Yes Public Service Electric and Gas Company Notes to Condensed Consolidated Financial Statements Item 2. Item 3. PART II. OTHER INFORMATION Item 1. Item 1A. Item 2. Item 5. adverse changes in the demand for or the price of the capacity and energy that we sell into wholesale electricity markets, adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission in the future, and reliability standards, any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, changes in federal and state environmental regulations that could increase our costs or limit our operations, changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations of our nuclear generating units, actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site, any inability to balance our energy obligations, available supply and trading risks, any deterioration in our credit quality or the credit quality of our counterparties, including in our leveraged leases, availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs, changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units, delays in receipt of necessary permits and approvals for our construction and development activities, delays or unforeseen cost escalations in our construction and development activities, any inability to achieve, or continue to sustain, our expected levels of operating performance, increase in competition in energy supply markets as well as competition for certain rate-based transmission projects, any inability to realize anticipated tax benefits or retain tax credits, challenges associated with recruitment and/or retention of a qualified workforce, adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in changes in technology and customer usage patterns. 2012 2011 2012 2011 OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses OPERATING INCOME Income from Equity Method Investments Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax (Expense) Benefit INCOME FROM CONTINUING OPERATIONS Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0 and $(36) for the three and six months ended 2011 NET INCOME WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): 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 2012 2011 2012 2011 NET INCOME Other Comprehensive Income (Loss), net of tax Available-for-Sale Securities, net of tax of $(17), $(9), $21 and $(17) for the three and six months ended 2012 and 2011, respectively Change in Fair Value of Derivative Instruments, net of tax of $(3), $(7),$11 and $(1) for the three and six months ended 2012 and 2011, respectively Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(2), $(9), $(17) and $(37) for the three and six months ended 2012 and 2011, respectively Pension/OPEB adjustment, net of tax of $6, $26, $11 and $30 for thethree and six months ended 2012 and 2011, respectively Other Comprehensive Income (Loss), net of tax COMPREHENSIVE INCOME 2012 2011 ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $56 in 2012 and 2011 Tax Receivable Unbilled Revenues Fuel Materials and Supplies, net Prepayments Derivative Contracts Deferred Income Taxes Regulatory Assets Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Regulatory Assets of Variable Interest Entities (VIEs) Long-Term Investments Nuclear Decommissioning Trust (NDT) Fund Other Special Funds Goodwill Other Intangibles Derivative Contracts Restricted Cash of VIEs Other Total Noncurrent Assets TOTAL ASSETS June 30, December 31, LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year (includes $50 at fair value in 2011) Securitization Debt of VIEs Due Within One Year Commercial Paper and Loans Accounts Payable Derivative Contracts Accrued Interest Accrued Taxes Deferred Income Taxes Clean Energy Program Obligation to Return Cash Collateral Regulatory Liabilities Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Regulatory Liabilities Regulatory Liabilities of VIEs Asset Retirement Obligations Other Postretirement Benefit (OPEB) Costs Accrued Pension Costs Clean Energy Program Environmental Costs Derivative Contracts Long-Term Accrued Taxes Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt of VIEs Project Level, Non-Recourse Debt Total Long-Term Debt STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued, 2012 and 2011—533,556,660 shares Treasury Stock, at cost, 2012—27,646,288 shares; 2011—27,611,374 shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholders’ Equity Noncontrolling Interest Total Stockholders’ Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposal of Discontinued Operations 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 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs Over (Under) Recovery of Societal Benefits Charge (SBC) Market Transition Charge Refund Cost of Removal Net Realized (Gains) Losses and (Income) Expense from NDT Fund Net Change in Tax Receivable Net Change in Certain Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Other Net Cash Provided By (Used In) Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Sale of Discontinued Operations Proceeds from Sales of Available-for-Sale Securities Investments in Available-for-Sale Securities Other Net Cash Provided By (Used In) Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans Issuance of Long-Term Debt Redemption of Long-Term Debt Repayment of Non-Recourse Debt Redemption of Securitization Debt Cash Dividends Paid on Common Stock Other Net Cash Provided By (Used In) Financing Activities Net Increase (Decrease) 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 (Received) Interest Paid, Net of Amounts Capitalized Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures 2012 2011 2012 2011 OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses OPERATING INCOME Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax (Expense) Benefit INCOME FROM CONTINUING OPERATIONS Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $0 and $(36) for the three and six months ended 2011 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 2012 2011 2012 2011 NET INCOME Other Comprehensive Income (Loss), net of tax Available-for-Sale Securities, net of tax of $(17), $(10), $22 and $(19) for the three and six months ended 2012 and 2011, respectively Change in Fair Value of Derivative Instruments, net of tax of $(3), $(7), $11 and $(1) for the three and six months ended 2012 and 2011, respectively Reclassification Adjustments for Net Amounts included in Net Income, net of tax of $(2), $(9), $(17) and $(37) for the three and six months ended 2012 and 2011, respectively Pension/OPEB adjustment, net of tax of $5, $24, $10 and $28 for the three and six months ended 2012 and 2011, respectively Other Comprehensive Income (Loss), net of tax COMPREHENSIVE INCOME 2012 2011 CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable Accounts Receivable—Affiliated Companies, net Short-Term Loan to Affiliate Fuel Materials and Supplies, net Derivative Contracts Prepayments Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Fund Goodwill Other Intangibles Other Special Funds Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS 2012 2011 CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable Derivative Contracts Deferred Income Taxes Accrued Interest Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Asset Retirement Obligations Other Postretirement Benefit (OPEB) Costs Derivative Contracts Accrued Pension Costs Long-Term Accrued Taxes Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) 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 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposal of Discontinued Operations Depreciation and Amortization Amortization of Nuclear Fuel Provision for Deferred Income Taxes and ITC Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives Non-Cash Employee Benefit Plan Costs Net Realized (Gains) Losses and (Income) Expense from NDT Fund Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies Margin Deposit Accounts Receivable 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 (Used In) Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Sale of Discontinued Operations Proceeds from Sales of Available-for-Sale Securities Investments in Available-for-Sale Securities Short-Term Loan—Affiliated Company, net Other Net Cash Provided By (Used In) Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Cash Dividend Paid Redemption of Long-Term Debt Other Net Cash Provided By (Used In) Financing Activities Net Increase (Decrease) 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 (Received) Interest Paid, Net of Amounts Capitalized Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures 2012 2011 2012 2011 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 Other-Than-Temporary Impairments Interest Expense INCOME BEFORE INCOME TAXES Income Tax (Expense) Benefit EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 2012 2011 2012 2011 NET INCOME Available-for-Sale Securities, net of tax of $0, $0, $(1) and $1 for the three and six months ended 2012 and 2011, respectively COMPREHENSIVE INCOME 2012 2011 ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $56 in 2012 and 2011 Tax Receivable Unbilled Revenues Materials and Supplies Prepayments Regulatory Assets Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Regulatory Assets of VIEs Long-Term Investments Other Special Funds Derivative Contracts Restricted Cash of VIEs Other Total Noncurrent Assets TOTAL ASSETS 2012 2011 CURRENT LIABILITIES Long-Term Debt Due Within One Year Securitization Debt of VIEs Due Within One Year Commercial Paper and Loans Accounts Payable Accounts Payable—Affiliated Companies, net Accrued Interest Clean Energy Program Derivative Contracts Deferred Income Taxes Obligation to Return Cash Collateral Regulatory Liabilities Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and ITC Other Postretirement Benefit (OPEB) Costs Accrued Pension Costs Regulatory Liabilities Regulatory Liabilities of VIEs Clean Energy Program Environmental Costs Asset Retirement Obligations Derivative Contracts Long-Term Accrued Taxes Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt of VIEs Total Long-Term Debt STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized; issued and outstanding, 2012 and 2011—132,450,344 shares Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Income Total Stockholder’s Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Provision for Deferred Income Taxes and ITC Non-Cash Employee Benefit Plan Costs Cost of Removal Market Transition Charge (MTC) Refund Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs Over (Under) Recovery of SBC Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues Materials and Supplies Prepayments Accounts Receivable/Payable-Affiliated Companies, net Other Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Other Net Cash Provided By (Used In) Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Sale of Available-for-Sale Securities Investments in Available-for-Sale Securities Solar Loan Investments Restricted Funds Net Cash Provided By (Used In) Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Issuance of Long-Term Debt Redemption of Long-Term Debt Redemption of Securitization Debt Deferred Issuance Costs Net Cash Provided By (Used In) Financing Activities Net Increase (Decrease) 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 (Received) Interest Paid, Net of Amounts Capitalized Increase (Decrease) in Accrued Property, Plant and Equipment Expenditures 2011 clarifies intent about application of existing fair value measurements and disclosures, changes some requirements for fair value measurements, and requires expanded disclosures. allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity’s financial position, and to present both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total price of $54 million. Three Months Ended 2011 Six Months Ended 2011 Operating Revenues Income Before Income Taxes Net Income Consumer Loans 2012 2011 Performing Commercial/Industrial Residential Total Consumer Loans 2012 2011 Lease Receivables (net of Non-Recourse Debt) Estimated Residual Value of Leased Assets Unearned and Deferred Income Gross Investments in Leases Deferred Tax Liabilities Net Investments in Leases Lease Receivables, Net of Counterparties’ Credit Rating (S&P) 2012 2011 AA A+ BBB - BB B - B- CCC Not Rated Total Asset Location Gross % Total Fuel Counterparties’ Counterparty Powerton Station Units 5 and 6 Joliet Station Units 7 and 8 Keystone Station Units 1 and 2 Conemaugh Station Units 1 and 2 Shawville Station Units 1, 2, 3 and 4 the first quarter of 2015. GenOn’s plan for the coal-fired units at the Shawville facility is to place them in a “long-term protective layup” by April 2015; however, GenOn has indicated that it will continue paying the required rent and maintaining the facility in accordance with the lease terms. GenOn has further stated that the lessee is evaluating its options under the lease, including termination for obsolescence or continuing to keep the facility in “long-term protective layup.” In the event that the lessee is able to terminate for obsolescence, the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy As of June 30, 2012 Cost Gross Gross Fair Government Obligations Other Debt Securities As of December 31, 2011 Cost Gross Gross Fair Government Obligations Other Debt Securities As of As of Accounts Receivable Accounts Payable Less Than 12 Greater Than 12 Less Than 12 Greater Than 12 Fair Gross Fair Gross Fair Gross Fair Gross Equity Securities (A) Debt Securities Government Obligations (B) Other Debt Securities (C) Total Debt Securities Other Securities NDT Available-for-Sale Securities 2012 2011 2012 2011 Proceeds from NDT Fund Sales Gross Realized Gains Gross Realized Losses Net Realized Gains (Losses) on NDT Fund Time Frame Fair Value Less than one year 1 - 5 years 6 - 10 years 11 - 15 years 16 - 20 years Over 20 years Total NDT Available-for-Sale Debt Securities Cost Gross Gross Fair Equity Securities Debt Securities Government Obligations Other Debt Securities Total Debt Securities Other Securities Total Rabbi Trust Available-for-Sale Securities Cost Gross Gross Fair Equity Securities Debt Securities Total Rabbi Trust Available-for-Sale Securities 2012 2011 2012 2011 Proceeds from Rabbi Trust Sales Net Realized Gains (Losses) on Rabbi Trust: Gross Realized Gains Gross Realized Losses Net Realized Gains (Losses) on Rabbi Trust Gross realized gains disclosed in the above table were recognized in Other Income in the Condensed Consolidated Statements of Operations. Net unrealized gains of Time Frame Fair Value Less than one year 1 - 5 years 6 - 10 years 11 - 15 years 16 - 20 years Over 20 years Total Rabbi Trust Available-for-Sale Debt Securities As of As of Power PSE&G Other Total Rabbi Trust Available-for-Sale Securities Pension Benefits Ended June 30, OPEB Ended Pension Benefits Ended June 30, OPEB Ended 2012 2011 2012 2011 2012 2011 2012 2011 Components of Net Periodic Benefit Cost: Service Cost Interest Cost Expected Return on Plan Assets Amortization of Net Transition Obligation Prior Service Cost (Credit) Actuarial Loss Net Periodic Benefit Cost Effect of Regulatory Asset Total Benefit Costs, Including Effect of Regulatory Asset Pension Benefits June 30, Pension Benefits June 30, 2012 2011 2012 2011 2012 2011 2012 2011 Power PSE&G Other Total Benefit Costs support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and obtain credit. fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). counterparty collateral calls related to commodity contracts, and certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. The face value of Power's outstanding guarantees, current exposure and margin positions as of 2012 2011 Face Value of Outstanding Guarantees Exposure under Current Guarantees Letters of Credit Margin Posted Letters of Credit Margin Received Cash Deposited and Received Counterparty Cash Margin Deposited Counterparty Cash Margin Received Net Broker Balance Deposited (Received) In the Event Power were to Lose its Investment Grade Rating: Additional Collateral that could be Required Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral Additional Amounts Posted Other Letters of Credit commenced. In October 2012, the Court issued a 90 day stay of discovery for the third-party defendants to explore a possible settlement of this matter with the State of New Jersey. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter. industry. The matter remains pending. Power has approved the expenditure of approximately the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards. 2009 2010 2011 2012 Load (MW) As of Fuel Type Power’s Share of Nuclear Fuel Uranium Enrichment Fabrication Natural Gas Coal/Oil court and the challenge filed by the EDCs has been remanded back to the BPU for consideration of certain procedural issues. In addition, the LCAPP Act has been challenged on constitutional grounds in federal court. On September 28, 2012, the federal court litigation will now be scheduled for hearing. paid forecasted energy sales from its generation stations and the related load obligations, the price of fuel to meet its fuel purchase requirements, and certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G. As of As of As of December 31, 2011 Fair Value of Cash Flow Hedges Impact on Accumulated Other Comprehensive Income (Loss) (after tax) 2012 2011 Consolidated Balance Sheet Location Energy- Energy- Netting Total Energy- Interest Total Current Assets Noncurrent Assets Total Mark-to-Market Derivative Assets Derivative Contracts Current Liabilities Noncurrent Liabilities Total Mark-to-Market Derivative (Liabilities) Total Net Mark-to-Market Derivative Assets (Liabilities) Consolidated Balance Sheet Location Energy- Energy- Netting Total Energy- Interest Total Derivative Contracts Current Assets Noncurrent Assets Total Mark-to-Market Derivative Assets Derivative Contracts Current Liabilities Noncurrent Liabilities Total Mark-to-Market Derivative (Liabilities) Total Net Mark-to-Market Derivative Assets (Liabilities) The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended Derivatives in Cash Flow Hedging Relationships PSEG (A) Energy-Related Contracts Energy-Related Contracts Interest Rate Swaps Total PSEG PSEG Power Energy-Related Contracts Energy-Related Contracts Total Power 2011: Derivatives in Cash Flow Hedging Relationships Energy-Related Contracts Energy-Related Contracts Interest Rate Swaps Total PSEG PSEG Power Energy-Related Contracts Energy-Related Contracts Total Power Accumulated Other Comprehensive Income Pre-Tax After-Tax Balance as of December 31, 2011 Gain Recognized in AOCI Less: Gain Reclassified into Income Balance as of March 31, 2012 Loss Recognized in AOCI Less: Gain Reclassified into Income Balance as of June 30, 2012 Derivatives Not Designated as Hedges 2012 2011 2012 2011 PSEG and Power Energy-Related Contracts Energy-Related Contracts Total PSEG and Power The following reflects the gross volume, on an absolute value basis, of derivatives as of Type Notional Total PSEG Power PSE&G As of June 30, 2012 Natural Gas Electricity Capacity FTRs Interest Rate Swaps Coal As of December 31, 2011 Natural Gas Electricity FTRs Interest Rate Swaps Coal 2011: Rating Current Securities Net Number of Net Exposure of 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 cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of Recurring Fair Value Measurements as of June 30, 2012 Description Total Cash Quoted Market Significant Significant (Level 3) Assets: Derivative Contracts: Energy-Related Contracts (A) Interest Rate Swaps (B) NDT Fund (C) Equity Securities Debt Securities—Govt Obligations Debt Securities—Other Other Securities Rabbi Trust (C) Equity Securities—Mutual Funds Debt Securities—Govt Obligations Debt Securities—Other Other Securities Liabilities: Derivative Contracts: Energy-Related Contracts (A) Power Assets: Derivative Contracts: Energy-Related Contracts (A) NDT Fund (C) Equity Securities Debt Securities—Govt Obligations Debt Securities—Other Other Securities Rabbi Trust (C) Equity Securities—Mutual Funds Debt Securities—Govt Obligations Debt Securities—Other Other Securities Derivative Contracts: Energy-Related Contracts (A) PSE&G Derivative Contracts: Energy Related Contracts (A) Rabbi Trust (C) Equity Securities—Mutual Funds Debt Securities—Govt Obligations Debt Securities—Other Other Securities Derivative Contracts: Energy Related Contracts (A) Recurring Fair Value Measurements as of December 31, 2011 Description Total Cash Quoted Market Significant Significant Unobservable Inputs (Level 3) PSEG Assets: Derivative Contracts: Energy-Related Contracts (A) Interest Rate Swaps (B) NDT Fund: (C) Equity Securities Debt Securities-Govt Obligations Debt Securities-Other Other Securities Rabbi Trust—Mutual Funds (C) Liabilities: Derivative Contracts: Energy-Related Contracts (A) Interest Rate Swaps (B) Non-Recourse Debt (D) Power Assets: Derivative Contracts: Energy-Related Contracts (A) NDT Fund: (C) Equity Securities Debt Securities-Govt Obligations Debt Securities-Other Other Securities Rabbi Trust—Mutual Funds (C) Liabilities: Derivative Contracts: Energy-Related Contracts (A) PSE&G Assets: Derivative Contracts: Energy-Related Contracts (A) Rabbi Trust—Mutual Funds (C) Liabilities: Derivative Contracts: Energy-Related Contracts (A) monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Commodity Level 3 Position Fair Value at June 30, 2012 Valuation Significant Range Assets (Liabilities) Power Electricity Other Total Power PSE&G Gas and Capacity Total PSE&G TOTAL PSEG Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power and PSE&G are sellers, an increase in either the power basis or the load variability or the longer-term basis amounts would decrease the fair value. For long-term electric capacity contracts where Power or PSE&G are buyers, an increase in the capacity price would increase the fair value. Total Gains or (Losses) Balance as of 2012 Included in Included in Purchases, Issuances Transfers Balance as of 2012 PSEG Net Derivative Assets (Liabilities) Non-Recourse Debt Power Net Derivative Assets (Liabilities) PSE&G Net Derivative Assets (Liabilities) Total Gains or (Losses) Description Balance as of Included in Included in Purchases, Issuances Transfers Balance as of PSEG Net Derivative Assets (Liabilities) Non-Recourse Debt Net Derivative Assets (Liabilities) PSE&G Net Derivative Assets (Liabilities) A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months and Included in PSEG Net Derivative Assets (Liabilities) Power Net Derivative Assets (Liabilities) PSE&G Net Derivative Assets (Liabilities) Included in PSEG Net Derivative Assets (Liabilities) NDT Funds Power Net Derivative Assets (Liabilities) NDT Funds PSE&G Net Derivative Assets (Liabilities) June 30, 2012 December 31, 2011 Carrying Fair Carrying Fair Long-Term Debt: PSEG (Parent) (A) Power -Recourse Debt (B) PSE&G (B) Transition Funding (PSE&G) (B) Transition Funding II (PSE&G) (B) Energy Holdings: Project Level, Non-Recourse Debt (C) Total Long-Term Debt Other Income Power PSE&G Other (A) Three Months Ended June 30, 2012 NDT Fund Gains, Interest, Dividend and Other Income Solar Loan Interest Other Total Other Income Three Months Ended June 30, 2011 NDT Fund Gains, Interest, Dividend and Other Income Solar Loan Interest Other Total Other Income Six Months Ended June 30, 2012 NDT Fund Gains, Interest, Dividend and Other Income Solar Loan Interest Other Total Other Income Six Months Ended June 30, 2011 NDT Fund Gains, Interest, Dividend and Other Income Solar Loan Interest Other Total Other Income Other Deductions Power PSE&G Other (A) Three Months Ended June 30, 2012 NDT Fund Realized Losses and Expenses Other Total Other Deductions Three Months Ended June 30, 2011 NDT Fund Realized Losses and Expenses Other Total Other Deductions Six Months Ended June 30, 2012 NDT Fund Realized Losses and Expenses Other Total Other Deductions Six Months Ended June 30, 2011 NDT Fund Realized Losses and Expenses Other Total Other Deductions Three Months Ended Six Months Ended 2012 2011 2012 2011 PSEG Power PSE&G NDT revenue, while the decrease in PSEG was due to the 2011 Energy Holdings' charge against earnings applicable to the Dynegy leases. audit settlements discussed below. property placed into service in 2012 Balance as of June 30, 2012 Power PSE&G Other Derivative Contracts Pension and OPEB Plans NDT Funds Other Accumulated Other Comprehensive Income (Loss) Balance as of December 31, 2010 Balance as of June 30, 2011 Power PSE&G Other Derivative Contracts Pension and OPEB Plans NDT Fund Other Accumulated Other Comprehensive Income (Loss) EPS Numerator (Millions) Continuing Operations Net Income EPS Denominator (Thousands) Weighted Average Common Shares Outstanding Effect of Stock Based Compensation Awards Total Shares EPS Continuing Operations Discontinued Operations Net Income Dividend Payments on Common Stock 2012 2011 2012 2011 Per Share in Millions Power PSE&G Energy Other (A) Consolidated Three Months Ended June 30, 2012 Total Operating Revenues Income (Loss) From Continuing Operations Net Income (Loss) Segment Earnings (Loss) Gross Additions to Long-Lived Assets Three Months Ended June 30, 2011 Total Operating Revenues Income (Loss) From Continuing Operations Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax Net Income (Loss) Segment Earnings (Loss) Gross Additions to Long-Lived Assets Six Months Ended June 30, 2012 Total Operating Revenues Income (Loss) From Continuing Operations Net Income (Loss) Segment Earnings (Loss) Gross Additions to Long-Lived Assets Six Months Ended June 30, 2011 Total Operating Revenues Income (Loss) From Continuing Operations Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax Net Income (Loss) Segment Earnings (Loss) Gross Additions to Long-Lived Assets As of June 30, 2012 Total Assets Investments in Equity Method Subsidiaries As of December 31, 2011 Total Assets Investments in Equity Method Subsidiaries Related Party Transactions Revenue from Affiliates: Billings to PSE&G through BGSS (A) Billings to PSE&G through BGS (A) Total Revenue from Affiliates Expense Billings from Affiliates: Administrative Billings from Services (B) Total Expense Billings from Affiliates Related Party Transactions As of As of Receivables from PSE&G through BGS and BGSS Contracts (A) Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A) Receivable from (Payable to) Services (B) Tax Receivable from (Payable to) PSEG (C) Receivable from (Payable to) PSEG Accounts Receivable—Affiliated Companies, net Short-Term Loan to Affiliate(Demand Note to PSEG) (D) Working Capital Advances to Services(E) Long-Term Accrued Taxes Receivable (Payable)(C) Related Party Transactions 2012 2011 2012 2011 Expense Billings from Affiliates: Billings from Power through BGSS (A) Billings from Power through BGS (A) Administrative Billings from Services (B) Total Expense Billings from Affiliates Related Party Transactions As of As of Payable to Power through BGS and BGSS Contracts (A) Payable to Power Related to Gas Supply Hedges for BGSS (A) Payable to Power for SREC Liability (F) Receivable from (Payable to) Services (B) Tax Receivable from (Payable to) PSEG (C) Receivable from PSEG Receivable from Energy Holdings Accounts Payable—Affiliated Companies, net Working Capital Advances to Services(E) Long-Term Accrued Taxes Payable(C) $300 per SREC. The BPU further directed the state’s Electric Distribution Companies (EDCs), including PSE&G, to file by July 1, 2012 a proposed rate recovery mechanism and a method for BGS suppliers to demonstrate that any incremental costs were reasonably and prudently incurred. Such a proposal was filed by the EDCs on June 26, 2012. On October 23, 2012, the EDCs filed a stipulation with the BPU seeking approval of a methodology for reviewing and approving incremental costs owed to BGS suppliers. