's hedging activity related to asset-backed transactions and derivative instruments that qualify for hedge accounting under SFAS 133, its amendments and related guidance. 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 Assets/Liabilities MTM Energy Assets Current Assets Noncurrent Assets Total MTM Energy Assets MTM Energy Liabilities Current Liabilities Noncurrent Liabilities Total MTM Current Liabilities Total MTM Energy Contract Net Liabilities 73
For the Quarter Ended March 31, 2006 Normal
Operations and
Hedging (A) Trading Total (Millions) $ (11 ) $ 12 $ 1 — — — — — — (9 ) (17 ) (26 ) (20 ) (5 ) (25 ) 9 17 26 — — — (11 ) 12 1 1,966 — 1,966 $ 1,955 $ 12 $ 1,967 (A) Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions and hedging activities, but excludes owned and contracted generation assets.
As of March 31, 2006 Normal
Operations
and Hedging Trading Total (Millions) $ 65 $ 51 $ 116 3 7 10 $ 68 $ 58 $ 126 $ (411 ) $ (51 ) $ (462 ) (448 ) (12 ) (460 ) $ (859 ) $ (63 ) $ (922 ) $ (791 ) $ (5 ) $ (796 )
The following table presents the maturity of net fair value of MTM energy trading contracts. Maturity of Net Fair Value of MTM Energy Trading Contracts Trading Normal Operations and Hedging Total Net Unrealized Losses on MTM Contracts 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. PSEG, Power and Energy Holdings The following table identifies losses on cash flow hedges that are currently in Accumulated Other Comprehensive Loss, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights (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 Accumulated Other Comprehensive Loss and into earnings over the next twelve months. Cash Flow Hedges Included in Accumulated Other Comprehensive Loss Commodities Interest Rates Foreign Currency Net Cash Flow Hedge Loss Power Credit Risk The following table provides information on Power's credit exposure, net of collateral, as of March 31, 2006. 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. 74
As of March 31, 2006 Maturities within 2006 2007 2008-2009 Total (Millions) $ — $ (7 ) $ 2 $ (5 ) (241 ) (321 ) (229 ) (791 ) $ (241 ) $ (328 ) $ (227 ) $ (796 )
As of March 31, 2006 Accumulated
Other
Comprehensive
Loss Portion Expected
to be Reclassified
in next 12 months (Millions) $ (443 ) $ (194 ) (59 ) (18 ) — — $ (502 ) $ (212 )
Schedule of Credit Risk Exposure on Energy Contracts Net Assets Investment Grade—External Rating Non-Investment Grade—External Rating Investment Grade—No External Rating Non-Investment Grade—No External Rating Total The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure. 75
As of March 31, 2006Rating Current
Exposure Securities
Held as
Collateral Net
Exposure Number of
Counterparties
>10% Net
Exposure of
Counterparties
>10% (Millions) (Millions) $ 359 $ 54 $ 351 1 (A) $ 270 5 1 4 — — 5 4 5 — — 28 — 28 — — $ 397 $ 59 $ 388 1 $ 270 (A) Counterparty is PSE&G.