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of September 30, 2012 and December 31, 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of September 30, 2012 and December 31, 2011. Under current accounting guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of September 30, 2012 and December 31, 2011. Power Guarantor Other Consolidating Consolidated Three Months Ended June 30, 2012 Operating Revenues Operating Expenses Operating Income (Loss) Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense Income Tax Benefit (Expense) Net Income (Loss) Comprehensive Income (Loss) Three Months Ended June 30, 2011 Operating Revenues Operating Expenses Operating Income (Loss) Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense Income Tax Benefit (Expense) Income (Loss) on Discontinued Operations, net of tax Net Income (Loss) Comprehensive Income (Loss) Power Guarantor Other Consolidating Consolidated Six Months Ended June 30, 2012 Operating Revenues Operating Expenses Operating Income (Loss) Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense Income Tax Benefit (Expense) Net Income (Loss) Comprehensive Income (Loss) Six Months Ended June 30, 2012 Net Cash Provided By (Used In) Operating Activities Net Cash Provided By (Used In) Investing Activities Net Cash Provided By (Used In) Financing Activities Six Months Ended June 30, 2011 Operating Revenues Operating Expenses Operating Income (Loss) Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Other-Than-Temporary Impairments Interest Expense Income Tax Benefit (Expense) Income (Loss) on Discontinued Operations, net of tax Net Income (Loss) Comprehensive Income (Loss) Six Months Ended June 30, 2011 Net Cash Provided By (Used In) Operating Activities Net Cash Provided By (Used In) Investing Activities Net Cash Provided By (Used In) Financing Activities Power Guarantor Other Consolidating Consolidated As of June 30, 2012 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, 2011 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 million of PSE&G's customers were without power. In terms of customer outages, this was the most in PSE&G's history, surpassing both Tropical Storm Irene and the October snowstorm in 2011. With the assistance of mutual aid crews from other utilities, PSE&G's associates are working to minimize the length of time its customers are without electric or gas service. PSE&G and Power are unable to estimate the possible loss or range of loss related to Hurricane Sandy; however, such costs could be material. We filed our 2013 Annual Formula Rate Update with FERC in October 2012, which would provide for approximately $174 million in increased annual transmission revenues effective January 1, 2013. the continuing potential for sustained lower natural gas and electricity prices, both at market hubs and at locations where we operate, customer migration away from our BGS supply contracts, regulatory and political uncertainty, particularly with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation, and challenges to competitive markets, including support for subsidized generation in many states, particularly in New Jersey. continue to focus on controlling costs while maintaining our safety, reliability and compliance standards, successfully New Jersey’s Long-Term Capacity Agreement Pilot Program Act (LCAPP Act), These efforts to artificially depress the wholesale capacity auction were intended to be mitigated by the Minimum Offer Price Rule (MOPR) approved by FERC. The MOPR was intended to restrict new natural gas-fired generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. The MOPR was in place for the May 2012 auction, but we believe it did not operate to protect the market against these suppression efforts. As a result, discussions among a diverse group of PJM Interconnection L.L.C. (PJM) stakeholders to improve the MOPR ensued and a settlement was recently reached among those stakeholders. PJM is currently educating its stakeholders on the settlement and PJM plans to bring the settlement to a stakeholder vote in November 2012. If this settlement is approved by the FERC, On March 30, 2012, the FERC issued an order finding that allocation of costs associated with high voltage (500 kV and higher) transmission projects in PJM to all customers in PJM is just and reasonable. This order, which has been challenged on rehearing, therefore preserves the current cost allocation for the Susquehanna-Roseland As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the Nuclear Regulatory Commission (NRC) has been performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan will result in a series of additional regulations for the nuclear industry. The first regulations have already been issued, and in conjunction with additional regulations, could impact future operations and capital requirements for our facilities. We believe that our nuclear plants currently meet the stringent applicable design and safety specifications of the NRC. We continued various construction activities at Power, including We are continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of Salem and Hope Creek stations. The In Earnings (Losses) 2012 2011 2012 2011 Power Energy Holdings PSEG Income from Continuing Operations PSEG Net Income Earnings Per Share (Diluted) 2012 2011 2012 2011 PSEG Income from Continuing Operations PSEG Net Income 2012 2011 2012 2011 NDT Fund Income (Expense) the absence of the after-tax charge on leveraged leases related to Dynegy in the prior year, and lower average prices realized lower gas volumes and demand due to milder winter audits in the first quarter of 2012. 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Operating Revenues Operation and Maintenance Depreciation and Amortization Taxes Other than Income Taxes Income from Equity Method Investments Other Income and (Deductions) Other-Than-Temporary Impairments Interest Expense Income (Loss) from Discontinued Operations 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Income from Continuing Operations Income (Loss) from Discontinued Operations, net of tax Net Income For the three months and lower average prices realized on generation sold into the PJM and New York power pools lower average pricing and lower volumes of electricity sold under our BGS contracts, net of lower cost to serve, lower volumes on wholesale load contracts in PJM, lower operating reserve, ancillary and Reliability Must Run (RMR) revenues primarily in PJM and New England, lower average pricing and volumes of gas sold under our BGSS contracts, net of lower cost to These decreases were partially offset by lower operation and maintenance costs in 2012 at our fossil plants. was partially offset by lower interest expense due to the 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income (Deductions) Other-Than-Temporary Impairments Interest Expense Income Tax Expense Income (Loss) from Discontinued Operations lower net revenues of a decrease of a decrease of partially offset by a a decrease of a net decrease of increased$4 million due primarily to placing the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut into service on June 1, 2012, as well as completion of the steam path retrofit upgrade at Peach Bottom Unit 3 in October 2011. lower net revenues of a decrease of a net decrease of a decrease of a a net decrease of Other-Than-Temporary Impairmentsincreased a decrease of 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Income from Continuing Operations Net Income tax benefits related to settlement of IRS audits, partially offset by lower gas volumes and demands due to milder winter weather. 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Operating Revenues Operation and Maintenance Taxes Other Than Income Taxes Other-Than Temporary Impairments Income Tax Expense (Benefit) Commodity Revenuedecreased 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Income from Continuing Operations Net Income audits in the first quarter of 2012. Power’s operating cash flow decreased requirements. As of June 30, 2012 Company/Facility Total Usage Available Expiration Primary Purpose PSEG 5-year Credit Facility 5-year Credit Facility Total PSEG Power 5-year Credit Facility 5-year Credit Facility Bilateral Credit Facility Total Power PSE&G 5-year Credit Facility Total PSE&G Total from positive. During the Three Months Ended June 30, 2012 MTM VaR (A) 95% Confidence Level, Loss could exceed VaR one day in 20 days Period End Average for the Period High Low 99.5% Confidence Level, Loss could exceed VaR one day in 200 days Period End Average for the Period High Low Three Months Ended June 30, 2012 Total Number Average April 1-April 30 May 1-May 31 June 1-June 30 Reliability Pricing Model auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for CPV in the 2015/2016 delivery year and for Hess in the 2016/2017 delivery year, provided that they satisfy their obligations under the SOCA and that the SOCA remains in effect. set the issues for a full hearing. will be applied in the RPM auction in May 2013 and should enhance the competitiveness of the auction. We cannot predict the outcome of this matter. opening up of transmission construction and ownership to third-party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects. 85. In September 2011, the Massachusetts Attorney General, along with several state utility commissions, consumer advocates and consumer groups from six New England states, filed a complaint at FERC against a group of New England transmission owners seeking to reduce the base return on equity used in calculating these transmission owners’ formula transmission rates. The matter has been set for hearing. While we are not the subject of ours. Evidentiary hearings were held in October 2012 and PURA is expected to issue a final decision by the end of 2012 effective January 1, 2013. no impact on Net Income. On September 13, 2012, a Decision and Order approving the stipulation for provisional rates was signed effective October 1, 2012. December 31, 2011 Form 10-K page 27, 87. 87. On July 18, 2012, the BPU approved a Stipulation regarding our March 2010 Solar I filing, effective August 1, 2012. This Order will result in an increase in rates of $2.5 million for our electric customers. On July 2, 2012, we filed a petition with the BPU for an increase in the electric SPRC for the Solar Loan I program. If our filing is approved by the BPU as filed, the result would be an increase in rates to be paid by our electric customers of $17.0 million on an annual basis. The discovery phase of this proceeding is underway and in October 2012 the matter was assigned to an ALJ. public comment. The audit report makes a number of findings and recommendations, including the finding that no violations of either the state or federal affiliate rules were found. In accordance with the BPU’s procedural schedule, the comment period recommendations, although the procedural schedule does not establish a date for a final order in this matter. .In accordance with a ruling of the United States Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the Clean Air Act. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. The Court of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAP and the NSPS. These cases remain pending. The EPA has stayed implementation of the new source NESHAP rule pending its reconsideration until November 2, 2012. matter remains pending. By: By: By:xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THEJuneSeptember 30, 2012 001-09120 22-2625848 22-2625848 001-34232 973 430-7000http://www.pseg.com001-3423222-3663480 22-3663480 001-00973 973 430-7000http://www.pseg.com001-0097322-1212800 973 430-7000http://www.pseg.com22-1212800 xý No¨Public Service Enterprise Group IncorporatedYes xNo ¨PSEG Power LLCYes xNo ¨Public Service Electric and Gas CompanyYes xNo ¨Public Service Enterprise Group IncorporatedLarge accelerated filer xAccelerated filer ¨Non-accelerated filer ¨Smaller reporting company ¨Public Service Enterprise Group Incorporated PSEG Power LLC ¨o¨o¨o¨o¨o¨oxýJuly 17,October 16, 2012, Public Service Enterprise Group Incorporated had outstanding 505,935,372505,917,472 shares of its sole class of Common Stock, without par value.July 17,October 16, 2012, 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.FORWARD-LOOKING STATEMENTSiiPART I. FINANCIAL INFORMATIONItem 1.Page FORWARD-LOOKING STATEMENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements 1 6 11 16 17 18 18 19 22 27 28 38 39 46 55 56 57 58 59 60 62 65 65 69 77 8080Item 4. 81 Item 4.8283838383Item 6. 83Item 6.9192discount rates and funding requirements, and Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 OPERATING REVENUES $ 2,402 $ 2,620 $ 7,375 $ 8,443 OPERATING EXPENSES Energy Costs 879 1,167 2,819 3,740 Operation and Maintenance 619 603 1,876 1,829 Depreciation and Amortization 286 263 797 739 Taxes Other Than Income Taxes 24 31 73 102 Total Operating Expenses 1,808 2,064 5,565 6,410 OPERATING INCOME 594 556 1,810 2,033 Income from Equity Method Investments 7 1 9 8 Other Income 121 45 216 176 Other Deductions (26 ) (11 ) (61 ) (39 ) Other-Than-Temporary Impairments (2 ) (8 ) (14 ) (13 ) Interest Expense (106 ) (117 ) (310 ) (361 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 588 466 1,650 1,804 Income Tax (Expense) Benefit (241 ) (201 ) (599 ) (757 ) INCOME FROM CONTINUING OPERATIONS 347 265 1,051 1,047 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(51) for the three and nine months ended 2011 — 29 — 96 NET INCOME $ 347 $ 294 $ 1,051 $ 1,143 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC 505,914 505,909 505,942 505,959 DILUTED 507,111 506,999 507,037 506,963 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS $ 0.69 $ 0.52 $ 2.08 $ 2.07 NET INCOME $ 0.69 $ 0.58 $ 2.08 $ 2.26 DILUTED INCOME FROM CONTINUING OPERATIONS $ 0.68 $ 0.52 $ 2.07 $ 2.06 NET INCOME $ 0.68 $ 0.58 $ 2.07 $ 2.25 DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.3550 $ 0.3425 $ 1.0650 $ 1.0275 Millions(Unaudited) Three Months Ended
June 30, Six Months Ended
June 30, $ 2,098 $ 2,469 $ 4,973 $ 5,823 761 1,010 1,940 2,573 629 575 1,257 1,226 255 235 511 476 20 28 49 71 1,665 1,848 3,757 4,346 433 621 1,216 1,477 2 4 2 7 51 55 95 131 (19 ) (15 ) (35 ) (28 ) (7 ) (1 ) (12 ) (5 ) (103 ) (117 ) (204 ) (244 ) 357 547 1,062 1,338 (146 ) (227 ) (358 ) (556 ) 211 320 704 782 0 3 0 67 $ 211 $ 323 $ 704 $ 849 505,903 505,988 505,956 505,984 506,969 506,761 506,999 506,945 $ 0.42 $ 0.63 $ 1.39 $ 1.55 $ 0.42 $ 0.63 $ 1.39 $ 1.68 $ 0.42 $ 0.63 $ 1.39 $ 1.54 $ 0.42 $ 0.63 $ 1.39 $ 1.67 $ 0.3550 $ 0.3425 $ 0.7100 $ 0.6850 Three Months Ended
June 30, Six Months Ended
June 30, $ 211 $ 323 $ 704 $ 849 (15 ) (10 ) 22 (15 ) (5 ) (10 ) 15 (1 ) (5 ) (15 ) (25 ) (56 ) 8 43 15 49 (17 ) 8 27 (23 ) $ 194 $ 331 $ 731 $ 826 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 NET INCOME $ 347 $ 294 $ 1,051 $ 1,143 Other Comprehensive Income (Loss), net of tax Available-for-Sale Securities, net of tax (expense) benefit of $5, $59, $(16) and $76 for the three and nine months ended 2012 and 2011, respectively (10 ) (58 ) 12 (73 ) Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $1, $(9), $(10) and $(8) for the three and nine months ended 2012 and 2011, respectively (2 ) 12 13 11 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $7, $25, $24 and $62 for the three and nine months ended 2012 and 2011, respectively (8 ) (35 ) (33 ) (91 ) Pension/OPEB adjustment, net of tax (expense) benefit of $(5), $(4), $(16) and $(34) for the three and nine months ended 2012 and 2011, respectively 8 4 23 53 Other Comprehensive Income (Loss), net of tax (12 ) (77 ) 15 (100 ) COMPREHENSIVE INCOME $ 335 $ 217 $ 1,066 $ 1,043 June 30, December 31, $ 765 $ 834 896 967 16 16 255 289 562 685 403 367 397 308 165 156 90 0 359 167 32 122 3,940 3,911 26,045 25,080 (7,455 ) (7,231 ) 18,590 17,849 3,417 3,805 827 925 1,294 1,303 1,417 1,349 187 172 16 16 52 131 133 106 19 22 250 232 7,612 8,061 $ 30,142 $ 29,821 September 30,
2012 December 31,
2011 ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 780 $ 834 Accounts Receivable, net of allowances of $52 and $56 in 2012 and 2011, respectively 1,044 967 Tax Receivable — 16 Unbilled Revenues 215 289 Fuel 657 685 Materials and Supplies, net 416 367 Prepayments 274 308 Derivative Contracts 123 156 Deferred Income Taxes 148 — Regulatory Assets 280 167 Other 41 122 Total Current Assets 3,978 3,911 PROPERTY, PLANT AND EQUIPMENT 26,731 25,080 Less: Accumulated Depreciation and Amortization (7,628 ) (7,231 ) Net Property, Plant and Equipment 19,103 17,849 NONCURRENT ASSETS Regulatory Assets 3,336 3,805 Regulatory Assets of Variable Interest Entities (VIEs) 760 925 Long-Term Investments 1,314 1,303 Nuclear Decommissioning Trust (NDT) Fund 1,501 1,349 Other Special Funds 192 172 Goodwill 16 16 Other Intangibles 57 131 Derivative Contracts 144 106 Restricted Cash of VIEs 21 22 Other 284 232 Total Noncurrent Assets 7,625 8,061 TOTAL ASSETS $ 30,706 $ 29,821
2012
2011 $ 751 $ 417 221 216 16 0 898 1,184 88 131 98 97 88 30 0 170 138 214 123 107 72 100 323 291 2,816 2,957 5,939 5,458 206 228 10 9 505 489 1,115 1,127 624 734 0 39 588 643 112 26 152 292 93 86 9,344 9,131 6,676 6,694 616 723 44 44 7,336 7,461 4,829 4,823 (605 ) (601 ) 6,730 6,385 (310 ) (337 ) 10,644 10,270 2 2 10,646 10,272 17,982 17,733 $ 30,142 $ 29,821 September 30,
2012 December 31,
2011 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year (includes $50 at fair value in 2011) $ 751 $ 417 Securitization Debt of VIEs Due Within One Year 224 216 Accounts Payable 1,012 1,184 Derivative Contracts 51 131 Accrued Interest 119 97 Accrued Taxes 216 30 Deferred Income Taxes — 170 Clean Energy Program 89 214 Obligation to Return Cash Collateral 122 107 Regulatory Liabilities 94 100 Other 361 291 Total Current Liabilities 3,039 2,957 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 6,058 5,458 Regulatory Liabilities 248 228 Regulatory Liabilities of VIEs 10 9 Asset Retirement Obligations 513 489 Other Postretirement Benefit (OPEB) Costs 1,116 1,127 Accrued Pension Costs 629 734 Clean Energy Program — 39 Environmental Costs 565 643 Derivative Contracts 112 26 Long-Term Accrued Taxes 166 292 Other 108 86 Total Noncurrent Liabilities 9,525 9,131 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 6,729 6,694 Securitization Debt of VIEs 561 723 Project Level, Non-Recourse Debt 44 44 Total Long-Term Debt 7,334 7,461 STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 1,000,000,000 shares; issued, 2012 and 2011—533,556,660 shares 4,836 4,823 Treasury Stock, at cost, 2012—27,664,188 shares; 2011—27,611,374 shares (606 ) (601 ) Retained Earnings 6,898 6,385 Accumulated Other Comprehensive Loss (322 ) (337 ) Total Common Stockholders’ Equity 10,806 10,270 Noncontrolling Interest 2 2 Total Stockholders’ Equity 10,808 10,272 Total Capitalization 18,142 17,733 TOTAL LIABILITIES AND CAPITALIZATION $ 30,706 $ 29,821 Six Months Ended
June 30, $ 704 $ 849 0 (82 ) 511 483 84 75 165 (28 ) 134 101 (98 ) (21 ) (86 ) 35 8 23 (30 ) (19 ) (23 ) (29 ) (44 ) (25 ) (26 ) (93 ) 0 593 278 (2 ) (175 ) (465 ) (24 ) 0 1,378 1,395 (1,280 ) (1,002 ) 0 352 850 657 (867 ) (676 ) (42 ) (4 ) (1,339 ) (673 ) 16 234 500 0 (139 ) (606 ) 0 (1 ) (101 ) (96 ) (359 ) (347 ) (25 ) (27 ) (108 ) (843 ) (69 ) (121 ) 834 280 $ 765 $ 159 $ 114 $ 57 $ 197 $ 259 $ (129 ) $ (118 ) Nine Months Ended September 30, 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 1,051 $ 1,143 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposal of Discontinued Operations — (122 ) Depreciation and Amortization 797 745 Amortization of Nuclear Fuel 129 114 Provision for Deferred Income Taxes (Other than Leases) and ITC 221 629 Non-Cash Employee Benefit Plan Costs 203 138 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes (81 ) (16 ) Leveraged Lease Reserve, net of tax — 170 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 116 (14 ) Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs 46 100 Over (Under) Recovery of Societal Benefits Charge (SBC) (51 ) (26 ) Market Transition Charge Refund (23 ) (47 ) Cost of Removal (71 ) (43 ) Net Realized (Gains) Losses and (Income) Expense from NDT Fund (107 ) (110 ) Net Change in Tax Receivable 16 312 Net Change in Certain Current Assets and Liabilities 305 (44 ) Employee Benefit Plan Funding and Related Payments (193 ) (486 ) Other (47 ) (34 ) Net Cash Provided By (Used In) Operating Activities 2,311 2,409 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (1,969 ) (1,479 ) Proceeds from Sale of Discontinued Operations — 687 Proceeds from Sales of Available-for-Sale Securities 1,473 1,088 Investments in Available-for-Sale Securities (1,497 ) (1,110 ) Other (58 ) (13 ) Net Cash Provided By (Used In) Investing Activities (2,051 ) (827 ) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans — (64 ) Issuance of Long-Term Debt 850 750 Redemption of Long-Term Debt (439 ) (606 ) Repayment of Non-Recourse Debt (1 ) (1 ) Redemption of Securitization Debt (154 ) (147 ) Cash Dividends Paid on Common Stock (538 ) (520 ) Other (32 ) (32 ) Net Cash Provided By (Used In) Financing Activities (314 ) (620 ) Net Increase (Decrease) in Cash and Cash Equivalents (54 ) 962 Cash and Cash Equivalents at Beginning of Period 834 280 Cash and Cash Equivalents at End of Period $ 780 $ 1,242 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid (Received) $ 109 $ 60 Interest Paid, Net of Amounts Capitalized $ 280 $ 341 Accrued Property, Plant and Equipment Expenditures $ 259 $ 211 Three Months Ended
June 30, Six Months Ended
June 30, $ 985 $ 1,285 $ 2,546 $ 3,252 447 603 1,269 1,738 284 271 525 548 58 56 115 110 789 930 1,909 2,396 196 355 637 856 37 49 67 119 (17 ) (14 ) (32 ) (26 ) (7 ) (1 ) (12 ) (3 ) (32 ) (41 ) (62 ) (92 ) 177 348 598 854 (73 ) (143 ) (241 ) (352 ) 104 205 357 502 0 3 0 67 $ 104 $ 208 $ 357 $ 569 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 OPERATING REVENUES $ 1,038 $ 1,398 $ 3,584 $ 4,650 OPERATING EXPENSES Energy Costs 456 597 1,725 2,335 Operation and Maintenance 255 262 780 810 Depreciation and Amortization 60 56 175 166 Total Operating Expenses 771 915 2,680 3,311 OPERATING INCOME 267 483 904 1,339 Other Income 104 37 171 156 Other Deductions (20 ) (10 ) (52 ) (37 ) Other-Than-Temporary Impairments (2 ) (8 ) (14 ) (10 ) Interest Expense (35 ) (42 ) (97 ) (134 ) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 314 460 912 1,314 Income Tax (Expense) Benefit (133 ) (187 ) (374 ) (539 ) INCOME FROM CONTINUING OPERATIONS 181 273 538 775 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of $(15) and $(51) for the three and nine months ended 2011 — 29 — 96 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 181 $ 302 $ 538 $ 871 Three Months Ended
June 30, Six Months Ended
June 30, $ 104 $ 208 $ 357 $ 569 (15 ) (10 ) 22 (17 ) (5 ) (10 ) 15 (1 ) (5 ) (15 ) (25 ) (56 ) 7 36 14 42 (18 ) 1 26 (32 ) $ 86 $ 209 $ 383 $ 537 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 NET INCOME $ 181 $ 302 $ 538 $ 871 Other Comprehensive Income (Loss), net of tax Available-for-Sale Securities, net of tax (expense) benefit of $6, $58, $(16) and $77 for the three and nine months ended 2012 and 2011, respectively (11 ) (60 ) 11 (77 ) Change in Fair Value of Derivative Instruments, net of tax (expense) benefit of $1, $(9), $(10) and $(8) for the three and nine months ended 2012 and 2011, respectively (2 ) 12 13 11 Reclassification Adjustments for Net Amounts included in Net Income, net of tax (expense) benefit of $7, $25, $24 and $62 for the three and nine months ended 2012 and 2011, respectively (9 ) (35 ) (34 ) (91 ) Pension/OPEB adjustment, net of tax (expense) benefit of $(4), $(3), $(14) and $(31) for the three and nine months ended 2012 and 2011, respectively 7 3 21 45 Other Comprehensive Income (Loss), net of tax (15 ) (80 ) 11 (112 ) COMPREHENSIVE INCOME $ 166 $ 222 $ 549 $ 759 June 30, December 31, ASSETS $ 2 $ 12 258 267 265 381 737 907 562 685 301 272 146 139 21 24 2 0 2,294 2,687 9,379 9,191 (2,586 ) (2,460 ) 6,793 6,731 1,417 1,349 16 16 52 131 35 33 40 55 102 85 1,662 1,669 $ 10,749 $ 11,087 September 30,
2012 December 31,
2011 ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 5 $ 12 Accounts Receivable 295 267 Accounts Receivable—Affiliated Companies, net 100 381 Short-Term Loan to Affiliate 890 907 Fuel 657 685 Materials and Supplies, net 310 272 Derivative Contracts 102 139 Prepayments 22 24 Total Current Assets 2,381 2,687 PROPERTY, PLANT AND EQUIPMENT 9,564 9,191 Less: Accumulated Depreciation and Amortization (2,692 ) (2,460 ) Net Property, Plant and Equipment 6,872 6,731 NONCURRENT ASSETS Nuclear Decommissioning Trust (NDT) Fund 1,501 1,349 Goodwill 16 16 Other Intangibles 57 131 Other Special Funds 36 33 Derivative Contracts 22 55 Other 109 85 Total Noncurrent Assets 1,741 1,669 TOTAL ASSETS $ 10,994 $ 11,087 June 30, December 31, LIABILITIES AND MEMBER’S EQUITY $ 300 $ 66 343 541 88 124 41 53 32 32 86 86 890 902 1,442 1,266 270 259 186 180 8 24 202 236 53 8 85 83 2,246 2,056 2,386 2,685 2,028 2,028 (986 ) (986 ) 4,435 4,678 (250 ) (276 ) 5,227 5,444 $ 10,749 $ 11,087 September 30,
2012 December 31,
2011 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 300 $ 66 Accounts Payable 433 541 Derivative Contracts 51 124 Deferred Income Taxes 4 53 Accrued Interest 49 32 Other 90 86 Total Current Liabilities 927 902 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) 1,463 1,266 Asset Retirement Obligations 275 259 Other Postretirement Benefit (OPEB) Costs 189 180 Derivative Contracts 6 24 Accrued Pension Costs 205 236 Long-Term Accrued Taxes 66 8 Other 84 83 Total Noncurrent Liabilities 2,288 2,056 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) LONG-TERM DEBT Total Long-Term Debt 2,386 2,685 MEMBER’S EQUITY Contributed Capital 2,028 2,028 Basis Adjustment (986 ) (986 ) Retained Earnings 4,616 4,678 Accumulated Other Comprehensive Loss (265 ) (276 ) Total Member’s Equity 5,393 5,444 TOTAL LIABILITIES AND MEMBER’S EQUITY $ 10,994 $ 11,087 Six Months Ended
June 30, $ 357 $ 569 0 (82 ) 115 116 84 75 184 (92 ) (86 ) 35 34 24 (26 ) (93 ) 94 99 36 (54 ) 40 162 (14 ) (141 ) 73 649 (6 ) 10 (39 ) (125 ) 6 (6 ) 852 1,146 (344 ) (323 ) 0 352 677 657 (692 ) (672 ) 170 (211 ) 0 16 (189 ) (181 ) (600 ) (350 ) (66 ) (606 ) (7 ) (6 ) (673 ) (962 ) (10 ) 3 12 11 $ 2 $ 14 $ 118 $ 69 $ 57 $ 101 $ (83 ) $ (69 ) Nine Months Ended September 30, 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 538 $ 871 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Gain on Disposal of Discontinued Operations — (122 ) Depreciation and Amortization 175 173 Amortization of Nuclear Fuel 129 114 Provision for Deferred Income Taxes and ITC 189 74 Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives 116 (14 ) Non-Cash Employee Benefit Plan Costs 53 33 Net Realized (Gains) Losses and (Income) Expense from NDT Fund (107 ) (110 ) Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies (10 ) (82 ) Margin Deposit (107 ) (63 ) Accounts Receivable 50 157 Accounts Payable (31 ) (103 ) Accounts Receivable/Payable-Affiliated Companies, net 193 650 Accrued Interest Payable 17 23 Other Current Assets and Liabilities 2 48 Employee Benefit Plan Funding and Related Payments (40 ) (127 ) Other 5 (35 ) Net Cash Provided By (Used In) Operating Activities 1,172 1,487 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (493 ) (530 ) Proceeds from Sale of Discontinued Operations — 687 Proceeds from Sales of Available-for-Sale Securities 1,295 1,088 Investments in Available-for-Sale Securities (1,315 ) (1,106 ) Short-Term Loan—Affiliated Company, net 17 (1,176 ) Other (10 ) 19 Net Cash Provided By (Used In) Investing Activities (506 ) (1,018 ) CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Recourse Long-Term Debt — 500 Cash Dividend Paid (600 ) (350 ) Redemption of Long-Term Debt (66 ) (606 ) Other (7 ) (10 ) Net Cash Provided By (Used In) Financing Activities (673 ) (466 ) Net Increase (Decrease) in Cash and Cash Equivalents (7 ) 3 Cash and Cash Equivalents at Beginning of Period 12 11 Cash and Cash Equivalents at End of Period $ 5 $ 14 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid (Received) $ 130 $ 110 Interest Paid, Net of Amounts Capitalized $ 73 $ 111 Accrued Property, Plant and Equipment Expenditures $ 84 $ 86 Three Months Ended
June 30, Six Months Ended
June 30, $ 1,407 $ 1,571 $ 3,346 $ 3,877 622 815 1,624 2,181 350 304 726 672 188 172 378 351 20 28 49 71 1,180 1,319 2,777 3,275 227 252 569 602 12 4 23 9 (1 ) 0 (2 ) (1 ) 0 0 0 (1 ) (74 ) (78 ) (147 ) (157 ) 164 178 443 452 (63 ) (73 ) (145 ) (184 ) $ 101 $ 105 $ 298 $ 268 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 OPERATING REVENUES $ 1,683 $ 1,841 $ 5,029 $ 5,718 OPERATING EXPENSES Energy Costs 756 943 2,380 3,124 Operation and Maintenance 366 342 1,092 1,014 Depreciation and Amortization 216 197 594 548 Taxes Other Than Income Taxes 24 31 73 102 Total Operating Expenses 1,362 1,513 4,139 4,788 OPERATING INCOME 321 328 890 930 Other Income 16 7 39 16 Other Deductions (6 ) (1 ) (8 ) (2 ) Other-Than-Temporary Impairments — — — (1 ) Interest Expense (73 ) (77 ) (220 ) (234 ) INCOME BEFORE INCOME TAXES 258 257 701 709 Income Tax (Expense) Benefit (103 ) (103 ) (248 ) (287 ) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 155 $ 154 $ 453 $ 422 Three Months Ended
June 30, Six Months Ended
June 30, $ 101 $ 105 $ 298 $ 268 0 0 (1 ) 1 $ 101 $ 105 $ 297 $ 269 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 NET INCOME $ 155 $ 154 $ 453 $ 422 Available-for-Sale Securities, net of tax (expense) benefit of $(1), $(0), $(0) and $(1) for the three and nine months ended 2012 and 2011, respectively 1 1 — 2 COMPREHENSIVE INCOME $ 156 $ 155 $ 453 $ 424 June 30, December 31, $ 22 $ 143 630 691 16 16 255 289 102 94 243 117 359 167 20 21 1,647 1,538 16,050 15,306 (4,618 ) (4,539 ) 11,432 10,767 3,417 3,805 827 925 313 280 61 57 45 4 19 22 102 89 4,784 5,182 $ 17,863 $ 17,487 September 30,
2012 December 31,
2011 ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 71 $ 143 Accounts Receivable, net of allowances of $52 and $56 in 2012 and 2011, respectively 729 691 Tax Receivable — 16 Unbilled Revenues 215 289 Materials and Supplies 105 94 Prepayments 145 117 Regulatory Assets 280 167 Derivative Contracts 3 — Other 30 21 Total Current Assets 1,578 1,538 PROPERTY, PLANT AND EQUIPMENT 16,509 15,306 Less: Accumulated Depreciation and Amortization (4,674 ) (4,539 ) Net Property, Plant and Equipment 11,835 10,767 NONCURRENT ASSETS Regulatory Assets 3,336 3,805 Regulatory Assets of VIEs 760 925 Long-Term Investments 334 280 Other Special Funds 63 57 Derivative Contracts 70 4 Restricted Cash of VIEs 21 22 Other 118 89 Total Noncurrent Assets 4,702 5,182 TOTAL ASSETS $ 18,115 $ 17,487 June 30, December 31, LIABILITIES AND CAPITALIZATION $ 450 $ 300 221 216 16 0 428 498 146 280 66 65 138 214 0 7 37 32 123 107 72 100 210 186 1,907 2,005 3,837 3,675 881 900 283 355 206 228 10 9 0 39 537 592 231 226 104 0 18 83 43 35 6,150 6,142 4,246 3,970 616 723 4,862 4,693 892 892 420 420 986 986 2,645 2,347 1 2 4,944 4,647 9,806 9,340 $ 17,863 $ 17,487 September 30,
2012 December 31,
2011 LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 450 $ 300 Securitization Debt of VIEs Due Within One Year 224 216 Accounts Payable 449 498 Accounts Payable—Affiliated Companies, net 155 280 Accrued Interest 71 65 Clean Energy Program 89 214 Derivative Contracts — 7 Deferred Income Taxes 16 32 Obligation to Return Cash Collateral 122 107 Regulatory Liabilities 94 100 Other 243 186 Total Current Liabilities 1,913 2,005 NONCURRENT LIABILITIES Deferred Income Taxes and ITC 3,916 3,675 Other Postretirement Benefit (OPEB) Costs 879 900 Accrued Pension Costs 285 355 Regulatory Liabilities 248 228 Regulatory Liabilities of VIEs 10 9 Clean Energy Program — 39 Environmental Costs 514 592 Asset Retirement Obligations 233 226 Derivative Contracts 106 — Long-Term Accrued Taxes 19 83 Other 37 35 Total Noncurrent Liabilities 6,247 6,142 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) CAPITALIZATION LONG-TERM DEBT Long-Term Debt 4,294 3,970 Securitization Debt of VIEs 561 723 Total Long-Term Debt 4,855 4,693 STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized; issued and outstanding, 2012 and 2011—132,450,344 shares 892 892 Contributed Capital 420 420 Basis Adjustment 986 986 Retained Earnings 2,800 2,347 Accumulated Other Comprehensive Income 2 2 Total Stockholder’s Equity 5,100 4,647 Total Capitalization 9,955 9,340 TOTAL LIABILITIES AND CAPITALIZATION $ 18,115 $ 17,487 Six Months Ended
June 30, $ 298 $ 268 378 351 75 65 89 67 (44 ) (25 ) (23 ) (29 ) 8 23 (30 ) (19 ) 108 204 (8 ) (2 ) (126 ) (234 ) (94 ) (65 ) (11 ) (30 ) (121 ) (294 ) (40 ) (1 ) 459 279 (870 ) (674 ) 71 0 (71 ) 0 (48 ) (23 ) 3 0 (915 ) (697 ) 16 298 500 0 (73 ) 0 (101 ) (96 ) (7 ) (3 ) 335 199 (121 ) (219 ) 143 245 $ 22 $ 26 $ 4 $ (44 ) $ 139 $ 153 $ (46 ) $ (49 ) Nine Months Ended September 30, 2012 2011 CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 453 $ 422 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization 594 548 Provision for Deferred Income Taxes and ITC 131 563 Non-Cash Employee Benefit Plan Costs 134 92 Cost of Removal (71 ) (43 ) Market Transition Charge (MTC) Refund (23 ) (47 ) Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs 46 100 Over (Under) Recovery of SBC (51 ) (26 ) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues 97 261 Materials and Supplies (11 ) (1 ) Prepayments (28 ) (203 ) Net Change in Tax Receivable 16 (21 ) Accounts Receivable/Payable-Affiliated Companies, net (41 ) (381 ) Other Current Assets and Liabilities 2 (66 ) Employee Benefit Plan Funding and Related Payments (137 ) (311 ) Other (70 ) (15 ) Net Cash Provided By (Used In) Operating Activities 1,041 872 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment (1,369 ) (939 ) Proceeds from Sale of Available-for-Sale Securities 73 — Investments in Available-for-Sale Securities (73 ) — Solar Loan Investments (56 ) (34 ) Restricted Funds 1 (1 ) Net Cash Provided By (Used In) Investing Activities (1,424 ) (974 ) CASH FLOWS FROM FINANCING ACTIVITIES Issuance of Long-Term Debt 850 250 Redemption of Long-Term Debt (373 ) — Redemption of Securitization Debt (154 ) (147 ) Deferred Issuance Costs (12 ) (4 ) Net Cash Provided By (Used In) Financing Activities 311 99 Net Increase (Decrease) In Cash and Cash Equivalents (72 ) (3 ) Cash and Cash Equivalents at Beginning of Period 143 245 Cash and Cash Equivalents at End of Period $ 71 $ 242 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid (Received) $ (30 ) $ (44 ) Interest Paid, Net of Amounts Capitalized $ 205 $ 225 Accrued Property, Plant and Equipment Expenditures $ 175 $ 125 primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings has also invested in solar generation projects and is exploring opportunities for other investments in renewable generation and has been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA). starting in 2014.ReportReports on Form 10-Q for the quarterquarters ended March 31, 2012 and June 30, 2012.2011.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS.(UNAUDITED)onconcerning balance sheet offsetting disclosures to facilitate comparability between financial statements prepared on the basis of GAAP and IFRS. This standard requires entities:entitiesNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)$16$16 million as of JuneSeptember 30, 2012 and December 31, 2011.2011. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II during the first halfnine months of 2012 or in 2011. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding or Transition Funding II.Power$352$352 million, resulting in an after-tax gain of $54 million.$335$335 million, resulting in an after-tax gain of approximately $25 million.$25 million.sixnine months ended JuneSeptember 30, 2011, which were reclassified to Discontinued Operations, are summarized below:
June 30,
June 30, Millions $ 29 $ 92 $ 2 $ 20 $ 2 $ 13 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) Three Months Ended Nine Months Ended September 30,
2011 September 30,
2011 Millions Operating Revenues $ 20 $ 112 Income Before Income Taxes $ 6 $ 26 Net Income $ 4 $ 17 Credit Risk Profile Based on Payment Activity As of As of June 30, December 31, Millions $ 150 $ 106 13 10 $ 163 $ 116 Credit Risk Profile Based on Payment Activity As of As of Consumer Loans September 30,
2012 December 31,
2011 Millions Commercial/Industrial $ 159 $ 106 Residential 14 10 Total $ 173 $ 116 JuneSeptember 30, 2012 and December 31, 2011, respectively. As of As of June 30, December 31, Millions $ 725 $ 763 535 553 1,260 1,316 (427 ) (435 ) 833 881 (677 ) (716 ) $ 156 $ 165 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) As of As of September 30,
2012 December 31,
2011 Millions Lease Receivables (net of Non-Recourse Debt) $ 724 $ 763 Estimated Residual Value of Leased Assets 535 553 1,259 1,316 Unearned and Deferred Income (423 ) (435 ) Gross Investments in Leases 836 881 Deferred Tax Liabilities (696 ) (716 ) Net Investments in Leases $ 140 $ 165
Non-Recourse Debt As of
June 30, As of
December 31, Millions $ 21 $ 21 73 110 316 316 165 299 134 0 16 17 $ 725 $ 763 As of As of Counterparties’ Credit Rating (S&P) as of September 30, 2012 September 30,
2012 December 31,
2011 Millions AA $ 21 $ 21 A+ 73 110 BBB+ - BBB- 316 316 B- 165 299 CCC 133 — Not Rated 16 17 Total $ 724 $ 763 JuneSeptember 30, 2012, the gross investment in the leases of such assets, net of non-recourse debt, was $553$555 million ($57 ($40 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the table below.
Investment
Owned
Type
S&P Credit
Ratings Millions MW IL $ 134 64% 1,538 Coal CCC Edison Mission Energy IL $ 84 64% 1,044 Coal CCC Edison Mission Energy PA $ 113 17% 1,711 Coal B- GenOn REMA, LLC PA $ 114 17% 1,711 Coal B- GenOn REMA, LLC PA $ 108 100% 603 Coal B- GenOn REMA, LLC Asset Location Total Counterparty Millions MW Powerton Station Units 5 and 6 IL $ 134 64 % 1,538 Coal CCC Edison Mission Energy Joliet Station Units 7 and 8 IL $ 84 64 % 1,044 Coal CCC Edison Mission Energy Keystone Station Units 1 and 2 PA $ 114 17 % 1,711 Coal B- GenOn REMA, LLC Conemaugh Station Units 1 and 2 PA $ 114 17 % 1,711 Coal B- GenOn REMA, LLC Shawville Station Units 1, 2, 3 and 4 PA $ 109 100 % 603 Coal B- GenOn REMA, LLC our facilities under lease by indirect subsidiary companies of Energy Holdings to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc (GenOn), PSEGEnergy Holdings believes Keystone has adequate environmental controls installed. Conemaugh has flue gas desulfurization control. Selective catalytic reduction (SCR) equipment for Nitrogen Oxidenitrogen oxide (NOx) and mercury control are scheduled to be installed and operational at Conemaugh in 2014.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)Holdings’Holdings' indirect subsidiaries' lease investment as specified in the lease agreement. On July 22, 2012, GenOn announced that it has signed a definitive agreement to merge with NRG Energy, Inc. We areEnergy Holdings is carefully monitoring these developments.EME,EME; that Midwest Generation is largely dependent upon EME for its funding,funding; and that, based upon current projections, EME will not be able to meet its debt obligation in June 2013,2013. In addition, Edison International also reported that, if EME and that failing a restructuring of itsMidwest Generation failed to restructure their obligations, EME and Midwest Generation may need to file for protection under Chapter 11 of the Bankruptcy Code, which could have an impact on the Powerton and Joliet leases.Some of theThe leasing transactions include letters of credit, affiliate guarantees, or covenants that restrict the flow of dividends from the lessee to its parent, collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met.parent. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a temporary market downturn or degradation in operating performance of the leased assets. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings could step into the lease directly to protect its investments. In the event of a default in any of the lease transactions, Energy HoldingsHoldings' indirect subsidiary companies would exercise itstheir rights and attempt to seek recovery of itstheir investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failurewould likely delay any efforts on the part of the lessors to assert their rights upon default. Failure to recover adequate value could ultimately lead to a foreclosure on the lease by the lenders. If foreclosures were toaffiliatesindirect subsidiary companies of Energy Holdings and Dynegy reached a settlement agreement resolving disputes that had arisen between them with regard to Dynegy Holding’s (DH) rejection of the Dynegy leases. The settlement agreement resolvesresolved certain disputes regarding theEnergy Holdings' Dynegy leases, including claims under our Tax Indemnity AgreementAgreements that indirect subsidiaries of Energy Holdings have with DH. The original terms of the settlement agreement included a cash payment to Energy Holdings of $7.5$7.5 million, which was received on January 4, 2012, and thean allowed claim in Bankruptcy Court’s allowanceCourt of a $110$110 million claim against DH. On December 30, 2011, the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. The Energy Holdings' indirect subsidiary companies that are owners/lessors of the two plants ceased leveraged lease accounting and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values (See Note 11. Fair Value Measurements).iswas supported by the various settling claimants, providing that weEnergy Holdings and other unsecured creditors of DH willwould be paid our claims partially in cash and partially in stock in a reorganized Dynegy that willwould emerge at the conclusion of the bankruptcy. On July 3,September 5, 2012, the Bankruptcy Court approved DH’s disclosure statementNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)describing its amendedDynegy’s plan of reorganization; that disclosure statement is now being usedreorganization. On October 1, 2012, Dynegy emerged from bankruptcy and distributed cash and stock settlements to the claimants. The total recovery of Energy Holdings' indirect subsidiary companies from the Dynegy leases, including proceeds from the liquidation of Dynegy common stock, the aforementioned cash payment received in January 2012 and the recovery of professional fees of formal solicitation of creditor votes on DH’s amended plan. The Bankruptcy Court will receive the results of the balloting by creditors and conduct a hearing on approval of DH’s amended plan on September 5,fourth quarter 2012.On December 30, 2011, the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP since the lease agreements were effectively terminated. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. As the owner of the two plants, Energy Holdings’ lessor entities ceased leveraged lease accounting, and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values (See Note 11. Fair Value Measurements). DH remains responsible for the operations, including the financial obligations, of these lessor entities. As of the June 5, 2012 effective date of the amended settlement agreement, the lease debt and the related assets were written off.third partythird-party investment advisorsadvisers who operate under investment guidelines developed by Power.In September 2012, Power restructured a portion of its NDT Fund and realized gains of $59 million. The investments were transitioned to new investment managers to remove under-performing managers.
Unrealized
Gains
Unrealized
Losses
Value Millions Equity Securities $ 583 $ 155 $ (10 ) $ 728 Debt Securities 291 15 0 306 303 17 0 320 Total Debt Securities 594 32 0 626 Other Securities 63 0 0 63 Total NDT Available-for-Sale Securities $ 1,240 $ 187 $ (10 ) $ 1,417
Unrealized
Gains
Unrealized
Losses
Value Millions Equity Securities $ 582 $ 126 $ (23 ) $ 685 Debt Securities 343 16 0 359 268 15 (2 ) 281 Total Debt Securities 611 31 (2 ) 640 Other Securities 24 0 0 24 Total NDT Available-for-Sale Securities $ 1,217 $ 157 $ (25 ) $ 1,349 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) As of September 30, 2012 Cost Millions Equity Securities $ 626 $ 128 $ (5 ) $ 749 Debt Securities Government Obligations 274 14 — 288 Other Debt Securities 311 22 — 333 Total Debt Securities 585 36 — 621 Other Securities 131 — — 131 Total NDT Available-for-Sale Securities $ 1,342 $ 164 $ (5 ) $ 1,501 As of December 31, 2011 Cost Millions Equity Securities $ 582 $ 126 $ (23 ) $ 685 Debt Securities Government Obligations 343 16 — 359 Other Debt Securities 268 15 (2 ) 281 Total Debt Securities 611 31 (2 ) 640 Other Securities 24 — — 24 Total NDT Available-for-Sale Securities $ 1,217 $ 157 $ (25 ) $ 1,349
June 30,
2012
December 31,
2011 Millions $ 21 $ 27 $ 16 $ 22 As of As of September 30,
2012 December 31,
2011 Millions Accounts Receivable $ 61 $ 27 Accounts Payable $ 80 $ 22 JuneSeptember 30, 2012. As of June 30, 2012 As of December 31, 2011
Months
Months
Months
Months
Value
Unrealized
Losses
Value
Unrealized
Losses
Value
Unrealized
Losses
Value
Unrealized
Losses Millions $ 143 $ (10 ) $ 0 $ 0 $ 183 $ (23 ) $ 0 $ 0 18 0 1 0 20 0 3 0 33 0 7 0 56 (1 ) 4 (1 ) 51 0 8 0 76 (1 ) 7 (1 ) 1 0 0 0 0 0 0 0 $ 195 $ (10 ) $ 8 $ 0 $ 259 $ (24 ) $ 7 $ (1 ) As of September 30, 2012 As of December 31, 2011 Millions Equity Securities (A) $ 215 $ (5 ) $ — $ — $ 183 $ (23 ) $ — $ — Debt Securities Government Obligations (B) 11 — 2 — 20 — 3 — Other Debt Securities (C) 7 — 3 — 56 (1 ) 4 (1 ) Total Debt Securities 18 — 5 — 76 (1 ) 7 (1 ) Other Securities 6 — — — — — — — NDT Available-for-Sale Securities $ 239 $ (5 ) $ 5 $ — $ 259 $ (24 ) $ 7 $ (1 ) (A) Equity Securities—Represent investments primarily in common stock within a broad range of industries and sectors. The unrealized losses are distributed over two hundred companies with limited impairment durations. (B) Debt Securities (Government)—Unrealized losses on investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis. Power does not intend to sell nor will it be more-likely-than-not required to sell these securities. (C) Debt Securities (Corporate)—Represent investment grade corporate bonds which are not expected to settle for less than their amortized cost. Power does not intend to sell nor will it be more-likely-than-not required to sell these securities. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) Three Months Ended
June 30, Six Months Ended
June 30, Millions $ 290 $ 342 $ 635 $ 657 Net Realized Gains (Losses) on NDT Fund: $ 26 $ 36 $ 42 $ 95 (16 ) (11 ) (22 ) (18 ) $ 10 $ 25 $ 20 $ 77 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Millions Proceeds from NDT Fund Sales $ 617 $ 431 $ 1,252 $ 1,088 Net Realized Gains (Losses) on NDT Fund: Gross Realized Gains $ 94 $ 26 $ 136 $ 121 Gross Realized Losses (19 ) (10 ) (41 ) (28 ) Net Realized Gains (Losses) on NDT Fund $ 75 $ 16 $ 95 $ 93 $88$77 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on Power’s Condensed Consolidated Balance Sheet as of JuneSeptember 30, 2012. 2012.JuneSeptember 30, 2012 had the following maturities: Millions $ 15 138 178 34 11 250 $ 626 Time Frame Fair Value Millions Less than one year $ 21 1 - 5 years 129 6 - 10 years 173 11 - 15 years 38 16 - 20 years 9 Over 20 years 251 Total NDT Available-for-Sale Debt Securities $ 621 $12$14 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) As of June 30, 2012
Unrealized
Gains
Unrealized
Losses
Value Millions $ 13 $ 3 $ 0 $ 16 114 2 0 116 43 1 0 44 157 3 0 160 3 0 0 3 $ 173 $ 6 $ 0 $ 179 As of December 31, 2011
Unrealized
Gains
Unrealized
Losses
Value Millions $ 16 $ 3 $ 0 $ 19 148 5 0 153 $ 164 $ 8 $ 0 $ 172 As of September 30, 2012 Cost Millions Equity Securities $ 13 $ 4 $ — $ 17 Debt Securities Government Obligations 113 3 — 116 Other Debt Securities 45 2 — 47 Total Debt Securities 158 5 — 163 Other Securities 3 — — 3 Total Rabbi Trust Available-for-Sale Securities $ 174 $ 9 $ — $ 183 As of December 31, 2011 Cost Millions Equity Securities $ 16 $ 3 $ — $ 19 Debt Securities 148 5 — 153 Total Rabbi Trust Available-for-Sale Securities $ 164 $ 8 $ — $ 172 JuneSeptember 30, 2012, amounts in the above table do not include Accounts Receivable of $1$4 million and Accounts Payable of $2$5 million for Rabbi Trust Fund transactions which had not yet settled. These amounts are included on the Condensed Consolidated Balance Sheets. Three Months Ended
June 30, Six Months Ended
June 30, Millions $ 61 $ 0 $ 215 $ 0 $ 1 $ 0 $ 6 $ 0 0 0 0 0 $ 1 $ 0 $ 6 $ 0 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Millions Proceeds from Rabbi Trust Sales $ 6 $ — $ 221 $ — Net Realized Gains (Losses) on Rabbi Trust: Gross Realized Gains $ — $ — $ 6 $ — Gross Realized Losses — — — — Net Realized Gains (Losses) on Rabbi Trust $ — $ — $ 6 $ — NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)$4$5 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheets as of JuneSeptember 30, 2012.2012. The Rabbi Trust available-for-sale debt securities held as of JuneSeptember 30, 2012 had the following maturities: Millions $ 0 58 29 16 5 52 $ 160 Time Frame Fair Value Millions Less than one year $ — 1 - 5 years 58 6 - 10 years 31 11 - 15 years 10 16 - 20 years 5 Over 20 years 59 Total Rabbi Trust Available-for-Sale Debt Securities $ 163 The cost of these securities was determined on the basis of specific identification.