ITEM 4. CONTROLS AND PROCEDURES PSEG, PSE&G, Power and Energy Holdings Disclosure Controls and Procedures 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 which is made up of several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures as of March 31, 2006 and, based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these quarterly reports. Internal Controls During the first quarter of 2006, PSEG, PSE&G, Power and Energy Holdings each made enhancements to internal controls. These enhancements, which are expected to improve the design and operational effectiveness of control processes for financial reporting, included significant changes to internal controls including enhanced policies and procedures related to the derivative accounting process. 76
Certain information reported under Item 3 of Part I of the 2005 Annual Report on Form 10-K is updated below. 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) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16) 77 Page 25. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003 and additional investigation Notice dated September 15, 2003 by the EPA regarding the Passaic River site. Docket No. EX93060255. Page 26. (Power) PSE&G's MGP Remediation Program instituted by NJDEP's Coal Gasification Facility Sites letter dated March 25, 1988. Page 31. (Power) Filing of Complaint by Nuclear against the DOE on September 26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-0551C seeking damages caused by DOE's failure to take possession of spent nuclear fuel. The complaint was amended to include PSE&G as a prior owner in interest. Page 33. (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. Page 35. (Energy Holdings) DRF Porto Alegre RS claim for past due taxes at RGE, Case No. 2004-47. Page 36. (Energy Holdings) Dhofar Power Company SAOC v. Ministry of Housing, Electricity and Water (Sultanate of Oman), ICC Reference EXP/233. Page 78. (PSEG, PSE&G and Power) FERC proceedings with MISO and PJM relating to RTOR and SECA methodology, Docket No. ER05-6-000 et al. Page 79. (PSEG, PSE&G and Power) FERC proceeding relating to PJM's stated rate proposal, Docket No. ER05-1181-000. Page 79. (Power) PJM Interconnection L.L.C. filing with FERC on November 2, 2004, Docket No. EL03-236-003 to amend Tariff and Operating Agreement to request Reliability Must-Run (RMR) compensation. Page 79. (Power) PSEG Power Connecticut's filing with FERC on November 17, 2004, Docket No. ER05-231-000, to request RMR compensation. Page 80. (PSEG and PSE&G) BPU proceeding on August 1, 2005 relating to ratepayer protections due to repeal of PUHCA under the Energy Policy Act of 2005. Docket No. AX05070641. Page 81. (PSE&G) BPU review of annual procurement process for BGS, Docket No. EO06020119. Page 81. (PSE&G) BPU proceeding relating to Electric Base Rate Case financial review, Docket No. ER02050303. Page 81. (PSE&G) PSE&G's BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390. Page 81. (PSE&G) PSE&G Petition for increase of gas base rates filed with BPU on September 30, 2005, Docket No. GR05100845. Page 82. (PSE&G) Cost Recovery filing with the BPU on July 1, 2004, Docket No. EE04070718.
Certain information reported under the 2005 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2005 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed. Federal Regulation Federal Energy Regulatory Commission (FERC) PSEG, PSE&G, Power and Energy Holdings Market Power 2005 Form 10-K, Page 16. On February 28, 2006, PSEG Power Connecticut LLC (Power Connecticut) filed its triennial updated market power report with the FERC. The FERC has not yet acted on this filing. Further, once the PSEG and Exelon merger is consummated, all PSEG and Exelon subsidiaries holding market based rate authority will be required to provide appropriate updates of their market power analyses to the FERC. PSEG, PSE&G and Power PJM Schedule 12 Filing On January 5, 2006, in accordance with its Tariff and Operating Agreement, PJM filed (1) a report identifying the “Responsible Customers” that will be required to pay for certain transmission upgrades approved through PJM's Regional Transmission Expansion Planning (RTEP) process and the percentage of the project cost that will be allocated to such Responsible Customers; and (2) revised tariff sheets to identify such allocations. On March 1, 2006, PJM submitted an amendment to the January 5, 2006 filing by (1) adding certain additional transmission upgrades that have been vetted through the PJM RTEP process and approved by the PJM Board of Managers in November 2004, and (2) updating the cost allocations by adding a new Responsible Customer. PJM has requested an effective date of May 30, 2006 for these Schedule 12 tariff sheets. On March 31, 2006, PSE&G and Power, filed comments to the PJM Schedule 12 filing, indicating general support for the filing but expressing concern with regard to certain aspects of the cost allocation methodology used by PJM, which may result in a disproportionate allocation of costs to load in the eastern portion of PJM. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. Regional through and out rates (RTOR) 2005 Form 10-K, Page 17. A trial-type hearing, encompassing a review of the actual amount of lost revenues to be recovered via the Seams Elimination Charge/Cost Adjustment/Assignment (SECA) mechanism, is now scheduled to commence on May 2, 2006, with an initial decision by August 11, 2006. In addition, in March 2006, PSE&G and Power entered into a settlement with a limited group of parties in PJM, which settlement was certified to the FERC, under which the parties have agreed that, notwithstanding the resolution of the SECA hearing at the FERC, the parties will agree to pay and collect 80% of SECA revenues. PSE&G has deferred the collection of any SECA revenues on its books. It is expected that PSE&G's potential refund exposure as a result of the FERC SECA hearing (should the FERC determine that the amount being collected under SECA has been too high), and Power's potential gain under the same scenario would likely offset each other. Thus, at the present time, the SECA hearing is not expected to have a significant adverse impact on PSEG. Currently, discussions are underway regarding the potential elimination of RTORs between PJM and the New York Independent System Operators. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. 78