June 30,
2012
December 31,
2011 Millions $ 35 $ 33 59 57 85 82 $ 179 $ 172 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) As of As of September 30,
2012 December 31,
2011 Millions Power $ 36 $ 33 PSE&G 61 57 Other 86 82 Total Rabbi Trust Available-for-Sale Securities $ 183 $ 172 New federalFederal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.
Three Months
Three Months
June 30,
Six Months
Six Months
June 30, Millions $ 25 $ 23 $ 4 $ 3 $ 50 $ 47 $ 8 $ 7 55 58 16 15 111 116 32 30 (77 ) (82 ) (5 ) (4 ) (153 ) (163 ) (9 ) (8 ) 0 0 0 1 0 0 1 3 (4 ) (2 ) (3 ) (3 ) (9 ) (2 ) (7 ) (6 ) 42 30 8 4 84 60 16 7 $ 41 $ 27 $ 20 $ 16 $ 83 $ 58 $ 41 $ 33 0 0 5 5 0 0 10 10 $ 41 $ 27 $ 25 $ 21 $ 83 $ 58 $ 51 $ 43 Pension Benefits OPEB Pension Benefits OPEB Three Months Ended Three Months Ended Nine Months
Ended Nine Months
Ended September 30, September 30, September 30, September 30, 2012 2011 2012 2011 2012 2011 2012 2011 Millions Components of Net Periodic Benefit Cost Service Cost $ 26 $ 22 $ 5 $ 3 $ 76 $ 69 $ 13 $ 10 Interest Cost 56 56 17 15 167 172 49 45 Expected Return on Plan Assets (76 ) (85 ) (4 ) (5 ) (229 ) (248 ) (13 ) (13 ) Amortization of Net Transition Obligation — — 1 1 — — 2 4 Prior Service Cost (Credit) (5 ) (4 ) (4 ) (4 ) (14 ) (6 ) (11 ) (10 ) Actuarial Loss 41 29 7 4 125 89 23 11 Net Periodic Benefit Cost $ 42 $ 18 $ 22 $ 14 $ 125 $ 76 $ 63 $ 47 Special Termination Benefits 1 0 0 0 1 0 0 0 Effect of Regulatory Asset — — 4 5 — — 14 15 Total Benefit Costs, Including Effect of Regulatory Asset $ 43 $ 18 $ 26 $ 19 $ 126 $ 76 $ 77 $ 62
Three Months
Ended OPEB
Three Months
Ended
June 30,
Six Months
Ended OPEB
Six Months
Ended
June 30, Millions $ 12 $ 8 $ 4 $ 3 $ 25 $ 18 $ 9 $ 6 25 15 20 17 49 32 40 35 4 4 1 1 9 8 2 2 $ 41 $ 27 $ 25 $ 21 $ 83 $ 58 $ 51 $ 43 Pension Benefits OPEB Pension Benefits OPEB Three Months Ended Three Months Ended Nine Months
Ended Nine Months
Ended September 30, September 30, September 30, September 30, 2012 2011 2012 2011 2012 2011 2012 2011 Millions Power $ 14 $ 6 $ 5 $ 3 $ 39 $ 24 $ 14 $ 9 PSE&G 24 9 21 16 73 41 61 51 Other 5 3 — — 14 11 2 2 Total Benefit Costs $ 43 $ 18 $ 26 $ 19 $ 126 $ 76 $ 77 $ 62 $124$124 million and $11$11 million into its pension and postretirement healthcare plans, respectively.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012 and December 31, 2011 are shown below: As of As of June 30, December 31, Millions $ 1,573 $ 1,756 $ 271 $ 315 $ 178 $ 135 $ 115 $ 91 $ 29 $ 20 (4 ) (7 ) (69 ) (92 ) $ 705 $ 812 $ 3,467 $ 3,415 $ 55 $ 52 As of As of September 30,
2012 December 31,
2011 Millions Face Value of Outstanding Guarantees $ 1,514 $ 1,756 Exposure under Current Guarantees $ 214 $ 315 Letters of Credit Margin Posted $ 178 $ 135 Letters of Credit Margin Received $ 109 $ 91 Cash Deposited and Received Counterparty Cash Margin Deposited $ 19 $ 20 Counterparty Cash Margin Received (3 ) (7 ) Net Broker Balance Deposited (Received) 12 (92 ) In the Event Power were to Lose its Investment Grade Rating: Additional Collateral that could be Required $ 610 $ 812 Liquidity Available under PSEG’s and Power’s Credit Facilities to Post Collateral $ 3,429 $ 3,415 Additional Amounts Posted Other Letters of Credit $ 45 $ 52 ourPSEG's accountinga Final RuleRules regarding the definition of a swap dealer in May 2012 but the CFTC has yet to publish the Final Rule regardingand the definition of a swap. In JulyHowever, in September 2012 a federal court vacated the CFTC held a public meetingCFTC's rule on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the definitioneffectiveness of a swap as well as the end-user exemption. Power willthese position limits rules. PSEG is carefully monitormonitoring all of these new rules as they are developedissued to analyze the potential impact on its swap and derivatives transactions, including any potential increase toin its collateral requirements.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)eight-mileeight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile17-mile tidal reach of the lower Passaic River.studyRemedial Investigation and Feasibility Study (RI/FS) would greatly exceed the original estimated cost of $20 million.$20 million. The total cost of the studyRI/FS is now estimated at approximately $105 million. $110 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the studyRI/FS and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 70 members, is presently executing the study.RI/FS. Approximately five percent of the studyRI/FS costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.$1.3$1.3 billion to $3.7 billion.$3.7 billion. The work contemplated by the studyFFS is not subject to the cost sharing agreement discussed above. The EPA is conducting a revised focused feasibility studyFFS which may be released as early as the fourth quarter of 2012.$80 million.$80 million. That removal work is underway. Tierra/Maxus have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.may require a pilot study and will require removal in advance of the completion of the Remedial Investigation and Feasibility StudyRI/FS or the issuance of a revised draft FFS. The CPG members, with the exception of Tierra/Maxus, which are no longer members of the CPG, have agreed to fund the 10.9 pilot study and removal, currently estimated at approximately $30 million.$30 million. PSEG’s share of that effort is approximately three percent.thesethe Passaic River matters.theyit allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaintcomplaints in June 2010. A special master for discovery has been appointed by the court and document production hasNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)$950 million.$950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.$616$610 million and $714$697 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $616$610 million as of JuneSeptember 30, 2012.2012. Of this amount, $90$107 million was recorded in Other Current Liabilities and $526$503 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $616$610 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.$25,000$25,000 to $37,500$37,500 per day for each violation, depending upon when the alleged violation occurred.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)coal firedcoal-fired plant in Pennsylvania,Inn accordance with a court ruling of the United States Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation in the Federal Register on February 16, 2012. These Mercury Air Toxics Standards (MATS) go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the Clean Air Act. OnIn February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 19, 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA’sEPA's implementation of MATS. The Court of Appeals has split the litigation related to these matters into three cases, addressing separately the existing source NESHAP, new source NESHAP and the NSPS. These cases remain pending. The EPA has stayed implementation of the new source NESHAP rule pending its reconsideration until November 2, 2012.Power’sits Hudson and Mercer coal facilities will meet the rule’s requirements. ItPower also believes that it will not be necessary to install any material controls at Power’sits other New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an estimated cost of approximately $5 million.immaterial cost. In December 2011, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal firedcoal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. PSEG’sPower's share of this investment is approximately $147 million.$147 million.coal firedcoal-fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal firedcoal-fired electric generating capacity until December 15, 2012.fuel firedfuel-fired electric generating units. The rule will have a significant impact on Power’s generation fleet, as it imposes NOx emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and four older New Jersey steam electric generating units (approximately 400 MW) by May 30, 2015. Power is currently evaluating its compliance options and is unable to estimate the possible loss or range of loss related to this matter.options.Emission reductions would have been governed by this rule beginning on January 1,In August 2012, for Sulfur Dioxide (SO2) and “annual NOx” and May 1, 2012 for “Ozone season NOx”.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)Certain states would have been required to make additional SO2reductions in 2014. The EPA issued draft technical adjustments to the final CSAPR in October 2011. Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NOx and ozone season NOx allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO2 allowances from the October proposal. The additional increases in NOx allocations are favorable to us, since both Power and New Jersey as a whole were projected to be short on NOx allowances (both ozone season and annual) under the original allocation scenario.On December 30, 2011, the United States Court of Appeals for the D.C. Circuit issued a ruling to stayvacated CSAPR pending judicial review. Until a final decision is reached, the court hasand ordered that the Clean Air Interstate Rule (CAIR) requirements continue temporarily. PSEGremain in effect until an appropriate substitute rule has intervened in this litigation alongbeen promulgated. On October 5, 2012, the EPA filed a request for rehearing with Calpinethe court with the support from several states, cities, environmental groups and Exelon in support of implementing CSAPR. Oral argument occurred on April 13, 2012. A final decision on the merits is expected in the summer of 2012.ourPower's generating stations in Connecticut, New Jersey and New York. The purpose of CAIR is to improve Ozone and Fine Particulate (PM2.5) air quality within states that have not demonstrated achievement of the National Ambient Air Quality Standards (NAAQS). CAIR was implemented through a cap-and-trade program and to date theusPower as the allowances allocated to ourits stations were sufficient. If 2012 operations are similar to those in the past three years, it is expected that the impact to operations from the temporary implementation of CAIR in 2012 will not be significant.PSEG continues to evaluate the impact of this rule on it due to many of the uncertainties that still exist regarding implementation. Power has made major capital investments over the past several years to lower the SO2 and NOx emissions of its fossil plants in the states affected by CSAPR (New Jersey, New York and Pennsylvania). Power does not foresee the need to make significant additional expenditures to its generation fleet to comply with the regulation. As such, Power believes this rule will not have a material impact to its capital investment program or units’ operations.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)OnIn June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. OnIn June 12, 2012, the EPA also posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. In July 2012, PSEG and industry trade associations submitted comments on both NODAs in early July. In July 2012,and the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.$1$1 billion, of which Power’s share would have been approximately $575 million.$575 million. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures. In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies may ultimately impact the EPA’s rulemaking.In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that company’s nuclear generating station located in New Jersey. In December 2010, the NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit was issued by NJDEP on June 1, 2011. The permit was issued as final on December 21, 2011 incorporating the 316(b) requirements as defined in the ACO. In that permit, NJDEP defended its position that closed-cycle cooling was not the best technology available for that facility. Per that permit the facility will cease operations on December 31, 2019. Power cannot predict at this time the final outcome of the NJDEP decision and the impact, if any; such a decision would have on any of Power’s once-through cooled generating stations.Station’sStation's thermal discharge limits and require compliance within five years of approval. Power is reviewing the proposed revisions with NJDEP and DRBC staff. Power cannot at this time determine the final form of the permit that will be presented to the DRBC commissioners for approval and what, if any, impact this permit would have on Mercer’sMercer's operations.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)Nuclear$192$192 million for a steam path retrofit and related upgrades at its co-ownedco-on schedule in October 2011. Unit 2 upgrades are expectedwere completed in October 2012. The balance of work to resultensure efficient operations will be completed in an increase of Power’s share of nominal capacity by approximately 14 MW in 2012.2013 and 2014, respectively. Total expenditures through JuneSeptember 30, 2012 were $127 million.$138 million.$419$419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through JuneSeptember 30, 2012 were $44 million.$56 million.gas firedgas-fired peaking capacity. Final approval was received and construction began in the second quarter of 2011. The project was placed in service in June 2012. Power’s total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power, wereare approximately $149$150 million as of September 30, 2012 (not including the capitalized cost to finance during construction).gas firedgas-fired peaking facilities at its Kearny site. Power’s total capitalized expenditures for these generating units, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power, wereare approximately $244 million.$247 million as of September 30, 2012.$262 million.$249 million. Approximately 3033 MW have been installed as of JuneSeptember 30, 2012.2012. PSE&G’s cumulative investments for these solar units were approximately $215$232 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement, to the extent adequate space on poles is available.$194 million.$194 million. Through JuneSeptember 30, 2012 36, 38 MW representing 2022 projects had been placed into service with an investment of approximately $173 million.$190 million.JanuarySeptember 2012, Energy Holdings acquired a 2515 MW solar project currently under construction in Arizona. CompletionDelaware. Energy Holdings expects to complete construction of this project is expected in 2012.the first quarter of 2013. Energy Holdings issued guarantees of up to $71.5$37 million for payment of obligations related to the construction of the project, all of which were outstanding as of September 30, 2012. The total investment for the project is expected to be approximately $47 million.$23$17 million was outstanding as of JuneSeptember 30, 2012. These guarantees will terminate upon successful completion of the project.2012. The total investment for the project is expected to bewas approximately $75 million.$75 million.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) Auction Year 36-Month Terms Ending May 2012 May 2013 May 2014 May 2015 (A) 2,900 2,800 2,800 2,900 $ per kWh 0.10372 0.09577 0.09430 0.08388 Auction Year 2009 2010 2011 2012 36-Month Terms Ending May 2012 May 2013 May 2014 May 2015 (A) Load (MW) 2,900 2,800 2,800 2,900 $ per kWh 0.10372 0.09577 0.09430 0.08388 (A) Prices set in the 2012 BGS auction became effective on June 1, 2012 when the 2009 BGS auction agreements expired. 20142016 to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012, the total minimum purchase requirements included in these commitments were as follows:
Commitments
through 2016 Millions $ 465 $ 451 $ 146 $ 960 $ 235 Fuel Type Millions Nuclear Fuel Uranium $ 452 Enrichment $ 445 Fabrication $ 145 Natural Gas $ 876 Coal $ 533 $1.2$1.2 billion for all years. PSE&G’s share is $705 million.$705 million. PSE&G has recorded a current liability of $138$89 million as of JuneSeptember 30, 2012.2012. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the Societal Benefits Charge (SBC).The BPU has publicly released these guaranteed capacity prices for two of the three generators. The remaining generator has challenged the release of its guaranteed capacity price in state court. Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellateNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)anddenied all motions for summary judgment. All issues in this case is pending.RPMReliability Pricing Model auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for one of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017 delivery year.derivative assetDerivative Asset or liabilityLiability with an offsetting Regulatory Asset or Liability on PSE&G’s Condensed Consolidated Balance Sheets. See Note 11. Fair Value Measurements for additional information.$175 million.$175 million. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of $245$245 million with respect to these tax years. Accordingly, the settlement resulted in a net $70$70 million decrease in the Income Tax Expense of PSEG.$320$320 million PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately $4$4 million during the second quarter 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately $620$620 million in tax and interest for tax years from 2004 through 2006. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million.$676 million. It is possible that PSEG would have to pay $620$620 million over the next year to the IRS and file claims for refunds for $676$676 million which the IRS would process in the normal course; it could take several years for the IRS to process these claims. In addition to the above, PSEG will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will give rise to a cash tax savings of approximately $100 million.$100 million.sixnine months of 2012:Power$66$66 million of 5.00% Pollution Control Revenue Refunding bond at maturity, and$600$600 million to PSEG.$50$50 million of 5.45% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due February 1, 2032 which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds, with $50 million of weekly-reset variable rate demand bonds due April 1, 2046, which are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds,NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)redeemed and retired at par $23 million of 5.20% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due March 1, 2025,, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,$450$450 million of 3.95% Secured Medium-Term Notes, Series H due May 2042,$96$149 million of Transition Funding’s securitization debt, and$5$5 million of Transition Funding II’s securitization debt.$50$50 million of nonrecourse project debt related to the Dynegy Leases.transaction istransactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.(UNAUDITED)JuneSeptember 30, 2012 and December 31, 2011, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:
June 30,
2012 Millions $ 5 $ 57 $ 23 $ 33 As of As of September 30,
2012 December 31,
2011 Millions Fair Value of Cash Flow Hedges $ — $ 57 Impact on Accumulated Other Comprehensive Income (Loss) (after tax) $ 13 $ 33 $19 million.$10 million. There was no ineffectiveness associated with qualifying hedges as of JuneSeptember 30, 2012.we serve.it serves. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power anticipates that it will not enter into any more trading derivative contracts.ourits expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings.wethey have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.JuneSeptember 30, 2012, PSEG had eight interest rate swaps outstanding totaling $1.1 billion.$1.1 billion. These swaps convert Power’s $250$250 million of 5% Senior Notes due April 2014, Power’s $300$300 million of 5.5% Senior Notes due December 2015, $300$300 million of Power’s $303$303 million of 5.32% Senior Notes due September 2016 and Power’s $250$250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying debt. As of JuneSeptember 30, 2012 and December 31, 2011, the fair value of all the underlying hedges was $66$70 million and $62$62 million, respectively.theirits exposure to the variability of cash flows, primarily related to variable-rate debt instruments. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(2)$(2) million as of JuneSeptember 30, 2012 and December 31, 2011. As of June 30, 2012 Power PSE&G PSEG Cash Flow
Hedges Non
Hedges Non
Hedges Fair Value
Hedges
Related
Contracts
Related
Contracts
(A)
Power
Related
Contracts
Rate
Swaps
Derivatives Millions Derivative Contracts $ 5 $ 480 $ (339 ) $ 146 $ 1 $ 18 $ 165 0 156 (116 ) 40 45 48 133 $ 5 $ 636 $ (455 ) $ 186 $ 46 $ 66 $ 298 $ 0 $ (370 ) $ 282 $ (88 ) $ 0 $ 0 $ (88 ) 0 (108 ) 100 (8 ) (104 ) 0 (112 ) $ 0 $ (478 ) $ 382 $ (96 ) $ (104 ) $ 0 $ (200 ) $ 5 $ 158 $ (73 ) $ 90 $ (58 ) $ 66 $ 98 As of December 31, 2011 Power PSE&G PSEG Cash Flow
Hedges Non
Hedges �� Non
Hedges Fair Value
Hedges
Related
Contracts
Related
Contracts
(A)
Power
Related
Contracts
Rate
Swaps
Derivatives Millions $ 55 $ 532 $ (448 ) $ 139 $ 0 $ 17 $ 156 8 121 (74 ) 55 4 47 106 $ 63 $ 653 $ (522 ) $ 194 $ 4 $ 64 $ 262 $ (5 ) $ (506 ) $ 387 $ (124 ) $ (7 ) $ 0 $ (131 ) (1 ) (76 ) 53 (24 ) 0 (2 ) (26 ) $ (6 ) $ (582 ) $ 440 $ (148 ) $ (7 ) $ (2 ) $ (157 ) $ 57 $ 71 $ (82 ) $ 46 $ (3 ) $ 62 $ 105 NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) As of September 30, 2012 Power PSE&G PSEG Consolidated Balance Sheet Location Millions Derivative Contracts Current Assets $ 3 $ 354 $ (255 ) $ 102 $ 3 $ 18 $ 123 Noncurrent Assets — 81 (59 ) 22 70 52 144 Total Mark-to-Market Derivative Assets $ 3 $ 435 $ (314 ) $ 124 $ 73 $ 70 $ 267 Derivative Contracts Current Liabilities $ (3 ) $ (303 ) $ 255 $ (51 ) $ — $ — $ (51 ) Noncurrent Liabilities — (63 ) 57 (6 ) (106 ) — (112 ) Total Mark-to-Market Derivative (Liabilities) $ (3 ) $ (366 ) $ 312 $ (57 ) $ (106 ) $ — $ (163 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ — $ 69 $ (2 ) $ 67 $ (33 ) $ 70 $ 104 As of December 31, 2011 Power PSE&G PSEG Consolidated Balance Sheet Location Millions Derivative Contracts Current Assets $ 55 $ 532 $ (448 ) $ 139 $ — $ 17 $ 156 Noncurrent Assets 8 121 (74 ) 55 4 47 106 Total Mark-to-Market Derivative Assets $ 63 $ 653 $ (522 ) $ 194 $ 4 $ 64 $ 262 Derivative Contracts Current Liabilities $ (5 ) $ (506 ) $ 387 $ (124 ) $ (7 ) $ — $ (131 ) Noncurrent Liabilities (1 ) (76 ) 53 (24 ) — (2 ) (26 ) Total Mark-to-Market Derivative (Liabilities) $ (6 ) $ (582 ) $ 440 $ (148 ) $ (7 ) $ (2 ) $ (157 ) Total Net Mark-to-Market Derivative Assets (Liabilities) $ 57 $ 71 $ (82 ) $ 46 $ (3 ) $ 62 $ 105 (A) Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. As of June 30, 2012 and December 31, 2011, net cash collateral received of $73 million and $82 million, respectively, was netted against the corresponding net derivative contract positions. Of the $73 million as of June 30, 2012, cash collateral of $(66) million and $(17) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $10 million was netted against current liabilities. Of the $82 million as of December 31, 2011, cash collateral of $(77) million and $(23) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.PSEG’sPower’s derivative instruments contain provisions that require PSEGPower to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PSEG’sPower’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if PSEGPower were to be downgraded or lose its investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. PSEGPower also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on NYMEX and ICE must adhere to comprehensive collateral and margining requirements.$209$130 million and $285$285 million as of JuneSeptember 30, 2012 and December 31, 2011, respectively. As of JuneSeptember 30, 2012 and December 31, 2011 PSEG, Power had the contractual right of offset of $125$88 million and $149$149 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If PSEGPower had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $84$42 million and $136$136 million as of JuneSeptember 30, 2012 and December 31, 2011, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $705$610 million and $812$812 million as of JuneSeptember 30, 2012 and December 31, 2011, respectively, discussed in Note 8. Commitments and Contingent Liabilities.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012 and 2011: Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion) Location
of Pre-Tax Gain
(Loss) Reclassified
from AOCI into
Income Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion) Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion) Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion) Three Months
Ended
June 30, Three Months
Ended
June 30, Three Months
Ended
June 30, 2012 2011 2012 2011 2012 2011 Millions $ (8 ) $ (16 ) Operating Revenues $ 13 $ 26 Operating Revenues $ 1 $ 3 0 (1 ) Energy Costs (5 ) (1 ) 0 0 0 0 Interest Expense (1 ) (1 ) 0 0 $ (8 ) $ (17 ) $ 7 $ 24 $ 1 $ 3 $ (8 ) $ (16 ) Operating Revenues $ 13 $ 26 Operating Revenues $ 1 $ 3 0 (1 ) Energy Costs (5 ) (1 ) 0 0 $ (8 ) $ (17 ) $ 8 $ 25 $ 1 $ 3 (A)Includes amounts for PSEG parent. Three Months Ended Three Months Ended Three Months Ended September 30, September 30, September 30, 2012 2011 2012 2011 2012 2011 Millions PSEG and Power Energy-Related Contracts $ (3 ) $ 21 Operating Revenues $ 15 $ 60 Operating Revenues $ (1 ) $ — Total PSEG and Power $ (3 ) $ 21 $ 15 $ 60 $ (1 ) $ — sixnine months ended JuneSeptember 30, 2012 and 2011: Amount of
Pre-Tax
Gain (Loss)
Recognized in
AOCI on
Derivatives
(Effective
Portion) Location
of Pre-Tax Gain
(Loss) Reclassified
from AOCI into
Income Amount of
Pre-Tax
Gain (Loss)
Reclassified
from AOCI
into Income
(Effective
Portion) Location of
Pre-Tax Gain
(Loss) Recognized in
Income on
Derivatives
(Ineffective Portion) Amount of
Pre-Tax
Gain (Loss)
Recognized in
Income on
Derivatives
(Ineffective
Portion) Six Months
Ended
June 30, Six Months
Ended
June 30, Six Months
Ended
June 30, 2012 2011 2012 2011 2012 2011 Millions PSEG (A) $ 30 $ (3 ) Operating Revenues $ 52 $ 92 Operating Revenues $ 0 $ 1 (4 ) 1 Energy Costs (9 ) 2 0 0 0 0 Interest Expense (1 ) (1 ) 0 0 $ 26 $ (2 ) $ 42 $ 93 $ 0 $ 1 $ 30 $ (3 ) Operating Revenues $ 52 $ 92 Operating Revenues $ 0 $ 1 (4 ) 1 Energy Costs (9 ) 2 0 0 $ 26 $ (2 ) $ 43 $ 94 $ 0 $ 1 Nine Months
Ended Nine Months
Ended Nine Months
Ended September 30, September 30, September 30, 2012 2011 2012 2011 2012 2011 Millions PSEG (A) Energy-Related Contracts $ 27 $ 18 Operating Revenues $ 67 $ 152 Operating Revenues $ (1 ) $ 1 Energy-Related Contracts (4 ) 1 Energy Costs (9 ) 2 — — Interest Rate Swaps — — Interest Expense (1 ) (1 ) — — Total PSEG $ 23 $ 19 $ 57 $ 153 $ (1 ) $ 1 Power Energy-Related Contracts $ 27 $ 18 Operating Revenues $ 67 $ 152 Operating Revenues $ (1 ) $ 1 Energy-Related Contracts (4 ) 1 Energy Costs (9 ) 2 — — Total Power $ 23 $ 19 $ 58 $ 154 $ (1 ) $ 1 (A) Includes amounts for PSEG parent. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED) Millions $ 54 $ 31 34 20 (35 ) (20 ) $ 53 $ 31 (8 ) (5 ) (7 ) (5 ) $ 38 $ 21 Accumulated Other Comprehensive Income Pre-Tax After-Tax Millions Balance as of December 31, 2011 $ 54 $ 31 Gain Recognized in AOCI 26 15 Less: Gain Reclassified into Income (42 ) (25 ) Balance as of June 30, 2012 $ 38 $ 21 Loss Recognized in AOCI (3 ) (2 ) Less: Gain Reclassified into Income (15 ) (8 ) Balance as of September 30, 2012 $ 20 $ 11 sixnine months ended JuneSeptember 30, 2012 and 2011: Location of Pre-Tax
Gain (Loss)
Recognized in Income
on Derivatives Pre-tax Gain (Loss)
Recognized in Income
on Derivatives Three Months Ended
June 30, Six Months Ended
June 30, Millions Operating Revenues $ 40 $ 0 $ 235 $ (42 ) Energy Costs 3 (2 ) (23 ) 1 $ 43 $ (2 ) $ 212 $ (41 ) Derivatives Not Designated as Hedges Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Millions PSEG and Power Energy-Related Contracts Operating Revenues $ (90 ) $ 24 $ 145 $ (18 ) Energy-Related Contracts Energy Costs 6 (11 ) (17 ) (10 ) Total PSEG and Power $ (84 ) $ 13 $ 128 $ (28 ) $5$6 million and $7$6 million for the three month periods and $11$17 million and $13$19 million for the sixnine month periods ended JuneSeptember 30, 2012 and 2011, respectively.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012 and December 31, 2011: Millions Dth 720 0 507 213 MWh 160 0 160 0 MW days 4 0 0 4 MWh 36 0 36 0 US Dollars 1,100 1,100 0 0 Tons 1 0 1 0 Dth 612 0 377 235 MWh 137 0 137 0 MWh 12 0 12 0 US Dollars 1,100 1,100 0 0 Tons 1 0 1 0 Type Notional Total PSEG Power PSE&G Millions As of September 30, 2012 Natural Gas Dth 588 — 385 203 Electricity MWh 179 — 179 — Capacity MW days 4 — — 4 FTRs MWh 28 — 28 — Interest Rate Swaps US Dollars 1,100 1,100 — — Coal Tons 1 — 1 — As of December 31, 2011 Natural Gas Dth 612 — 377 235 Electricity MWh 137 — 137 — FTRs MWh 12 — 12 — Interest Rate Swaps US Dollars 1,100 1,100 — — Coal Tons 1 — 1 — JuneSeptember 30, 2012, 99% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).JuneSeptember 30, 2012.2012. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of Power’s credit risk by credit rating of the counterparties.
Exposure
held as
Collateral
Exposure
Counterparties
>10%
Counterparties
>10% Millions Millions $ 472 $ 88 $ 469 2 $ 265 (A) 2 0 2 0 0 9 0 9 0 0 3 0 3 0 0 $ 486 $ 88 $ 483 2 $ 265 Rating Millions Millions Investment Grade—External Rating $ 311 $ 85 $ 309 2 $ 153 (A) Non-Investment Grade—External Rating 3 — 3 — — Investment Grade—No External Rating 9 — 9 — — Non-Investment Grade—No External Rating — — — — — Total $ 323 $ 85 $ 321 2 $ 153 (A) $196$108 million with PSE&G. The remaining net exposure of $69$45 million is with one nonaffiliated power purchaser which is a regulated investment grade counterparty.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012, Power had 206177 active counterparties.JuneSeptember 30, 2012, these consist primarily of electric swaps whose basis is deemed significant to the fair value measurement, long-term electric capacity contracts and long-term gas supply contracts.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012 and December 31, 2011, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.
Collateral
Netting (E)
Prices for
Identical Assets
(Level 1)
Other
Observable
Inputs
(Level 2)
Unobservable
Inputs PSEG Millions $ 232 $ (83 ) $ 0 $ 247 $ 68 $ 66 $ 0 $ 0 $ 66 $ 0 $ 728 $ 0 $ 728 $ 0 $ 0 $ 306 $ 0 $ 0 $ 306 $ 0 $ 320 $ 0 $ 0 $ 320 $ 0 $ 62 $ 0 $ 0 $ 62 $ 0 $ 16 $ 0 $ 16 $ 0 $ 0 $ 116 $ 0 $ 0 $ 116 $ 0 $ 44 $ 0 $ 0 $ 44 $ 0 $ 3 $ 0 $ 0 $ 3 $ 0 $ (200 ) $ 10 $ 0 $ (106 ) $ (104 ) $ 186 $ (83 ) $ 0 $ 247 $ 22 $ 728 $ 0 $ 728 $ 0 $ 0 $ 306 $ 0 $ 0 $ 306 $ 0 $ 320 $ 0 $ 0 $ 320 $ 0 $ 62 $ 0 $ 0 $ 62 $ 0 $ 3 $ 0 $ 3 $ 0 $ 0 $ 23 $ 0 $ 0 $ 23 $ 0 $ 8 $ 0 $ 0 $ 8 $ 0 $ 1 $ 0 $ 0 $ 1 $ 0 Liabilities: $ (96 ) $ 10 $ 0 $ (106 ) $ 0 Assets: $ 46 $ 0 $ 0 $ 0 $ 46 $ 5 $ 0 $ 5 $ 0 $ 0 $ 38 $ 0 $ 0 $ 38 $ 0 $ 15 $ 0 $ 0 $ 15 $ 0 $ 1 $ 0 $ 0 $ 1 $ 0 Liabilities: $ (104 ) $ 0 $ 0 $ 0 $ (104 )
Collateral
Netting (E)
Prices of
Identical Assets
(Level 1)
Other
Observable
Inputs
(Level 2) Millions $ 198 $ (100 ) $ 0 $ 257 $ 41 $ 64 $ 0 $ 0 $ 64 $ 0 $ 685 $ 0 $ 685 $ 0 $ 0 $ 359 $ 0 $ 0 $ 359 $ 0 $ 281 $ 0 $ 0 $ 281 $ 0 $ 24 $ 0 $ 0 $ 24 $ 0 $ 172 $ 0 $ 19 $ 153 $ 0 $ (155 ) $ 18 $ 0 $ (153 ) $ (20 ) $ (2 ) $ 0 $ 0 $ (2 ) $ 0 $ (50 ) $ 0 $ 0 $ 0 $ (50 ) $ 194 $ (100 ) $ 0 $ 257 $ 37 $ 685 $ 0 $ 685 $ 0 $ 0 $ 359 $ 0 $ 0 $ 359 $ 0 $ 281 $ 0 $ 0 $ 281 $ 0 $ 24 $ 0 $ 0 $ 24 $ 0 $ 33 $ 0 $ 4 $ 29 $ 0 $ (148 ) $ 18 $ 0 $ (153 ) $ (13 ) $ 4 $ 0 $ 0 $ 0 $ 4 $ 57 $ 0 $ 6 $ 51 $ 0 $ (7 ) $ 0 $ 0 $ 0 $ (7 ) Recurring Fair Value Measurements as of September 30, 2012 Description Total Significant Other Observable Inputs (Level 2) Millions PSEG Assets: Derivative Contracts: Energy-Related Contracts (A) $ 197 $ (6 ) $ — $ 116 $ 87 Interest Rate Swaps (B) $ 70 $ — $ — $ 70 $ — NDT Fund (C) Equity Securities $ 749 $ — $ 749 $ — $ — Debt Securities—Govt Obligations $ 288 $ — $ — $ 288 $ — Debt Securities—Other $ 333 $ — $ — $ 333 $ — Other Securities $ 123 $ — $ — $ 123 $ — Rabbi Trust (C) Equity Securities—Mutual Funds $ 17 $ — $ 17 $ — $ — Debt Securities—Govt Obligations $ 116 $ — $ — $ 116 $ — Debt Securities—Other $ 47 $ — $ — $ 47 $ — Other Securities $ 3 $ — $ — $ 3 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (163 ) $ 4 $ — $ (59 ) $ (108 ) Power Assets: Derivative Contracts: Energy-Related Contracts (A) $ 124 $ (6 ) $ — $ 116 $ 14 NDT Fund (C) Equity Securities $ 749 $ — $ 749 $ — $ — Debt Securities—Govt Obligations $ 288 $ — $ — $ 288 $ — Debt Securities—Other $ 333 $ — $ — $ 333 $ — Other Securities $ 123 $ — $ — $ 123 $ — Rabbi Trust (C) Equity Securities—Mutual Funds $ 3 $ — $ 3 $ — $ — Debt Securities—Govt Obligations $ 23 $ — $ — $ 23 $ — Debt Securities—Other $ 9 $ — $ — $ 9 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (57 ) $ 4 $ — $ (59 ) $ (2 ) PSE&G Assets: Derivative Contracts: Energy Related Contracts (A) $ 73 $ — $ — $ — $ 73 Rabbi Trust (C) Equity Securities—Mutual Funds $ 6 $ — $ 6 $ — $ — Debt Securities—Govt Obligations $ 38 $ — $ — $ 38 $ — Debt Securities—Other $ 16 $ — $ — $ 16 $ — Other Securities $ 1 $ — $ — $ 1 $ — Liabilities: Derivative Contracts: Energy Related Contracts (A) $ (106 ) $ — $ — $ — $ (106 ) Recurring Fair Value Measurements as of December 31, 2011 Description Total Millions PSEG Assets: Derivative Contracts: Energy-Related Contracts (A) $ 198 $ (100 ) $ — $ 257 $ 41 Interest Rate Swaps (B) $ 64 $ — $ — $ 64 $ — NDT Fund: (C) Equity Securities $ 685 $ — $ 685 $ — $ — Debt Securities-Govt Obligations $ 359 $ — $ — $ 359 $ — Debt Securities-Other $ 281 $ — $ — $ 281 $ — Other Securities $ 24 $ — $ — $ 24 $ — Rabbi Trust—Mutual Funds (C) $ 172 $ — $ 19 $ 153 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (155 ) $ 18 $ — $ (153 ) $ (20 ) Interest Rate Swaps (B) $ (2 ) $ — $ — $ (2 ) $ — Non-Recourse Debt (D) $ (50 ) $ — $ — $ — $ (50 ) Power Assets: Derivative Contracts: Energy-Related Contracts (A) $ 194 $ (100 ) $ — $ 257 $ 37 NDT Fund: (C) Equity Securities $ 685 $ — $ 685 $ — $ — Debt Securities-Govt Obligations $ 359 $ — $ — $ 359 $ — Debt Securities-Other $ 281 $ — $ — $ 281 $ — Other Securities $ 24 $ — $ — $ 24 $ — Rabbi Trust—Mutual Funds (C) $ 33 $ — $ 4 $ 29 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (148 ) $ 18 $ — $ (153 ) $ (13 ) PSE&G Assets: Derivative Contracts: Energy-Related Contracts (A) $ 4 $ — $ — $ — $ 4 Rabbi Trust—Mutual Funds (C) $ 57 $ — $ 6 $ 51 $ — Liabilities: Derivative Contracts: Energy-Related Contracts (A) $ (7 ) $ — $ — $ — $ (7 ) (A) Level 2—Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. (B) Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. (C) $1$8 million which is part of the NDT Fund as of JuneSeptember 30, 2012.2012. The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).(D) For Non-Recourse Debt, see Fair Value Option below. (E) Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)PSEG Energy Resources & Trade LLC (ER&T)’s tradersPower to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group, and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements. our significant Level 3 valuations, of which the most significant positions are electric swaps for Power and long-term electric capacity contracts and long-term natural gas supply contracts for PSE&G. For Power, in general, electric swaps are valued based on at least two pricing inputs, basis and underlying. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The remaining balance of Power’s Level 3 positions consist primarily of certain long-term electric capacity contracts and certain long-term natural gas supply contracts. Long-term electric capacity contracts are measured at fair value using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. For Power and PSE&G, long-term gas supply contracts are measured at fair value using both actively traded pricing points as well as unobservable inputs such as gas prices beyond observable periods and long-term basis quotes and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity prices and unobservable inputs consisting of forecasts of future long-term electric capacity prices and include adjustments for contingencies, such as litigation risk and plant construction risk. Accordingly, the fair value Quantitative Information About Level 3 Fair Value Measurements
Technique(s)
Unobservable Input Millions Electric Swaps $ 18 $ 1 Discounted cash
flow Power Basis $0 -$10/MWh Various (A) 4 (1 ) $ 22 $ 0 Forward Contracts (B) $ 46 $ (104 ) Discounted cash
flow Long-Term Gas
Basis and Capacity
Prices (B) $ 46 $ (104 ) $ 68 $ (104 ) Quantitative Information About Level 3 Fair Value Measurements Commodity Level 3 Position Fair Value at September 30, 2012 Range Assets (Liabilities) Millions Power Electricity Electric Swaps $ 10 $ (1 ) Discounted cash flow Power Basis $0 -$10/MWh Other Various (A) 4 (1 ) Total Power $ 14 $ (2 ) PSE&G Gas and Capacity Forward Contracts (B) $ 73 $ (106 ) Discounted cash flow Long-Term Gas Basis and Capacity Prices (B) Total PSE&G $ 73 $ (106 ) TOTAL PSEG $ 87 $ (108 ) (A) Includes long-term electric capacity and long-term gas supply positions which are immaterial. (B) $0$0 to $2/$2/MMBTU of natural gas. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100$100 to $400/$400/MW day.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)sixnine months ended JuneSeptember 30, 2012 follows: JuneSeptember 30, 2012
Realized/Unrealized Description
April 1,
Income (A)
Regulatory Assets/
Liabilities (B)
(Sales) (C)
(Settlements)
(D)
In (Out)
(E)
June 30, Millions $ 61 $ 7 $ (90 ) $ 0 $ (14 ) $ 0 $ (36 ) $ (50 ) $ 50 $ 0 $ 0 $ 0 $ 0 $ 0 $ 29 $ 7 $ 0 $ 0 $ (14 ) $ 0 $ 22 $ 32 $ 0 $ (90 ) $ 0 $ 0 $ 0 $ (58 ) Description Balance as of
July 1,
2012 Balance as of
September 30,
2012 Millions PSEG Net Derivative Assets (Liabilities) $ (36 ) $ (1 ) $ 25 $ — $ (9 ) $ — $ (21 ) Power Net Derivative Assets (Liabilities) $ 22 $ (1 ) $ — $ — $ (9 ) $ — $ 12 PSE&G Net Derivative Assets (Liabilities) $ (58 ) $ — $ 25 $ — $ — $ — $ (33 ) SixNine Months Ended JuneSeptember 30, 2012
Realized/Unrealized
January 1,
2012
Income (F)
Regulatory Assets/
Liabilities (B)
(Sales) (C)
(Settlements)
(D)
In (Out)
(E)
June 30,
2012 Millions $ 21 $ 41 $ (55 ) $ 0 $ (43 ) $ 0 $ (36 ) $ (50 ) $ 50 $ 0 $ 0 $ 0 $ 0 $ 0 Power $ 24 $ 41 $ 0 $ 0 $ (43 ) $ 0 $ 22 $ (3 ) $ 0 $ (55 ) $ 0 $ 0 $ 0 $ (58 ) Description Balance as of
January 1,
2012 Balance as of
September 30,
2012 Millions PSEG Net Derivative Assets (Liabilities) $ 21 $ 40 $ (30 ) $ — $ (52 ) $ — $ (21 ) Non-Recourse Debt $ (50 ) $ 50 $ — $ — $ — $ — $ — Power Net Derivative Assets (Liabilities) $ 24 $ 40 $ — $ — $ (52 ) $ — $ 12 PSE&G Net Derivative Assets (Liabilities) $ (3 ) $ — $ (30 ) $ — $ — $ — $ (33 ) NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)sixnine months ended JuneSeptember 30, 2011 follows: JuneSeptember 30, 2011 Total Gains or (Losses)
Realized/Unrealized Description Balance as of
April 1,
2011
Income (A) Included in
Regulatory Assets/
Liabilities (B) Purchases,
(Sales) (C) Issuances
(Settlements)
(D) Transfers
In (Out)
(E) Balance as of
June 30,
2011 Millions $ 2 $ (9 ) $ 6 $ 1 $ (3 ) $ 0 $ (3 ) $ 7 $ (9 ) $ 0 $ 1 $ (3 ) $ 0 $ (4 ) $ (5 ) $ 0 $ 6 $ 0 $ 0 $ 0 $ 1 Description Balance as of
July 1,
2011 Balance as of
September 30,
2011 Millions PSEG Net Derivative Assets (Liabilities) $ (3 ) $ 13 $ (27 ) $ 10 $ 3 $ — $ (4 ) Power Net Derivative Assets (Liabilities) $ (4 ) $ 13 $ — $ 10 $ 3 $ — $ 22 PSE&G Net Derivative Assets (Liabilities) $ 1 $ — $ (27 ) $ — $ — $ — $ (26 ) SixNine Months Ended JuneSeptember 30, 2011 Total Gains or (Losses)
Realized/Unrealized Description Balance as of
January 1,
2011
Income (F) Included in
Regulatory Assets/
Liabilities (B) Purchases,
(Sales) (C) Issuances
(Settlements)
(D) Transfers
In (Out)
(E) Balance as of
June 30,
2011 Millions $ 47 $ (40 ) $ (4 ) $ 19 $ (25 ) $ 0 $ (3 ) $ 8 $ 0 $ 0 $ 0 $ 0 $ (8 ) $ 0 $ 42 $ (40 ) $ 0 $ 19 $ (25 ) $ 0 $ (4 ) $ 8 $ 0 $ 0 $ 0 $ 0 $ (8 ) $ 0 $ 5 $ 0 $ (4 ) $ 0 $ 0 $ 0 $ 1 Description Balance as of
January 1,
2011 Balance as of
September 30,
2011 Millions PSEG Net Derivative Assets (Liabilities) $ 47 $ (27 ) $ (31 ) $ 29 $ (22 ) $ — $ (4 ) NDT Funds $ 8 $ — $ — $ — $ — $ (8 ) $ — Power Net Derivative Assets (Liabilities) $ 42 $ (27 ) $ — $ 29 $ (22 ) $ — $ 22 NDT Funds $ 8 $ — $ — $ — $ — $ (8 ) $ — PSE&G Net Derivative Assets (Liabilities) $ 5 $ — $ (31 ) $ — $ — $ — $ (26 ) (A) $7$(1) million and $(7)$12 million in Operating Income in 2012 and 2011 respectively; $(2), respectively, $1 million in OCI and less than $1$1 million in Income from Discontinued Operations in 2011.2011. Of the $7$(1) million in Operating Income in 2012 $(7), $(10) million is unrealized. Of the $(7)$12 million in Operating Income in 2011 $(24), $31 million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets.(B) Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers. NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)(C) none$10 million in purchases and sales in 2012. Includes $37$0 million in purchases and $(36) million in sales for the three months ended JuneSeptember 30, 2011.2011. Includes $55$65 million in purchases and $(36)$(36) million in sales for the sixnine months months ended JuneSeptember 30, 2011.2011.(D) $0$0 million and $(9)$(5) million in issuances and $(14)$(9) million and $6$8 million in settlements for the three months ended JuneSeptember 30, 2012 and 2011, respectively. Includes $0$0 million and $(20)$(25) million in issuances and $(43)$(52) million and $(5)$3 million in settlements for the sixnine months ended JuneSeptember 30, 2012 and 2011, respectively.(E) JuneSeptember 30, 2012 and 2011 and the sixnine months ended JuneSeptember 30, 2012.2012. During the sixnine months ended JuneSeptember 30, 2011 $8, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. The transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred), as per PSEG’s policy.(F) $41$40 million and $(40)$(28) million in Operating Income in 2012 and 2011 respectively; $(3), respectively, $(2) million in OCI and $3$3 million in Income from Discontinued Operations in 2011.2011. Of the $41$40 million in Operating Income in 2012 $(2), $(12) million is unrealized. Of the $(40)$(28) million in Operating Income in 2011 $(56), $(25) million is unrealized. Energy Holdings’ release from its obligations under the non-recourse debt is included in PSEG’s Operating Income and is offset by the write-off of the related assets.JuneSeptember 30, 2012, PSEG carried $1.7$1.8 billion of net assets that are measured at fair value on a recurring basis, of which $(36)$21 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets.JuneSeptember 30, 2011, PSEG carried $1.7$1.5 billion of net assets that are measured at fair value on a recurring basis, of which $(3)$4 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets.$550$550 million of contractual principal outstanding on the Notes Payable is valued at $50$50 million as of December 31, 2011.2011. Energy Holdings elected this option to eliminate certain complexities in applying the effective interest method of amortization given the uncertain payment streams between the election date and the expected foreclosure date. There were no other debt instruments of this type eligible for the fair value option as of December 31, 2011.2011. The $50$50 million fair value of these Notes Payable is included on PSEG’s Condensed Consolidated Balance Sheet as of December 31, 2011.2011. The fair values of the Notes Payable include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral.Changes to projected capacity factors, capacity and energy prices, fuel costs and other required cash outflows could significantly impact the fair value of the collateral which would increase or decrease the fair value of the Notes. These Notes Payable are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs. As of the June 5, 2012 effective date of the amended settlement agreement, the Notes Payable and related assets were written off.NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)JuneSeptember 30, 2012 and December 31, 2011.