PJM Reliability Pricing Model (RPM) 2005 Form 10-K, Page 17. On April 20, 2006, the FERC issued an order acknowledging the existence of issues in the current (non-locational) capacity market design in PJM, and setting PJM's RPM filing for both a technical conference and a hearing. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. PJM Stated Rate Filing 2005 Form 10-K, Page 18. On July 1, 2005, PJM filed with FERC a proposal to change the rate design for its administrative cost recovery from a formula rate, which allocates PJM's administrative costs to its members on a yearly basis, to a stated rate of 39 cents per MW-hour. On August 31, 2005, FERC accepted these changes subject to the provision of further cost-of-service data by PJM within 60 days to demonstrate that its stated rate is a just and reasonable prediction of its costs for future years. PJM provided this cost-of-service data on November 30, 2005. Several parties, including PSE&G, Power, the New Jersey Board of Public Utilities (BPU) and the New Jersey Ratepayer Advocate (RPA), submitted comments and protests regarding PJM's filing, which protested the filing and requested that FERC order an evidentiary hearing regarding the filing. Settlement discussions were conducted over the course of several months, and a settlement in principle amongst all parties in the proceeding has been reached. This settlement establishes a base stated rate that is significantly lower than PJM's filed rate, establishes a rate for PJM's proposed second control center, and establishes a revised protocol to govern future interaction between the PJM Finance Committee, PJM management, PJM's Board of Managers, and the PJM membership, revisions which will result in the Finance Committee having greater access to PJM financial information and greater input into PJM's financial decision making processes. The settlement was filed with the FERC for its approval on April 18, 2006. Power Reliability Must Run (RMR) Status PJM 2005 Form 10-K, Page 18. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, net of operating margins for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19 million and $14.5 million for the Sewaren and Hudson units, respectively, plus reimbursements of Power's expenditures in connection with certain construction at the units that are necessary to maintain reliability, offset by certain revenues earned in PJM's energy market. FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC seeking to recover $11 million paid to PJM. The FERC has not yet acted on the refund report filing. New England 2005 Form 10-K, Page 19. On November 17, 2004, Power Connecticut, a wholly owned indirect subsidiary of Power, filed a request for RMR treatment for the New Haven Harbor generation station and Unit 2 at the Bridgeport Harbor generation station. Beginning on January 14, 2005, when FERC issued an order accepting this filing, subject to refund and hearing, Power Connecticut began collecting monthly fixed payments of approximately $1.6 million and $3.9 million for reliability services provided by the Bridgeport Harbor Station, Unit 2 and the New Haven Harbor Station, respectively, net of operating margins at the units. On June 17, 2005, Power Connecticut filed revised studies supporting monthly recovery of $1.3 million and $3.3 million for the Bridgeport Harbor and New Haven Harbor units, respectively. On June 20, 2005, FERC issued an order on rehearing of its January 14, 2005 order and reversed its prior conclusion that Power Connecticut's November 17, 2004 filing would become effective only after a 60-day notice period. Instead, the rehearing order allowed the filing to become effective as of November 18, 2004, which permits Power Connecticut two additional months of RMR compensation. 79
On November 28, 2005, FERC denied rehearing of its June 20, 2005 order. Certain parties opposing the RMR filing, on January 27, 2006, sought judicial review of the FERC's orders in this proceeding. FERC assigned this matter to an Administrative Law Judge (ALJ) for hearings that were scheduled to commence on April 19, 2006. Power Connecticut and the affected intervenors have, nonetheless, continued to engage in settlement discussions. On April 21, 2006, Power Connecticut, the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel and the ISO New England Inc. filed with the FERC a Joint Stipulation and Settlement Agreement and Motion for Expedited Consideration. The Joint Stipulation and Settlement, if approved by the FERC, resolves all issues set for hearing by the FERC in this proceeding, as well as issues for which rehearing had been sought and for which petitions for review have been filed with appellate courts. The Joint Stipulation and Settlement Agreement, among other