Amount
Value
Amount
Value Millions $ 44 $ 66 $ 39 $ 62 2,686 3,112 2,751 3,158 4,696 5,206 4,270 4,905 799 896 895 1,016 38 41 44 47 45 45 95 95 $ 8,308 $ 9,366 $ 8,094 $ 9,283 September 30, 2012 December 31, 2011 Millions Long-Term Debt: PSEG (Parent) (A) $ 49 $ 70 $ 39 $ 62 Power -Recourse Debt (B) 2,686 3,205 2,751 3,158 PSE&G (B) 4,744 5,631 4,270 4,905 Transition Funding (PSE&G) (B) 746 832 895 1,016 Transition Funding II (PSE&G) (B) 39 41 44 47 Energy Holdings: Project Level, Non-Recourse Debt (C) 45 45 95 95 Total Long-Term Debt $ 8,309 $ 9,824 $ 8,094 $ 9,283 (A) Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power and the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings. (B) The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements). (C) $50$50 million of non-recourse project debt related to Dynegy which is classified as a Level 3 measurement. See “Fair Value Option” above for more details on Dynegy debt. Non-recourse project debt of $45$45 million is valued as equivalent to the amortized cost and is classified as a Level 3 measurement. Consolidated Millions $ 36 $ 0 $ 0 $ 36 0 4 0 4 1 8 2 11 $ 37 $ 12 $ 2 $ 51 $ 48 $ 0 $ 0 $ 48 0 2 0 2 1 2 2 5 $ 49 $ 4 $ 2 $ 55 $ 64 $ 0 $ 0 $ 64 0 8 0 8 3 15 5 23 $ 67 $ 23 $ 5 $ 95 $ 117 $ 0 $ 0 $ 117 0 4 0 4 2 5 3 10 $ 119 $ 9 $ 3 $ 131 Other Income Power PSE&G Other (A) Consolidated Millions Three Months Ended September 30, 2012 NDT Fund Gains, Interest, Dividend and Other Income $ 103 $ — $ — $ 103 Allowance of Funds Used During Construction — 6 — 6 Solar Loan Interest — 5 — 5 Other 1 5 1 7 Total Other Income $ 104 $ 16 $ 1 $ 121 Three Months Ended September 30, 2011 NDT Fund Gains, Interest, Dividend and Other Income $ 36 $ — $ — $ 36 Allowance of Funds Used During Construction — 2 — 2 Solar Loan Interest — 3 — 3 Other 1 2 1 4 Total Other Income $ 37 $ 7 $ 1 $ 45 Nine Months Ended September 30, 2012 NDT Fund Gains, Interest, Dividend and Other Income $ 167 $ — $ — $ 167 Allowance of Funds Used During Construction — 17 — 17 Solar Loan Interest — 13 — 13 Other 4 9 6 19 Total Other Income $ 171 $ 39 $ 6 $ 216 Nine Months Ended September 30, 2011 NDT Fund Gains, Interest, Dividend and Other Income $ 153 $ — $ — $ 153 Allowance of Funds Used During Construction — 4 — 4 Solar Loan Interest — 7 — 7 Other 3 5 4 12 Total Other Income $ 156 $ 16 $ 4 $ 176 Consolidated Millions $ 17 $ 0 $ 0 $ 17 0 1 1 2 $ 17 $ 1 $ 1 $ 19 $ 13 $ 0 $ 0 $ 13 1 0 1 2 $ 14 $ 0 $ 1 $ 15 $ 25 $ 0 $ 0 $ 25 7 2 1 10 $ 32 $ 2 $ 1 $ 35 $ 22 $ 0 $ 0 $ 22 4 1 1 6 $ 26 $ 1 $ 1 $ 28 Other Deductions Power PSE&G Other (A) Consolidated Millions Three Months Ended September 30, 2012 NDT Fund Realized Losses and Expenses $ 20 $ — $ — $ 20 Other — 6 — 6 Total Other Deductions $ 20 $ 6 $ — $ 26 Three Months Ended September 30, 2011 NDT Fund Realized Losses and Expenses $ 10 $ — $ — $ 10 Other — 1 — 1 Total Other Deductions $ 10 $ 1 $ — $ 11 Nine Months Ended September 30, 2012 NDT Fund Realized Losses and Expenses $ 45 $ — $ — $ 45 Other 7 8 1 16 Total Other Deductions $ 52 $ 8 $ 1 $ 61 Nine Months Ended September 30, 2011 NDT Fund Realized Losses and Expenses $ 32 $ — $ — $ 32 Other 5 2 — 7 Total Other Deductions $ 37 $ 2 $ — $ 39 (A) Other primarily consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. sixnine months ended JuneSeptember 30, 2012 and 2011 were as follows:
June 30,
June 30, 40.9% 41.5% 33.7% 41.6% 41.2% 41.1% 40.3% 41.2% 38.4% 41.0% 32.7% 40.7% Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 PSEG 41.0 % 43.1 % 36.3 % 42.0 % Power 42.4 % 40.7 % 41.0 % 41.0 % PSE&G 39.9 % 40.1 % 35.4 % 40.5 % JuneSeptember 30, 2012, the decreaseincrease in PSE&G’sPower's effective tax rate was due primarily to tax benefits from PSE&G’s increased write-offs of uncollectible accounts.sixnine months ended JuneSeptember 30, 2012, the decrease in PSEG’s and PSE&G’s effective tax rate was due primarily to the settlement with the IRS in regard to leveraged leases (See Note 8. Commitments and Contingent Liabilities) and the federal audits for tax years 1997 through 2006 (see below). The decrease in Power’s effective tax rate was due primarily to a reduction in NDT taxes which was partially offset by a reduction in the IRC section 199 deduction for domestic production activities. 2010, enacted December 17, 2010 included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualifiedNOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)will beis eligible for $11$21 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first sixnine months of 2012. Prior to 2012, the law provided an option to claim either a grant or the ITC. For years prior to 2012, the ITC had been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense. As the grant program expired at the end of 2011, ITC for 2012 has been accounted for as an accumulated deferred investment credit on$546$533 million through the first halfnine months of 2012, primarily attributable to PSEG. This decrease was primarily due to the settlement with the IRS, in the amount of $387$387 million, of the leasing issue (See Note 8. Commitments and Contingent Liabilities) and the federal audits for tax years 1997 through 2006 (see below).2006. The remaining unrecognized tax benefit of $159$146 million represents a decrease of prior period positions. As a result, as of JuneSeptember 30, 2012, there is no material increase or decrease in unrecognized tax benefits that is reasonably possible to occur within the next twelve months. The interest and penalties associated with the decrease in the uncertain tax position was $356 million.$356 million. The impact on the accumulated deferred income taxes and regulatory asset associated with the unrecognized tax benefit decrease is $228 million.$216 million. The change in the total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $318 million.$317 million.$140$140 million $80, $80 million and $100$100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments (see Note 8. Commitments and Contingent Liabilities).investments. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits will be applied against tax and interest due pursuant to the closing agreement. Further, on the same date, PSEG signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude ten years of audits for PSEG and the leasing issue for all tax years. The financial statement impacts of these agreements, net of existing financial statement reserves, is a net decrease in tax expense of approximately $70$70 million for PSEG, including $30$30 million and $1$1 million for PSE&G and Power, respectively. Balance as of
December 31, 2011 Other Comprehensive Income (Loss)
Six Months Ended
June 30, 2012 Millions $ 31 $ (10 ) $ 0 $ 0 $ 21 (438 ) 14 0 1 (423 ) 66 22 0 0 88 4 0 (1 ) 1 4 $ (337 ) $ 26 $ (1 ) $ 2 $ (310 ) Balance as of December 31, 2011 Balance as of September 30, 2012 Power PSE&G Other Millions Derivative Contracts $ 31 $ (21 ) $ — $ 1 $ 11 Pension and OPEB Plans (438 ) 21 — 2 (415 ) NDT Funds 66 11 — — 77 Other 4 — — 1 5 Accumulated Other Comprehensive Income (Loss) $ (337 ) $ 11 $ — $ 4 $ (322 ) Balance as of December 31, 2010 Balance as of September 30, 2011 Power PSE&G Other Millions Derivative Contracts $ 111 $ (80 ) $ — $ — $ 31 Pension and OPEB Plans (377 ) 45 — 8 (324 ) NDT Fund 109 (77 ) — — 32 Other 1 — 2 2 5 Accumulated Other Comprehensive Income (Loss) $ (156 ) $ (112 ) $ 2 $ 10 $ (256 ) Other Comprehensive Income (Loss)
Six Months Ended
June 30, 2011 Millions $ 111 $ (57 ) $ 0 $ 0 $ 54 (377 ) 42 0 7 (328 ) 109 (17 ) 0 0 92 1 0 1 1 3 $ (156 ) $ (32 ) $ 1 $ 8 $ (179 ) ourPSEG's stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS: Three Months Ended June 30, Six Months Ended June 30, 2012 2011 2012 2011 Basic Diluted Basic Diluted Basic Diluted Basic Diluted $ 211 $ 211 $ 320 $ 320 $ 704 $ 704 $ 782 $ 782 Discontinued Operations 0 0 3 3 0 0 67 67 $ 211 $ 211 $ 323 $ 323 $ 704 $ 704 $ 849 $ 849 505,903 505,903 505,988 505,988 505,956 505,956 505,984 505,984 0 1,066 0 773 0 1,043 0 961 505,903 506,969 505,988 506,761 505,956 506,999 505,984 506,945 $ 0.42 $ 0.42 $ 0.63 $ 0.63 $ 1.39 $ 1.39 $ 1.55 $ 1.54 0.00 0.00 0.00 0.00 0.00 0.00 0.13 0.13 $ 0.42 $ 0.42 $ 0.63 $ 0.63 $ 1.39 $ 1.39 $ 1.68 $ 1.67 Three Months Ended
June 30, Six Months Ended
June 30, $ 0.3550 $ 0.3425 $ 0.7100 $ 0.6850 $ 180 $ 173 $ 359 $ 347 Three Months Ended September 30, Nine Months Ended September 30, 2012 2011 2012 2011 Basic Diluted Basic Diluted Basic Diluted Basic Diluted Continuing Operations $ 347 $ 347 $ 265 $ 265 $ 1,051 $ 1,051 $ 1,047 $ 1,047 Discontinued Operations — — 29 29 — — 96 96 Net Income $ 347 $ 347 $ 294 $ 294 $ 1,051 $ 1,051 $ 1,143 $ 1,143 Weighted Average Common Shares Outstanding 505,914 505,914 505,909 505,909 505,942 505,942 505,959 505,959 Effect of Stock Based Compensation Awards — 1,197 — 1,090 — 1,095 — 1,004 Total Shares 505,914 507,111 505,909 506,999 505,942 507,037 505,959 506,963 EPS Continuing Operations $ 0.69 $ 0.68 $ 0.52 $ 0.52 $ 2.08 $ 2.07 $ 2.07 $ 2.06 Discontinued Operations — — 0.06 0.06 — — 0.19 0.19 Net Income $ 0.69 $ 0.68 $ 0.58 $ 0.58 $ 2.08 $ 2.07 $ 2.26 $ 2.25 Three Months Ended Nine Months Ended September 30, September 30, Dividend Payments on Common Stock 2012 2011 2012 2011 Per Share $ 0.3550 $ 0.3425 $ 1.0650 $ 1.0275 in Millions $ 180 $ 173 $ 538 $ 520
Holdings Millions $ 985 $ 1,407 $ 14 $ (308 ) $ 2,098 104 101 2 4 211 104 101 2 4 211 104 101 2 4 211 107 435 44 7 593 $ 1,285 $ 1,571 $ 21 $ (408 ) $ 2,469 205 105 5 5 320 3 0 0 0 3 208 105 5 5 323 208 105 5 5 323 168 335 0 2 505 $ 2,546 $ 3,346 $ 34 $ (953 ) $ 4,973 357 298 42 7 704 357 298 42 7 704 357 298 42 7 704 344 870 55 11 1,280 $ 3,252 $ 3,877 $ 41 $ (1,347 ) $ 5,823 502 268 2 10 782 67 0 0 0 67 569 268 2 10 849 569 268 2 10 849 323 674 1 4 1,002 $ 10,749 $ 17,863 $ 1,953 $ (423 ) $ 30,142 $ 41 $ 0 $ 103 $ 0 $ 144 $ 11,087 $ 17,487 $ 1,888 $ (641 ) $ 29,821 $ 31 $ 0 $ 106 $ 0 $ 137 Power PSE&G Other (A) Consolidated Millions Three Months Ended September 30, 2012 Total Operating Revenues $ 1,038 $ 1,683 $ 15 $ (334 ) $ 2,402 Income (Loss) From Continuing Operations 181 155 7 4 347 Net Income (Loss) 181 155 7 4 347 Segment Earnings (Loss) 181 155 7 4 347 Gross Additions to Long-Lived Assets 149 499 30 11 689 Three Months Ended September 30, 2011 Total Operating Revenues $ 1,398 $ 1,841 $ (247 ) $ (372 ) $ 2,620 Income (Loss) From Continuing Operations 273 154 (166 ) 4 265 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax 29 — — — 29 Net Income (Loss) 302 154 (166 ) 4 294 Segment Earnings (Loss) 302 154 (166 ) 4 294 Gross Additions to Long-Lived Assets 207 265 1 4 477 Nine Months Ended September 30, 2012 Total Operating Revenues $ 3,584 $ 5,029 $ 49 $ (1,287 ) $ 7,375 Income (Loss) From Continuing Operations 538 453 49 11 1,051 Net Income (Loss) 538 453 49 11 1,051 Segment Earnings (Loss) 538 453 49 11 1,051 Gross Additions to Long-Lived Assets 493 1,369 85 22 1,969 Nine Months Ended September 30, 2011 Total Operating Revenues $ 4,650 $ 5,718 $ (206 ) $ (1,719 ) $ 8,443 Income (Loss) From Continuing Operations 775 422 (164 ) 14 1,047 Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax 96 — — — 96 Net Income (Loss) 871 422 (164 ) 14 1,143 Segment Earnings (Loss) 871 422 (164 ) 14 1,143 Gross Additions to Long-Lived Assets 530 939 2 8 1,479 As of September 30, 2012 Total Assets $ 10,994 $ 18,115 $ 1,974 $ (377 ) $ 30,706 Investments in Equity Method Subsidiaries $ 41 $ — $ 99 $ — $ 140 As of December 31, 2011 Total Assets $ 11,087 $ 17,487 $ 1,888 $ (641 ) $ 29,821 Investments in Equity Method Subsidiaries $ 31 $ — $ 106 $ — $ 137 (A) Other activities include amounts applicable to PSEG (as parent company), Services and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are priced in accordance with applicable regulations, including affiliate pricing rules, or at cost or, in the case 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 17. Related-Party Transactions. Three Months Ended
June 30, Six Months Ended
June 30, 2012 2011 2012 2011 Millions $ 112 $ 169 $ 563 $ 867 192 229 381 462 $ 304 $ 398 $ 944 $ 1,329 $ (38 ) $ (35 ) $ (72 ) $ (72 ) $ (38 ) $ (35 ) $ (72 ) $ (72 )
June 30, 2012
December 31, 2011 Millions $ 102 $ 247 66 109 (24 ) (26 ) 121 58 0 (7 ) $ 265 $ 381 $ 737 $ 907 $ 17 $ 17 $ (53 ) $ (8 ) Three Months Ended Nine Months Ended September 30, September 30, Related-Party Transactions 2012 2011 2012 2011 Millions Revenue from Affiliates: Billings to PSE&G through BGSS (A) $ 67 $ 91 $ 630 $ 958 Billings to PSE&G through BGS (A) 258 272 639 734 Total Revenue from Affiliates $ 325 $ 363 $ 1,269 $ 1,692 Expense Billings from Affiliates: Administrative Billings from Services (B) $ (38 ) $ (37 ) $ (110 ) $ (109 ) Total Expense Billings from Affiliates $ (38 ) $ (37 ) $ (110 ) $ (109 ) As of As of Related-Party Transactions September 30, 2012 December 31, 2011 Millions Receivables from PSE&G through BGS and BGSS Contracts (A) $ 96 $ 247 Receivables from PSE&G Related to Gas Supply Hedges for BGSS (A) 21 109 Receivable from (Payable to) Services (B) (23 ) (26 ) Tax Receivable from (Payable to) PSEG (C) 7 58 Receivable from (Payable to) PSEG (1 ) (7 ) Accounts Receivable—Affiliated Companies, net $ 100 $ 381 $ 890 $ 907 $ 17 $ 17 $ (66 ) $ (8 ) Three Months Ended
June 30, Six Months Ended
June 30, Millions $ (112 ) $ (169 ) $ (563 ) $ (867 ) (192 ) (229 ) (381 ) (462 ) (57 ) (50 ) (107 ) (101 ) $ (361 ) $ (448 ) $ (1,051 ) $ (1,430 ) NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(UNAUDITED)
June 30, 2012
December 31, 2011 Millions $ (102 ) $ (247 ) (66 ) (109 ) (7 ) (7 ) (47 ) (56 ) 72 131 3 8 1 0 $ (146 ) $ (280 ) $ 33 $ 33 $ (18 ) $ (83 ) Three Months Ended Nine Months Ended September 30, September 30, Related-Party Transactions 2012 2011 2012 2011 Millions Expense Billings from Affiliates: Billings from Power through BGSS (A) $ (67 ) $ (91 ) $ (630 ) $ (958 ) Billings from Power through BGS (A) (258 ) (272 ) (639 ) (734 ) Administrative Billings from Services (B) (58 ) (53 ) (165 ) (154 ) Total Expense Billings from Affiliates $ (383 ) $ (416 ) $ (1,434 ) $ (1,846 ) As of As of Related-Party Transactions September 30, 2012 December 31, 2011 Millions Payable to Power through BGS and BGSS Contracts (A) $ (96 ) $ (247 ) Payable to Power Related to Gas Supply Hedges for BGSS (A) (21 ) (109 ) Payable to Power for SREC Liability (F) (7 ) (7 ) Receivable from (Payable to) Services (B) (47 ) (56 ) Tax Receivable from (Payable to) PSEG (C) 8 131 Receivable from PSEG 6 8 Receivable from Energy Holdings 2 — Accounts Payable—Affiliated Companies, net $ (155 ) $ (280 ) $ 33 $ 33 $ (19 ) $ (83 ) (A) PSE&G has entered into a requirements contract with Power under which Power provided the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 31, 2012 and continues on a year-to-year basis thereafter.requirements. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.(B) Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. (C) PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. (D) Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. (E) Power and PSE&G have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on Power’s and PSE&G’s Condensed Consolidated Balance Sheets. (F) $300$300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU’s 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU subsequently held a legislative hearing process to comply with the Court’s ruling. On May 1, 2012, the BPU affirmed its earlier order and ruled that BGS suppliers could recover verified SREC expenditures above $300 per SREC. The BPU further directed the state’s Electric Distribution Companies (EDCs), including PSE&G, to file by July 1, 2012 a proposed rate recovery mechanism and a method for BGS suppliers to demonstrate that any incremental costs were reasonably and prudently incurred. The BPU has not yet acted on the EDCs’ joint proposal, which was filed on June 26, 2012. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of June 30, 2012 and December 31, 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable—Affiliated Companies as of June 30, 2012 and December 31, 2011. Under current guidance, Power was unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Condensed Consolidated Balance Sheet as of June 30, 2012 and December 31, 2011.