things, provides for an Annual Fixed Revenue Requirement of approximately $37 million for New Haven Harbor and $14 million for Bridgeport Harbor. These rates, subject to certain limited exceptions specified in the Joint Stipulation and Settlement Agreement, will be fixed for the term of the RMR Cost of Service Agreements, which may be extended through June 2011 if the FERC approves the offer of settlement filed with it on March 6, 2006. If the settlement is not approved by the FERC, these rates will remain in effect until the FERC implements a Locational Installed Capacity Market or an alternative, unless the RMR Cost of Service Agreements are earlier terminated in accordance with their terms and conditions. Initial comments concerning the Joint Stipulation and Settlement Agreement are to be filed with the FERC by May 11, 2006, with reply comments being due by May 22, 2006. While Power Connecticut believes that the Joint Stipulation and Settlement Agreement, which is either supported or unopposed by most of the active parties to this proceeding, is likely to be approved by the FERC, it cannot predict a final outcome at this time. NRC Recirculation Pump 2005 Form 10-K, Page 21. In a letter to the NRC dated January 9, 2005, Power committed to install vibration-monitoring equipment on Hope Creek's ‘B' Reactor Recirculation Pump prior to the unit's return to service to address pump vibration concerns and replace the pump's shaft during the next refueling outage or any sooner outage of sufficient duration. This commitment was the subject of a January 11, 2005 Confirmatory Action Letter from the NRC. The shaft was replaced during the Hope Creek outage in April 2006. On April 20, 2006, the NRC issued a Closure of Confirmatory Action Letter indicating that all of the commitments were completed. State Regulation PSEG, PSE&G, Power and Energy Holdings Public Utility Holding Company Act of 1935 (PUHCA) Repeal 2005 Form 10-K, Page 21. On March 31, 2006, the BPU issued draft proposed rules in this proceeding. Specifically, these proposed rules would preserve and further codify the BPU's access to both utility and utility holding company system books and records, establish ring-fencing measures around the utility, seek to separate the corporate boards of directors between the utility and its holding company system, and address issues regarding the extent of the BPU's oversight of service agreements between a utility and its holding company system. Comments to the BPU on these draft proposed rules are due on May 22, 2006. PSE&G anticipates filing extensive comments on these proposed rules. PSEG, PSE&G, Power and Energy Holdings are not able to predict the outcome of these proceedings at this time. 80
PSE&G BGS Auction Review The BPU has initiated a proceeding to review the annual procurement process for BGS for all of the New Jersey Electric Distribution Companies. The BPU will review the procurement process as well as the policy issues directly related thereto. The BPU will consider written submissions as well as testimony supplied in the legislative-type hearing held on this issue on April 28, 2006. A BPU decision is expected by June 7, 2006. PSE&G cannot predict the outcome of this proceeding. Electric Distribution Financial Review 2005 Form 10-K, Page 22. Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and amortized this liability from August 1, 2003 through December 31, 2005. The $64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization expense. PSE&G filed for the elimination of the $64 million (based on 2003 test year sales volumes) electric distribution rate credit effective January 1, 2006, subject to BPU approval, including a review of PSE&G's earnings and other relevant financial information. Based on current sales volumes, the amount approximates $68 million. The BPU issued an order on February 7, 2006 that found that insufficient information had been provided to support the elimination of the rate credit. The order permits PSE&G to file, no later than June 15, 2006, actual data through March 31, 2006. The BPU will determine, based on the additional information, if the elimination of the rate credit is warranted. The impact of not eliminating the depreciation rate credit reduces PSE&G's earnings and cash flows by more than $5 million (pre-tax) per month. PSE&G expects to file the data with the BPU in mid-May 2006. Action on PSE&G's recent filings, including the excess depreciation rate credit, has been subject to ongoing delays. It appears that until the merger is resolved with the BPU, decisions on PSE&G's revenue requests may be difficult to achieve. Basic Gas Supply Service (BGSS) Filings 2005 Form 10-K, Page 22. On March 8, 2006 a meeting of the PSE&G, BPU Staff and the RPA was held regarding the BGSS rates for the 2005/2006 period. PSE&G addressed the RPA's discovery concerns, however the RPA requested that the BGSS not be finalized until the merger case was resolved. Pursuant to the existing schedule at the OAL, the RPA's testimony was to be filed on March 15, 2006. The RPA failed to file and subsequently argued that the BGSS be held in abeyance until the merger case is resolved. The ALJ directed the RPA to file a motion, which was subsequently filed. The motion requested that the BGSS proceeding be stayed, or that it be consolidated with the gas base rate case. PSE&G filed its reply on April 5, 2006 arguing that the issues of the two proceedings are unrelated and that the RPA's motion had no merit. Gas Base Rate Case 2005 Form 10-K, Page 23. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78% increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates. The balance of the request will cover the return on increased plant investment, higher operating expenses and provide an 11% return on equity. PSE&G's current gas base rates have been in effect since January 2002. PSE&G presented a detailed overview of the filing to the BPU and the RPA in October 2005 and subsequent to the presentation signed an agreement with the BPU Staff providing for transfer of the matter to OAL and agreeing to have the matter settled or ready for a BPU decision before September 28, 2006. 81
On February 28, 2006, PSE&G filed its revised testimony and exhibits for 12 months of actual test year data. The schedule now calls for a BPU decision by December 2006. Action on PSE&G's recent filings, including the gas base rate case, has been subject to ongoing delays. It appears that until the merger is resolved with the BPU, decisions on PSE&G's revenue requests may be difficult to achieve. CAS Cost Recovery Mechanism 2005 Form 10-K, Page 23. The New Jersey Electric Discount and Energy Competition Act (EDECA) required that the BPU provide electric and natural gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). In July 2004, PSE&G filed a petition with the BPU to implement the CAS Cost Recovery Mechanism for both its electric and gas operations to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G's dual billing for its delivery costs and for the third-party suppliers' commodity charges as a result of customer migration from PSE&G. In September 2004, the case was transferred to the OAL as a contested case. A pre-hearing conference was held on December 20, 2005 at which time a schedule was established. On April 7, 2006, a settlement agreement was reached and filed with the ALJ. Upon final agreement with the ALJ, the case will be presented to the BPU for final determination. Under the agreement, PSE&G will recover approximately $3.4 million in previously deferred costs. Carbon Dioxide (CO2) Emissions 2005 Form 10-K, Page 27. Several states, primarily in the Northeastern U.S., are developing state-specific or regional legislative initiatives to stimulate CO2 emission reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO2 emissions from the electric power sector in the RGGI region. A draft model rule was issued on March 23, 2006 but stakeholder comments are being received and the model rule has not been finalized. States are expected to enact legislation and/or regulation representing, at least, the minimum requirements stipulated in the MOU. The NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO2 as an air contaminant subject to regulation. The RGGI program is scheduled to start in 2009. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO2 emission reduction requirements in the Northeast could materially impact Power's operation of its fossil fuel-fired electric generating units. Remedial Investigation/Feasibility Study On March 9, 2006, the EPA sent PSE&G, Power and approximately 157 other entities a notice that the EPA considered each of the entities to be a PRP with respect to contamination in Berry's Creek in Bergen County, New Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry's Creek and the connected tributaries and wetlands. Berry's Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18 million. PSE&G and Power are unable to predict the outcome of this matter, however, the related costs are not expected to be material. 82
A listing of exhibits being filed with this document is as follows: a. PSEG: Exhibit 10: Retention Program for Key Employees, as amended April 18, 2006
| Exhibit 12: Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31: Certification by E. James Ferland 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 E. James Ferland 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 10: Retention Program for Key Employees, as amended April 18, 2006 |
| 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 E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 |
| Exhibit 31.3: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 |
| Exhibit 32.2: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| Exhibit 32.3: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
c. Power:
| Exhibit 10: Retention Program for Key Employees, as amended April 18, 2006 |
| Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31.4: Certification by E. James Ferland 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 E. James Ferland 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: Retention Program for Key Employees, as amended April 18, 2006 |
| Exhibit 12.4: Computation of Ratios of Earnings to Fixed Charges |
| Exhibit 31.6: Certification by E. James Ferland 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 E. James Ferland 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 |
83
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. Date: May 1, 2006 84PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Registrant) By: /s/ PATRICIA A. RADO
Patricia A. Rado
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. Date: May 1, 2006 85PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Registrant) By: /s/ PATRICIA A. RADO
Patricia A. Rado
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. Date: May 1, 2006 86PSEG POWER LLC
(Registrant) By: /s/ PATRICIA A. RADO
Patricia A. Rado
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. Date: May 1, 2006 87PSEG ENERGY HOLDINGS L.L.C.
(Registrant) By: /s/ PATRICIA A. RADO
Patricia A. Rado
Controller
(Principal Accounting Officer)