Subsidiaries
Subsidiaries
Adjustments Millions $ 0 $ 1,329 $ 31 $ (375 ) $ 985 2 1,135 28 (376 ) 789 (2 ) 194 3 1 196 116 (1 ) 0 (115 ) 0 11 39 0 (13 ) 37 0 (17 ) 0 0 (17 ) 0 (7 ) 0 0 (7 ) (31 ) (10 ) (4 ) 13 (32 ) 10 (82 ) 0 (1 ) (73 ) $ 104 $ 116 $ (1 ) $ (115 ) $ 104 $ 86 $ 91 $ (1 ) $ (90 ) $ 86 $ 0 $ 1,619 $ 27 $ (361 ) $ 1,285 (1 ) 1,263 28 (360 ) 930 1 356 (1 ) (1 ) 355 220 0 0 (220 ) 0 9 50 0 (10 ) 49 0 (14 ) 0 0 (14 ) 0 (1 ) 0 0 (1 ) (36 ) (11 ) (4 ) 10 (41 ) 14 (160 ) 2 1 (143 ) 0 0 3 0 3 $ 208 $ 220 $ 0 $ (220 ) $ 208 $ 209 $ 185 $ 0 $ (185 ) $ 209 Power Consolidated Millions Three Months Ended September 30, 2012 Operating Revenues $ — $ 1,358 $ 36 $ (356 ) $ 1,038 Operating Expenses (1 ) 1,095 32 (355 ) 771 Operating Income (Loss) 1 263 4 (1 ) 267 Equity Earnings (Losses) of Subsidiaries 191 — — (191 ) — Other Income 11 106 — (13 ) 104 Other Deductions — (20 ) — — (20 ) Other-Than-Temporary Impairments — (2 ) — — (2 ) Interest Expense (29 ) (15 ) (5 ) 14 (35 ) Income Tax Benefit (Expense) 7 (142 ) 1 1 (133 ) Net Income (Loss) $ 181 $ 190 $ — $ (190 ) $ 181 Comprehensive Income (Loss) $ 166 $ 168 $ — $ (168 ) $ 166 Three Months Ended September 30, 2011 Operating Revenues $ — $ 1,725 $ 29 $ (356 ) $ 1,398 Operating Expenses 1 1,241 29 (356 ) 915 Operating Income (Loss) (1 ) 484 — — 483 Equity Earnings (Losses) of Subsidiaries 315 29 — (344 ) — Other Income 9 38 — (10 ) 37 Other Deductions (1 ) (8 ) — (1 ) (10 ) Other-Than-Temporary Impairments 1 (9 ) — — (8 ) Interest Expense (33 ) (17 ) (3 ) 11 (42 ) Income Tax Benefit (Expense) 12 (200 ) 1 — (187 ) Income (Loss) on Discontinued Operations, net of tax — — 29 — 29 Net Income (Loss) $ 302 $ 317 $ 27 $ (344 ) $ 302 Comprehensive Income (Loss) $ 222 $ 233 $ 27 $ (260 ) $ 222
Subsidiaries
Subsidiaries
Adjustments Millions $ 0 $ 3,202 $ 57 $ (713 ) $ 2,546 0 2,568 55 (714 ) 1,909 0 634 2 1 637 376 (4 ) 0 (372 ) 0 24 70 0 (27 ) 67 (7 ) (25 ) 0 0 (32 ) 0 (12 ) 0 0 (12 ) (60 ) (20 ) (8 ) 26 (62 ) 24 (267 ) 2 0 (241 ) $ 357 $ 376 $ (4 ) $ (372 ) $ 357 $ 383 $ 388 $ (4 ) $ (384 ) $ 383 $ 301 $ 902 $ 3 $ (354 ) $ 852 $ 365 $ (601 ) $ (23 ) $ 70 $ (189 ) $ (666 ) $ (310 ) $ 19 $ 284 $ (673 ) $ 0 $ 3,897 $ 77 $ (722 ) $ 3,252 1 3,037 80 (722 ) 2,396 (1 ) 860 (3 ) 0 856 602 59 0 (661 ) 0 19 121 0 (21 ) 119 (3 ) (23 ) 0 0 (26 ) (1 ) (2 ) 0 0 (3 ) (82 ) (21 ) (10 ) 21 (92 ) 35 (392 ) 5 0 (352 ) 0 0 67 0 67 $ 569 $ 602 $ 59 $ (661 ) $ 569 $ 537 $ 528 $ 59 $ (587 ) $ 537 $ 367 $ 1,400 $ (148 ) $ (473 ) $ 1,146 $ 589 $ (674 ) $ 317 $ (413 ) $ (181 ) $ (956 ) $ (725 ) $ (168 ) $ 887 $ (962 ) Power Consolidated Millions Nine Months Ended September 30, 2012 Operating Revenues $ — $ 4,560 $ 93 $ (1,069 ) $ 3,584 Operating Expenses (1 ) 3,663 87 (1,069 ) 2,680 Operating Income (Loss) 1 897 6 — 904 Equity Earnings (Losses) of Subsidiaries 567 (4 ) — (563 ) — Other Income 35 176 — (40 ) 171 Other Deductions (7 ) (45 ) — — (52 ) Other-Than-Temporary Impairments — (14 ) — — (14 ) Interest Expense (89 ) (35 ) (13 ) 40 (97 ) Income Tax Benefit (Expense) 31 (409 ) 3 1 (374 ) Net Income (Loss) $ 538 $ 566 $ (4 ) $ (562 ) $ 538 Comprehensive Income (Loss) $ 549 $ 556 $ (4 ) $ (552 ) $ 549 Nine Months Ended September 30, 2012 Net Cash Provided By (Used In) Operating Activities $ 409 $ 1,259 $ (3 ) $ (493 ) $ 1,172 Net Cash Provided By (Used In) Investing Activities $ 257 $ (897 ) $ (24 ) $ 158 $ (506 ) Net Cash Provided By (Used In) Financing Activities $ (666 ) $ (368 ) $ 26 $ 335 $ (673 ) Nine Months Ended September 30, 2011 — Operating Revenues $ — $ 5,622 $ 106 $ (1,078 ) $ 4,650 Operating Expenses 2 4,278 109 (1,078 ) 3,311 Operating Income (Loss) (2 ) 1,344 (3 ) — 1,339 Equity Earnings (Losses) of Subsidiaries 917 88 — (1,005 ) — Other Income 28 159 — (31 ) 156 Other Deductions (4 ) (32 ) — (1 ) (37 ) Other-Than-Temporary Impairments — (10 ) — — (10 ) Interest Expense (115 ) (38 ) (13 ) 32 (134 ) Income Tax Benefit (Expense) 47 (592 ) 6 — (539 ) Income (Loss) on Discontinued Operations, net of tax — — 96 — 96 Net Income (Loss) $ 871 $ 919 $ 86 $ (1,005 ) $ 871 Comprehensive Income (Loss) $ 759 $ 761 $ 86 $ (847 ) $ 759 Nine Months Ended September 30, 2011 Net Cash Provided By (Used In) Operating Activities $ 370 $ 2,029 $ (319 ) $ (593 ) $ 1,487 Net Cash Provided By (Used In) Investing Activities $ 86 $ (935 ) $ 652 $ (821 ) $ (1,018 ) Net Cash Provided By (Used In) Financing Activities $ (456 ) $ (1,091 ) $ (332 ) $ 1,413 $ (466 ) Power Consolidated Millions As of September 30, 2012 Current Assets $ 4,182 $ 7,926 $ 919 $ (10,646 ) $ 2,381 Property, Plant and Equipment, net 88 5,835 948 1 6,872 Investment in Subsidiaries 4,193 740 — (4,933 ) — Noncurrent Assets 175 1,631 62 (127 ) 1,741 Total Assets $ 8,638 $ 16,132 $ 1,929 $ (15,705 ) $ 10,994 Current Liabilities $ 403 $ 10,183 $ 984 $ (10,643 ) $ 927 Noncurrent Liabilities 456 1,754 204 (126 ) 2,288 Long-Term Debt 2,386 — — — 2,386 Member’s Equity 5,393 4,195 741 (4,936 ) 5,393 Total Liabilities and Member’s Equity $ 8,638 $ 16,132 $ 1,929 $ (15,705 ) $ 10,994 As of December 31, 2011 Current Assets $ 4,311 $ 7,248 $ 951 $ (9,823 ) $ 2,687 Property, Plant and Equipment, net 66 5,715 950 — 6,731 Investment in Subsidiaries 4,185 804 — (4,989 ) — Noncurrent Assets 179 1,557 51 (118 ) 1,669 Total Assets $ 8,741 $ 15,324 $ 1,952 $ (14,930 ) $ 11,087 Current Liabilities $ 172 $ 9,549 $ 1,003 $ (9,822 ) $ 902 Noncurrent Liabilities 440 1,589 145 (118 ) 2,056 Long-Term Debt 2,685 — — — 2,685 Member’s Equity 5,444 4,186 804 (4,990 ) 5,444 Total Liabilities and Member’s Equity $ 8,741 $ 15,324 $ 1,952 $ (14,930 ) $ 11,087 (UNAUDITED)1.7
Subsidiaries
Subsidiaries
Adjustments Millions $ 4,071 $ 7,718 $ 906 $ (10,401 ) $ 2,294 71 5,765 957 0 6,793 4,124 740 0 (4,864 ) 0 189 1,534 62 (123 ) 1,662 $ 8,455 $ 15,757 $ 1,925 $ (15,388 ) $ 10,749 $ 385 $ 9,896 $ 1,011 $ (10,402 ) $ 890 458 1,737 173 (122 ) 2,246 2,386 0 0 0 2,386 5,226 4,124 741 (4,864 ) 5,227 $ 8,455 $ 15,757 $ 1,925 $ (15,388 ) $ 10,749 $ 4,311 $ 7,248 $ 951 $ (9,823 ) $ 2,687 66 5,715 950 0 6,731 4,185 804 0 (4,989 ) 0 179 1,557 51 (118 ) 1,669 $ 8,741 $ 15,324 $ 1,952 $ (14,930 ) $ 11,087 $ 172 $ 9,549 $ 1,003 $ (9,822 ) $ 902 440 1,589 145 (118 ) 2,056 2,685 0 0 0 2,685 5,444 4,186 804 (4,990 ) 5,444 $ 8,741 $ 15,324 $ 1,952 $ (14,930 ) $ 11,087 ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) ReportReports on Form 10-Q for the quarterquarters ended March 31, 2012 and June 30, 2012.halfnine months of 2012, our results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. Our pricing also continues to be affected by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales. While the average BGS rates have been declining based on recent market prices, customers may still see an incentive to switch to third party suppliers. The result of such a switch may affect the price we receive on our sales, shifting from BGS rates that were established in auctions that had taken place over the past three years, to prices offered by third party suppliers which may be more representative of recent market pricing.arewere higher transmission revenues as a result of our 2012 Annual Formula Rate Update with the Federal Energy Regulatory Commission (FERC), which providesprovided for approximately $94 million in increased annual transmission revenues effective January 1, 2012.most recentReliability Pricing Model capacity auction in May 2012, for the 2015-2016 period, Power cleared approximately 9,000 MW of its generating capacity at an average price of $167 per MW-day.halfnine months of 2012, but the decline in gas revenues was significantly mitigated by the favorable impact of a $51$57 million increase due to recovery of deficiency revenues through the Weather Normalization Charge (WNC). PSE&G’s WNC is a rate mechanism that allows us to increase our rates, subject to an earnings test, to compensate for lower revenues we receive from customers as a result of warmer-than-normal winters and to decrease our rates to make up for higher revenues we receive as a result of colder-than-normal winters.recontractre-contract our open supply positions, andOn April 12, 2012, the Maryland Public Utility Commission (PUC) issued an order requiring three of the four Maryland utility companies to enter into contracts with CPV Shore, LLC (CPV) to construct a new 661 MW natural gas-fired, combined cycle station in Maryland with an in-service date of June 2015. CPV cleared the May 2012 Reliability Pricing Model (RPM) auction. These developments in Maryland may stimulate construction of subsidized generation and impact energy and capacity prices in PJM. Power has joined other generators in challenging the constitutionality of this order in federal court. In addition, the Maryland electric distribution companies have appealed the PUC’s order in state court. Both proceedings are pending.Maryland’sactions by the Maryland Public Service Commission's Request for Proposal or similar activity in other states to subsidize new generation may artificially depress energy and capacity prices in the competitive wholesale market and have the potential to harm competitive markets and adversely impact our generation business, on both a short-term and long-term basis.Final Ruleit will change how the MOPR will be applied in the RPM auction in May 2013 and should enhance the competitiveness of the auction. We cannot predict the outcome of this matter.this Order 1000 in federal court. Other companies and state commissions have filed appeals as well. PJM is currently conductinghas concluded a stakeholder process to develop implementing details regarding Order 1000. An expected outcome of this process is the construction of more transmission and the opening up of transmission construction and ownership to third-partythird party developers and to incumbents seeking to build outside of their service territories. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 in the various regions, including within our service territory, may expose us to competition for construction of transmission, additional regulatory considerations and potential delay with respect to future transmission projects.project.project discussed below. However, the FERC also stated in its order that other cost allocation methodologies could be just and reasonable and this may lead to the adoption of a different cost allocation methodology for transmission in PJM in the future.SECSecurities and Exchange Commission and the Commodity Futures Trading Commission (CFTC) continued efforts to enact stricter regulation over swaps and derivatives. The CFTC has issued Notices of Proposed Rulemakings on many of the key issues and is in the process of issuing Final Rules on these issues. In May 2012, the CFTC issued a Final RuleRules regarding the definition of a swap dealer and in July 2012, the CFTC voted to issue a Final Rule regarding the definition of a swap, but thisswap. However, in September 2012, a federal court vacated the CFTC's rule has yet to be published.on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the effectiveness of these position limits rules. We are carefully monitoring all of these new rules as they are issued to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.sixnine months of 2012. Our92.7%92.5% and our combined cycle units have continued to improve their forced outage rates. Overall, generation volumes for the first halfnine months of 2012 were 25.8 TWh,40.8 terawatt hours, approximately 5%2.4% lower than in 2011 due primarily to reduced demandsdemand due to milder weather in 2012.sixnine months of 2012, we made approximately $1.3$2.0 billion in capital expenditures, paid dividends of $359$538 million and made our entire planned pension and other postretirement employee benefit contributions for the year 2012 of $135 million.JuneSeptember 30, 2012, our total credit capacity was $4.3 billion and we had over $750$780 million of cash on hand.We are continuing to pursue obtainingOn October 1, 2012, the necessary regulatory approvalsNational Park Service (NPS) issued a final Environmental Impact Statement (EIS), affirming our and PPL Electric Utilities Corporation's choice of route for the Susquehanna-Roseland transmission line project including approvalthat follows the existing right-of-way. On October 15, 2012, several environmental groups filed a complaint in federal court challenging the NPS' issuance of the final EIS, seeking to set aside the EIS and to enjoin implementation of the NPS' decision. If this request for injunctive relief is granted, the construction schedule for the project could be impacted. We have also recently obtained environmental permits for the project from the National Park Service (NPS), which has resultedNew Jersey Department of Environmental Protection (NJDEP). We have begun construction in a delay to the project implementation date. In March 2012, the NPS identified a “preferred alternative” for the final form of its Draft Environmental Impact Statement (EIS), under which the project would follow the route of the existing transmission line. This route was the one approved by state regulators including the BPU. The final EIS is expected to be issued in October 2012.those areas where necessary permits have been obtained. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. The cost of construction is up toJuneSeptember 30, 2012, total capital expenditures were $217$261 million.$177$192 million in loans for 721812 projects as of JuneSeptember 30, 2012, representing 5561 MW to date. Under our Solar 4 All program, we have made total programcapital expenditures of approximately $401$422 million as of JuneSeptember 30, 2012.2012. Approximately 3033 MW of solar panels have been installed on distribution poles and another 3638 MW representing 2022 projects have been placed into service. Additional projects are in various stages of development. Our total anticipated expenditures to develop all approved 80 MW are approximately $456$443 million. The BPU has concluded a generic stakeholder proceeding to examine whether utility rate-based solar programs should be modified, expanded or terminated in the future, and has determined that utility rate-based solar programs should be continued under defined scope and size parameters.PSE&Gwe filed for an extension of itsour Solar 4 All program. In this filing, PSE&G iswe are seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, PSE&G proposeswe propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets.Also, consistent withmarkets which will offset the BPU’s generic proceeding on solar, PSE&Gcost of the program.PSE&G iswe are seeking BPU approval to provide financing support for the installation of 9798 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, projects are built and loans are closed.JuneSeptember 30, 2012, total capital expenditures since inception of this program were $177$224 million.JuneSeptember 30, 2012, total capital expenditures since inception of these projects were $147$152 million for Energy Efficiency Economic Stimulus (EEE), $2$4 million for EEE Extension and $43$44 million for Carbon Abatement and $23$26 million for Demand Response.a steam path retrofit andan extended power uprate at Peach Bottom and weBottom. We completed construction of new gas-fired peaking units at Kearny and in Connecticut and primary installation of the Peach Bottom steam path retrofit (see Note 8. Commitments and Contingent Liabilities and Part II. Item 5. Other Information for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility.Nuclear Regulatory Commission (NRC)NRC acceptance review is complete and agency evaluation is underway. There were no petitions filed for permission to intervene. The current NRC schedule would likely result insupports issuance of the Early Site Permit in 2014.JanuarySeptember 2012, we acquired an additional 25a 15 MW solar project at Energy Holdings, currently under construction in Arizona. CompletionDelaware. We expect to complete construction of this project in the first quarter of 2013. Effective with commencement of commercial operation, the project has a 20-year power purchase agreement for energy and the majority of renewable energy credits with a wholesale electric utility servicing municipal electric distribution utilities in Delaware. We issued guarantees of up to $37 million for payment of obligations related to the construction of the project. The total investment for the project is expected to be approximately $47 million.2012.Arizona. All of the energy, capacity and environmental attributes generated by the project in the first 20 years are expectedwere sold to be soldan Arizona electric utility under a long-term power purchase agreement. We had issued guarantees of up to $72 million for payment of obligations related to the construction of the project, of which $17 million was outstanding as ofwill bewas approximately $75 million.$75 million.sixnine months ended JuneSeptember 30, 2012 and 2011 are presented below: Three Months Ended Six Months Ended June 30, June 30, Millions $ 104 $ 205 $ 357 $ 502 PSE&G 101 105 298 268 2 5 42 2 Other (A) 4 5 7 10 211 320 704 782 Income (Loss) from Discontinued Operations (B) 0 3 0 67 $ 211 $ 323 $ 704 $ 849 Three Months Ended Six Months Ended June 30, June 30, $ 0.42 $ 0.63 $ 1.39 $ 1.54 Income (Loss) from Discontinued Operations (B) 0.00 0.00 0.00 0.13 $ 0.42 $ 0.63 $ 1.39 $ 1.67 Three Months Ended Nine Months Ended September 30, September 30, Earnings (Losses) 2012 2011 2012 2011 Millions Power $ 181 $ 273 $ 538 $ 775 PSE&G 155 154 453 422 Energy Holdings 7 (166 ) 49 (164 ) Other (A) 4 4 11 14 PSEG Income from Continuing Operations 347 265 1,051 1,047 Income (Loss) from Discontinued Operations (B) — 29 — 96 PSEG Net Income $ 347 $ 294 $ 1,051 $ 1,143 Three Months Ended Nine Months Ended September 30, September 30, Earnings Per Share (Diluted) 2012 2011 2012 2011 PSEG Income from Continuing Operations $ 0.68 $ 0.52 $ 2.07 $ 2.06 Income (Loss) from Discontinued Operations (B) — 0.06 — 0.19 PSEG Net Income $ 0.68 $ 0.58 $ 2.07 $ 2.25 (A) Other primarily includes parent company interest and financing costs, donations and certain administrative and general expenses. (B) See Note 4. Discontinued Operations and Dispositions. six month-over-sixnine month-over-nine month variances in our Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below: Three Months Ended Six Months Ended June 30, June 30, Millions, after tax $ 4 $ 15 $ 9 $ 42 Non-Trading MTM Gains (Losses) $ (10 ) $ 4 $ 42 $ 8 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 2011 Millions, after tax NDT Fund Income (Expense) $ 40 $ 7 $ 49 $ 49 Non-Trading MTM Gains (Losses) $ (76 ) $ 8 $ (34 ) $ 16 $109$82 millionincrease and $78$4 million decreasesincrease in Income from Continuing Operations for the three months and sixnine months ended JuneSeptember 30, 2012, respectively, were driven primarily by:prices and/or lower sales volumes in theon generation sold into various power pools, andweather, partially offset by the WNC.decreaseincrease for the sixnine months ended JuneSeptember 30, 2012 was partially offset by increased earnings from transmission and renewable investments at PSE&G and also includes lower tax expense due to the settlement of 10 years of IRS audits. Three Months Ended
June 30, Increase/
(Decrease) Six Months Ended
June 30, Increase/
(Decrease) Millions Millions % Millions Millions % $ 2,098 $ 2,469 $ (371 ) (15 ) $ 4,973 $ 5,823 $ (850 ) (15 ) Energy Costs 761 1,010 (249 ) (25 ) 1,940 2,573 (633 ) (25 ) 629 575 54 9 1,257 1,226 31 3 255 235 20 9 511 476 35 7 20 28 (8 ) (29 ) 49 71 (22 ) (31 ) 2 4 (2 ) (50 ) 2 7 (5 ) (71 ) 32 40 (8 ) (20 ) 60 103 (43 ) (42 ) 7 1 6 N/A 12 5 7 N/A 103 117 (14 ) (12 ) 204 244 (40 ) (16 ) Income Tax Expense 146 227 (81 ) (36 ) 358 556 (198 ) (36 ) 0 3 (3 ) N/A 0 67 (67 ) N/A Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 vs. 2011 2012 2011 2012 vs. 2011 Millions Millions % Millions Millions % Operating Revenues $ 2,402 $ 2,620 $ (218 ) (8 ) $ 7,375 $ 8,443 $ (1,068 ) (13 ) Energy Costs 879 1,167 (288 ) (25 ) 2,819 3,740 (921 ) (25 ) Operation and Maintenance 619 603 16 3 1,876 1,829 47 3 Depreciation and Amortization 286 263 23 9 797 739 58 8 Taxes Other than Income Taxes 24 31 (7 ) (23 ) 73 102 (29 ) (28 ) Income from Equity Method Investments 7 1 6 N/A 9 8 1 13 Other Income and (Deductions) 95 34 61 N/A 155 137 18 13 Other-Than-Temporary Impairments 2 8 (6 ) (75 ) 14 13 1 8 Interest Expense 106 117 (11 ) (9 ) 310 361 (51 ) (14 ) Income Tax Expense 241 201 40 20 599 757 (158 ) (21 ) Income (Loss) from Discontinued Operations — 29 (29 ) (100 ) — 96 (96 ) (100 ) Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Millions Income from Continuing Operations $ 181 $ 273 $ (92 ) $ 538 $ 775 $ (237 ) Income (Loss) from Discontinued Operations, net of tax — 29 (29 ) — 96 (96 ) Net Income $ 181 $ 302 $ (121 ) $ 538 $ 871 $ (333 ) Power Three Months Ended
June 30, Increase/
(Decrease) Six Months Ended
June 30, Increase/
(Decrease) Millions $ 104 $ 205 $ (101 ) $ 357 $ 502 $ (145 ) 0 3 (3 ) 0 67 (67 ) $ 104 $ 208 $ (104 ) $ 357 $ 569 $ (212 ) sixnine months ended JuneSeptember 30, 2012, the primary reasons for the $101$92 milliondecrease and $145$237 million decreasesdecrease in Income from Continuing Operations wereserve, as a result of warmer winter weather in 2012,higher operation and maintenance costs in 2012 at our nuclear plants, andlower net realized gains on the NDT Fund.maturity of Senior Notes in December 2011.The decrease for the three months ended June 30, 2012 was also attributable to unfavorable MTM activity. The decrease for the six months ended June 30, 2012 was partially offset by favorable MTM activity and lower interest expense due to the early redemption of Senior Notes in April 2011 and December 2011. Three Months Ended
June 30, Increase/
(Decrease) Six Months Ended
June 30, Increase/
(Decrease) Millions Millions % Millions Millions % $ 985 $ 1,285 $ (300 ) (23 ) $ 2,546 $ 3,252 $ (706 ) (22 ) 447 603 (156 ) (26 ) 1,269 1,738 (469 ) (27 ) 284 271 13 5 525 548 (23 ) (4 ) 58 56 2 4 115 110 5 5 20 35 (15 ) (43 ) 35 93 (58 ) (62 ) 7 1 6 N/A 12 3 9 N/A 32 41 (9 ) (22 ) 62 92 (30 ) (33 ) 73 143 (70 ) (49 ) 241 352 (111 ) (32 ) 0 3 (3 ) N/A 0 67 (67 ) N/A Three Months Ended Nine Months Ended September 30, September 30, 2012 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Millions Millions % Millions Millions % Operating Revenues $ 1,038 $ 1,398 $ (360 ) (26 ) $ 3,584 $ 4,650 $ (1,066 ) (23 ) Energy Costs 456 597 (141 ) (24 ) 1,725 2,335 (610 ) (26 ) Operation and Maintenance 255 262 (7 ) (3 ) 780 810 (30 ) (4 ) Depreciation and Amortization 60 56 4 7 175 166 9 5 Other Income (Deductions) 84 27 57 N/A 119 119 — — Other-Than-Temporary Impairments 2 8 (6 ) (75 ) 14 10 4 40 Interest Expense 35 42 (7 ) (17 ) 97 134 (37 ) (28 ) Income Tax Expense 133 187 (54 ) (29 ) 374 539 (165 ) (31 ) Income (Loss) from Discontinued Operations — 29 (29 ) (100 ) — 96 (96 ) (100 ) ended JuneEndedSeptember 30, 2012 as compared As Compared to 2011 $300$360 million due to $244$323 million due primarily to$113$226 million due primarily to lower average realized and unrealized prices for our generation sold into the PJM and New York power pools partially offset by higherand MTM losses due in part to adverse changes in unrealized prices on generation sales in New England,$75$78 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts primarily as a result of customer migration, and re-contracting,$42$47 million due primarily to lower volumes on wholesale load contracts in both the PJM and New England regions, anddecreasenet increase of $25$28 million due to higher capacity payments received in the PJM power pool resulting from higher auction prices partly offset by lower operating reserve revenue in 2012 resulting from lower demand and lower market prices, lower ancillary revenues and lower RMR revenues in the PJM region. $55$37 million due primarily to$51$29 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to milder winter weather during the secondthird quarter of 2012, and$4$8 million due primarily to lower average gas prices on higher volumes of sales volumes to third party customers.Trading Revenues were immaterial in 2012 due to the discontinuation of trading activities in the second quarter of 2011. $156$141 million due to•Generation costsdecreased by $109 due primarily to $83 million of lower fuel costs, primarily due to lower fossil fuel costs, reflecting the utilization of lower volumes of coal and lower natural gas prices, partially offset by the utilization of higher volumes of natural gas. The decrease was also attributable to $36 million in lower energy purchases in the PJM and New England regions as a result of lower load contract demand in 2012, and $8 million of lower CO2 emission charges. These decreases were partially offset by an increase of $18 million in congestion costs in 2012 in the PJM region.•Gas costsdecreased $47 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due to milder winter weather during the second quarter of 2012.Operation and Maintenance increased $13 million due primarily to higher refueling$55 million of lower fuel costs, in 2012 for our 100%-owned Hope Creek nuclear facility as compared to our portionreflecting the utilization of refueling costs in 2011 for our 57%-owned Salem 2 nuclear unit. This increase waslower volumes of coal and oil and lower average natural gas prices, partially offset by the utilization of higher volumes of natural gas and higher nuclear fuel prices. The decrease was also attributable to $38 million in lower plannedenergy purchases in the PJM region as a result of lower load contract volumes in 2012, and $12 million of lower emission charges due to lower coal generation in the PJM and New England regions.coal-fired Mercercoal/gas-fired Hudson facility and gas-fired Linden and Bergen plants in New Jersey and our co-owned coal-fired KeystoneConemaugh plant in Pennsylvania. experienced no material change.decreaseincrease of $15$57 million was due primarily to lowerhigher net realized gains onfrom the restructuring of our NDT Fund.Fund in September 2012.increased $6decreased$6 million due primarily to lower impairments on the NDT Fund in 2012. $9$7 million due to a decrease of $11 million due primarily tofrom the early redemption of $600 million of 6.95% Senior Notes in December 2011, partially offset by an increase of $4 million due to the issuance of $250 million of 2.75% Senior Notes and $250 million of 4.15% Senior Notes in September 2011. $70$54 million in 2012 due primarily to lower pre-tax income.atand an after-tax gain of $54 million. In July 2011, we completed the sale of the second plant for proceeds of $335 million atand an after-tax gain of $25 million. The sale of the second plant was reflected in Power’s Condensed Consolidated Financial Statements for the third quarter of 2011. The results of operations for both plantsthe second plant through sale date, including the after-tax gain on its sale, are included for the secondthird quarter of 2011 in this category. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information.SixNine Months ended JuneEndedSeptember 30, 2012 as compared As Compared to 2011 $706$1,066 million due to $429$752 million due primarily to$144$355 million due primarily to lower average realized and unrealized prices for our generation sold into the PJM and New York power pools$137$215 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts primarily as a result of warmer winter weather in 2012 as well as customer migration,$69$132 million due to lower volumes on wholesale load contracts in the PJM and New England regions, and$64$50 million due to lower operating reserve revenue in 2012 resulting from lower demand and lower average market prices, lower ancillary revenues, lower Reliability Must Run revenues and lower RMR revenuescapacity payments received in the PJM region. $310$347 million due primarily to net decrease of $272$319 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to warmer average temperatures during the first quarter of 2012, and$38$28 million due primarily to lower average gas prices partially offset by higher sales volumes to third party customers. $33$33 million in 2012 due to the discontinuation of trading activities in the second quarter of 2011. As a result, the increase is due primarily to the absence of losses on electric energy supply contracts recognized in 2011. $469$610 million due to•Gas costsdecreased $272 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due primarily to warmer average temperatures during the first quarter of 2012.•Generation costsdecreased by $197 million due primarily to $184 and oil and lower natural gas prices, partially offset by the utilization of higher volumes of nuclear fuel at higher prices in 2012. The decrease was also attributable to $68 million in lower energy purchases in the PJM region as a result of lower load contract demand in 2012, and $13 million of lower CO2emission charges. These decreases were partially offset by an increase of $68 million in congestion costs.Operation and Maintenance decreased $23oil and lower average natural gas prices, partially offset by the utilization of higher volumes of natural gas and higher nuclear fuel prices in 2012. The decrease was also attributable to $105 million in lower energy purchases primarily in the PJM region as a result of lower load contract volumes in 2012, and $26 million of lower emission charges due to lower coal generation in the PJM and New England regions. These decreases were partially offset by an increase of $66 million due primarily to higher congestion costs in the PJM region. planned outage and maintenance costs in 2012, mainly at our gas-fired Bethlehem facility in New York, Bergen and Linden gas-fired plants, and Mercer coal-fired plant and coal/gas-fired Hudson plant in New Jersey, and coal-fired Keystone plantand Conemaugh plants in Pennsylvania. This decrease was partially offset by refueling costs in 2012 for our 100%-owned Hope Creek nuclear facility as compared to our portion of refueling costs in 2011 for our 57%-owned Salem 2 nuclear unit. $5$9 million due primarily to higher depreciable asset bases at Fossil and Nuclear, largely resulting fromincluding placing ainto service the new 267 MW gas-fired peaking unitunits at Kearny, New Jersey and 130 MW gas-fired peaking capacity at New Haven, Connecticut into service on June 1, 2012 as well asand completion of the steam path retrofit upgrade at our co-owned Peach Bottom Unit 3 in October 2011.Other Income and (Deductions)net decrease of $58 million was due primarily to lower net realized gains on our NDT Fund. $9$4 million due primarily to impairments on the NDT Fund in 2012. $30$37 million due primarily to$26$47 million resulting primarily from the redemptionmaturity of $606 million of 7.75% Senior Notes in early April 2011 and the early redemption of $600 million of 6.95% Senior Notes in December 2011, anda $4partially offset by an increase of $12 million decrease due to interest costs that we capitalizedtwo $250 million Senior Notes issuances in 2012 for projects while under construction, primarily the gas-fired peaking facilities at Kearny, New Jersey and New Haven, Connecticut, both of which we began building in the second quarter ofSeptember 2011. $111$165 million in 2012 due primarily to lower pre-tax income.gain of $54 milliongains from the March 2011 sale,their sales, are included in this category.category for 2011. See Item 8. Financial Statements and Supplementary Data—Note 4. Discontinued Operations and Dispositions for additional information. Three Months Ended
June 30, Increase/
(Decrease) Six Months Ended
June 30, Increase/
(Decrease) Millions $ 101 $ 105 $ (4 ) $ 298 $ 268 $ 30 $ 101 $ 105 $ (4 ) $ 298 $ 268 $ 30 Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 vs. 2011 2012 2011 2012 vs. 2011 Millions Income from Continuing Operations $ 155 $ 154 $ 1 $ 453 $ 422 $ 31 Net Income $ 155 $ 154 $ 1 $ 453 $ 422 $ 31 JuneSeptember 30, 2012, the primary reason for the $1 millionincrease in Income from Continuing Operations was$4$31 million decreaseincrease in Income from Continuing Operations werehigher Operation and Maintenance costs,partially offset by higher transmission formula rates, andhigher Weather Normalization Charge (WNC).For the six months ended June 30, 2012, the primary reasons for the $30 million increase in Income from Continuing Operations werehigher WNC,higher transmission formula rates, and Three Months
Ended June 30, Increase/
(Decrease) Six Months
Ended June 30, Increase/
(Decrease) Millions Millions % Millions Millions % $ 1,407 $ 1,571 $ (164 ) (10 ) $ 3,346 $ 3,877 $ (531 ) (14 ) Energy Costs 622 815 (193 ) (24 ) 1,624 2,181 (557 ) (26 ) 350 304 46 15 726 672 54 8 Depreciation and Amortization 188 172 16 9 378 351 27 8 20 28 (8 ) (29 ) 49 71 (22 ) (31 ) Other Income (Deductions) 11 4 7 N/A 21 8 13 N/A 0 0 0 0 0 1 (1 ) N/A Interest Expense 74 78 (4 ) (5 ) 147 157 (10 ) (6 ) 63 73 (10 ) (14 ) 145 184 (39 ) (21 ) Three Months Ended Nine Months Ended September 30, September 30, 2012 2011 2012 vs 2011 2012 2011 2012 vs 2011 Millions Millions % Millions Millions % Operating Revenues $ 1,683 $ 1,841 $ (158 ) (9 ) $ 5,029 $ 5,718 $ (689 ) (12 ) Energy Costs 756 943 (187 ) (20 ) 2,380 3,124 (744 ) (24 ) Operation and Maintenance 366 342 24 7 1,092 1,014 78 8 Depreciation and Amortization 216 197 19 10 594 548 46 8 Taxes Other Than Income Taxes 24 31 (7 ) (23 ) 73 102 (29 ) (28 ) Other Income (Deductions) 10 6 4 67 31 14 17 N/A Other-Than Temporary Impairments — — — N/A — 1 (1 ) (100 ) Interest Expense 73 77 (4 ) (5 ) 220 234 (14 ) (6 ) Income Tax Expense (Benefit) 103 103 — — 248 287 (39 ) (14 ) ended JuneEndedSeptember 30, 2012 as compared As Compared to 2011 $164$158 million due primarily to $193$187 million due to lower Electric and Gas revenues. This is entirely offset asby savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.BGSS to retail customers. $135$158 million due primarily to $107$141 million in lower BGS revenues and $28$17 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to lower prices. BGS sales decreased 15%11% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 2%1%. $58$29 million due to lower BGSS prices of $42$26 million and lower BGSS volumes of $16$3 million due to weather. $1$3 million due primarily to lower miscellaneous electric operating revenues partially offset by increasedand decreased revenues from our appliance repair business. $23$23 million due primarily to an increase in transmission revenues.$20$22 millionhigher due primarily to net rate increases.increases. $6$4 million due primarily to a higher WNC revenue of $6 millionand higher Capital Infrastructure Program (CIP) revenue of $1 million, partially offset by lower sales volume and of $3 million.lower sales volumes.Electric distribution revenues decreased $3 million due primarily to lower TEFA revenue due to a lower TEFA rate and lower sales volumes of $6 million, partially offset by higher Solar, Energy Efficiency and Conservation Program (Solar/EE) revenue of $7 millionand higher CIP revenue. $7$9 million due primarily to higher Securitization Transition Charge (STC) revenues of $4$7 million and higher Societal Benefit Charges (SBC) of $5 million, partially offset by a higherlower Margin Adjustment Clause (MAC) of $2$3 million and higher Societal Benefit Charges (SBC) of $1 million.. The changes in STC, MAC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections. $193 million.$187 million. This is entirely offset by Commodity Revenue. $135$158 million due to $69$75 million or 10% in lower BGS and NUG volumes due to customer migration to TPS, $62$47 million of lower BGS prices, and $4$36 million for decreased deferred cost recovery. $58$29 million due to $42$26 million or 24%25% in lower prices and $16$3 million or 9%3% in lower sales volumes due primarily to weather. $46$24 million due primarily to$14$10 millionincrease in pension and other postretirement benefits (OPEB) expenses,$9$6 millionincrease in transmission related costs, and$6$3 millionincrease in payroll costs, andgas bad debt expense,a $5 increase in pension and other postretirement benefits (OPEB) expenses.storm damages in prior year. $16$19 million due primarily to$10$13 million for amortization of Regulatory Assets, and$6$6 million for additional plant in service. $8$7 million due to a lower TEFA rate and lower sales volumes for electric and gas.$7$4 million was due primarily to a $5 million an increase in capitalized allowance for Equity Funds used during construction and a $2 million increase in Solar Loan interest income.construction. $4$4 million due primarily to the $101 millionpartial redemption of securitization debts, partially offset by the interest associated with the $450 million MTN issued in May 2012.debt. See Note 9. Changes in Capitalization for details.Income Tax ExpenseNine Months EndedSeptember 30, 2012 As Compared to 2011 $10$689 million due primarily to lower pre-tax income.Six Months ended June 30, 2012 as compared to 2011Operating Revenuesdecreased $531 million due primarily to $557$744 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.Gas revenues decreased $298 million dueBGSS to lower BGSS volumes of $163 million and lower BGSS prices of $135 million. The average price of gas was 16% lower in 2012 than in 2011. $259$417 million due primarily to $230$371 million in lower BGS revenues and $29$46 million in lower revenues from the sale of NUG energy and collections of NGC due primarily to lower prices. BGS sales decreased 16%14% due primarily to customer migration to TPS; in contrast, delivery sales decreased only 3%2%.were flatincreased$4 million due primarily to higher STC revenues of $6$13 million, partially offset by lower SBC of $8 million and higherlower MAC of $1$1 million offset by lower SBC of $7 million.. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections. $24$51 million due primarily to an increase in transmission revenues.$42$64 millionhigher due primarily to net rate increases.increases. $12$3 million due primarily to lower sales volume of $57 million, lower TEFA revenue of $11 million due to a lower TEFA rate and lower Solar/EE revenue,, partially offset by higher WNC revenue of $57 millionand higher CIP revenue.revenue of $8 million.Electric distribution revenues decreased $6 millionOther Operating Revenueswas flat due primarily to lower TEFA revenue due to a lower TEFA rate and lower sales volumes, partially offset by higher Solar/EE revenue and higher CIP revenue.Other Operating Revenuesincreased $2 million due primarily to increased revenues from our appliance repair business, partially offset by lower miscellaneous electric operating revenues. $557 million.$744 million. This is entirely offset by Commodity Revenue.Gas $298$417 million due to $163$210 million or 19% in lower sales volumes due primarily to weather and $135 million or 16% in lower prices.Electric costs decreased $259 million due to $135 million or 10% in lower BGS and NUG volumes due to customer migration to TPS, $97$145 million of lower BGS prices, and $27$62 million for decreased deferred cost recovery. $54$78 million due primarily to$15$23 millionincrease in costs recognized related to SBC, Solar/EE and CIP,$13$19 millionincrease in transmission related costs,a $9 in payroll costs, anda $8 million increase in pension and OPEB expenses. $27$46 million due primarily to$16$30 million for amortization of Regulatory Assets, and$12$18 million for additional plant in service. $22$29 million due to a lower TEFA rate and lower sales volumes for electric and gas.$13$17 million was due primarily to a $9$13 millionincrease in capitalized allowance for Equity Funds used during construction and a $3$6 millionincrease in Solar Loan interest income. $10$14 million due primarily to the $101 millionpartial redemption of securitization debts, partially offset by the interest associated with the $450 million Medium-Term Notes issued in May 2012.debt. See Note 9. Changes in Capitalization for details. $39$39 million due primarily to tax benefits related to settlement of IRS tax audits. Three Months Ended
June 30, Increase/
(Decrease) Six Months Ended
June 30, Increase/
(Decrease) Millions $ 2 $ 5 $ (3 ) $ 42 $ 2 $ 40 $ 2 $ 5 $ (3 ) $ 42 $ 2 $ 40 Three Months Ended Nine Months Ended September 30 September 30 2012 2011 2012 vs. 2011 2012 2011 2012 vs. 2011 Millions Income from Continuing Operations $ 7 $ (166 ) $ 173 $ 49 $ (164 ) $ 213 Net Income $ 7 $ (166 ) $ 173 $ 49 $ (164 ) $ 213 sixthree months ended JuneSeptember 30, 2012, the primary reason for the $40$173 million increase in Income from Continuing Operations was the absence of the after-tax charge on leveraged leases related to Dynegy in the prior year.audits.sixnine months ended JuneSeptember 30, 2012, our operating cash flow decreased $17$98 million as compared to the same period in 2011. The net change was due primarily to net changes from Power and PSE&G, as discussed below.Power $294$315 million from $1,146$1,487 million to $852$1,172 million for the sixnine months ended JuneSeptember 30, 2012, as compared to the same period in 2011, primarily resulting from lower earnings partially offset by a decrease of $86$87 million in benefit plan funding. $180$169 million from $279$872 million to $459$1,041 million for the sixnine months ended JuneSeptember 30, 2012, as compared to the same period in 2011, due primarily to higher earnings combined with$173$174 million in benefit plan funding, and$108$175 million in net prepayments,$96$164 million due to lower collections of customer receivables.JuneSeptember 30, 2012, no single institution represented more than 8% of the total commitments in our credit facilities.JuneSeptember 30, 2012, our total credit capacity was in excess of our anticipated maximum liquidity requirements through 2012.JuneSeptember 30, 2012 were as follows:
Facility
Liquidity
Date Millions $ 500 $ 12 (A) $ 488 Mar 2017 Commercial Paper (CP) Support/Funding/Letters of Credit 500 0 500 Apr 2016 CP Support/Funding/Letters of Credit $ 1,000 $ 12 $ 988 $ 1,600 $ 121 (A) $ 1,479 Mar 2017 Funding/Letters of Credit 1,000 0 1,000 Apr 2016 Funding/Letters of Credit 100 100 (A) 0 Sept 2015 Letters of Credit $ 2,700 $ 221 $ 2,479 $ 600 $ 16 (A) $ 584 Apr 2016 CP Support/Funding/Letters of Credit $ 600 $ 16 $ 584 $ 4,300 $ 249 $ 4,051 As of September 30, 2012 Company/Facility Usage Primary Purpose Millions PSEG 5-year Credit Facility $ 500 $ 4 (A) $ 496 Mar 2017 Commercial Paper (CP) Support/Funding/Letters of Credit 5-year Credit Facility 500 — 500 Apr 2016 CP Support/Funding/Letters of Credit Total PSEG $ 1,000 $ 4 $ 996 Power 5-year Credit Facility $ 1,600 $ 119 (A) $ 1,481 Mar 2017 Funding/Letters of Credit 5-year Credit Facility 1,000 — 1,000 Apr 2016 Funding/Letters of Credit Bilateral Credit Facility 100 100 (A) — Sept 2015 Letters of Credit Total Power $ 2,700 $ 219 $ 2,481 PSE&G 5-year Credit Facility $ 600 $ 1 (A) $ 599 Apr 2016 CP Support/Funding/Letters of Credit Total PSE&G $ 600 $ 1 $ 599 Total $ 4,300 $ 224 $ 4,076 (A) Includes amounts related to letters of credit outstanding. $300$150 million of 5.13% 5.00%Medium Term Notes maturing in January 2013 and $300 million5.38%Medium Term Notes maturing in September 2012.2013. Power has $300 million of 2.50%Senior Notes maturing in April 2013. For a discussion of our long-term debt transactions during 2012, see Note 9. Changes in Capitalization.Thethe Board of Directors declared a quarterly dividend of $0.3550 per share of common stock for the third quarter of 2012. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.agencies’agencies' ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In AprilMay 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In October 2012, S&P published updated credit opinions that left the ratings and outlooks for Power and PSE&G unchanged. In May 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In May 2012, Moody’sMoody's published updated credit opinions on PSEG, Power and PSE&G. Moody’sMoody's upgraded PSE&G’s&G's Mortgage Bond Rating to A1 from A2 and revised the outlook to stablePSEG’sPSEG's and Power’sPower's ratings and outlooks remained unchanged. In July 2012, Fitch published updated credit opinions on PSEG, Power and PSE&G. Fitch upgraded PSE&G’s&G's Mortgage Bond Rating to A+ from A and its stable outlook remained unchanged. PSEG’sPSEG's and Power’sPower's ratings and outlooks remained unchanged. Moody’s(A)S&P(B)Fitch(C)PSEGOutlookStable Positive Stable Commercial Paper P2Moody’s (A) S&P (B) Fitch (C) PSEG Outlook Stable Positive Stable Commercial Paper P2 A2 F2 PowerOutlookStablePower Positive Stable Senior NotesOutlook Stable Baa1Positive Stable Senior Notes Baa1 BBB BBB+ PSE&G OutlookStable Positive Stable Mortgage BondsOutlook Stable A1Positive Stable Mortgage Bonds A1 A– A+ Commercial Paper P2 A2 F2 (A) Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. (B) S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities. (C) Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities. Powersixnine months ended JuneSeptember 30, 2012, Power made $240$322 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $104$171 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 8. Commitments and Contingent Liabilities.sixnine months ended JuneSeptember 30, 2012, PSE&G made $920$1,433 million of capital expenditures, including $870$1,369 million of investment in plant, primarily for reliability of transmission and distribution systems and $50$64 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $44$71 million, which is included in operating cash flows.ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We use VaR models to assess the market risk of our commodity businesses. The Portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. Millions $ 15 $ 13 $ 19 $ 9 $ 24 $ 21 $ 30 $ 13 Three Months Ended September 30, 2012 MTM VaR (A) Millions 95% Confidence Level, Loss could exceed VaR one day in 20 days Period End $ 11 Average for the Period $ 12 High $ 18 Low $ 7 99.5% Confidence Level, Loss could exceed VaR one day in 200 days Period End $ 16 Average for the Period $ 19 High $ 28 Low $ 11 (A) JuneSeptember 30, 2012 and December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011.ITEM 4. CONTROLS AND PROCEDURES secondthird quarter of 2012 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.ITEM 1. LEGAL PROCEEDINGS ReportReports on Form 10-Q for the quarterquarters ended March 31, 2012 and June 30, 2012, see Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.ITEM 1A. RISK FACTORS TheFactor shown below updates a risk factorFactors to be added to those disclosed in Part I Item 1A on page 35 of our 2011 Annual ReportsReport on Form 10-K.We are subject to comprehensive10-K and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.We are subject to regulation by federal, state and local authorities. Changes in regulation can cause significant delays in or materially affect business planning and transactions and can materially increase our costs. Regulation affects almost every aspectPart II Item 1A of our businesses, such as our ability to:
June 30, 2012 Quarterly Report on Form 10-Q.•Obtain fair and timely rate relief— Our transmission assets are regulated by FERC and costs are recovered through rates set by FERC. Transmission formula rates, and specifically the Return on Equity (ROE) embedded in these formula rates, have recently become the target of certain state utility commissions, consumer advocates and consumer groups seeking to lower customer rates in New England. These agencies and groups have filed complaints at FERC asking the FERC to reduce the base ROE of various New England transmission owners with formula rates. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, the matter could set a precedent for FERC-regulated transmission owners with formula rates in place, such as PSE&G. Inability to obtain a fair return on our investments or to timely recover material costs not included in rates would have a material adverse effect on our business.ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS secondthird quarter of 2012:
of Shares
Purchased
Price Paid
per Share 0 $ 0 58,267 $ 31.67 25,000 $ 31.28 Three Months Ended September 30, 2012 July 1-July 31 — $ — August 1-August 31 67,900 $ 32.65 September 1-September 30 26,000 $ 31.59 ITEM 5. OTHER INFORMATION ReportReports on Form 10-Q for the Quarter Endedquarters ended March 31, 2012 isand June 30, 2012 are updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2011 Annual Report on Form 10-K and the Quarterly ReportReports on Form 10-Q for the Quarter Endedquarters ended March 31, 2012 and June 30, 2012. References are to the related pages on the Form 10-K or Forms 10-Q as printed and distributed.and March 31, 2012 Form-10-QForm 10-Q page 77.77 and June 30, 2012 Form 10-Q page 84.In 2011, the State of New Jersey concluded that new natural gas-fired generation was needed and enacted the Long-Term Capacity Agreement Pilot Program Act (LCAPP Act) to subsidize approximately 2,000 MW of new generation. The LCAPP Act provided that subsidies would be offered through long-term standard offer capacity agreements (SOCAs) between selected generators and the New Jersey Electric Distribution Companies (EDCs). The SOCA requires that the generator bid in and clear in the PJM RPM base residual auction in each year of the SOCA term in order to receive the subsidized payment. The SOCA requires each New Jersey EDC to provide the generators with guaranteed capacity payments funded by ratepayers. Each of the New Jersey EDCs, including PSE&G, entered into the SOCAs as directed by the State, but did so under protest reserving their rights. TwoIn May 2012, two of the three generators, CPV Shore, LLC (CPV), a subsidiary of Competitive Power Ventures, Inc.May 2012 RPM auction.court,court. On September 28, 2012, the judge in the federal action denied all motions for summary judgment and this case is pending.Power hasWe have joined other generators in challenging this order on constitutional grounds in federal court. The Maryland EDCs have also appealed the April 12, 2012 order in state court. Developments in Maryland may stimulate the construction of subsidized generation and impact energy and capacity prices in PJM.gas firedgas-fired generation from bidding in RPM at less than an established minimum level established by Tariff, or a cost-based bid to the extent that the generator can demonstrate that its costs are lower than the MOPR. Despite challenges by several parties, theThe MOPR was in place for the May 2012 auction, althoughbut we believe it did not operate to protect the market against these suppression efforts. As a result, discussions among a diverse group of PJM stakeholders to improve the MOPR are ongoingensued and a settlement was recently reached among those stakeholders. PJM is currently educating its stakeholders on the settlement and PJM plans to bring the settlement to a stakeholder vote in PJM. In addition, legal challenges toNovember 2012. If this settlement is approved by the FERC’sFERC, it will change how the MOPR order remain pending.20.20 and June 30, 2012 Form 10-Q page 84.In July 2011, FERC issued Order 1000 (Order 1000) which, among other things (i) directs regional planners, such as PJM, to modify their planning processes to “consider transmission needs driven by public policy requirements established by state or federal laws or regulations” (ii) directs regional planners to remove the “ right of first refusal” (ROFR) from its tariffs and agreements under which incumbent transmission companies have a ROFR to build transmission located within their respective service territories, subject to certain exceptions (iii) requires regional planners to develop regional cost allocation methodologies that take into consideration that costs be “roughly commensurate” with project benefits and (iv) requires regional planners in neighboring regions to have a common interregional cost allocation method for new interregional facilities. We, along with many other parties to the proceeding, sought rehearing of the Final Rule.Order 1000. In May 2012, the FERC issued an order that denied rehearing in this proceeding. In June 2012, PSEGwe filed a Petition for Review of Order No. 1000 in federal appellate court, in which we plan to challenge the legal basis for the FERC’s actions. Other companies and state commissions have filed appeals as well. PJM is currently conductinghas recently concluded a stakeholder process to developfinalize the rules implementing details regarding Order 1000. An expected outcome of this Final Ruleproceeding is the construction of more transmission through “public policy” planning and theand March 31, 2012 Form 10-Q page 78.We have not received certain environmental approvals that are required for each of the Eastern78 and Western segments of the Susquehanna-Roseland line, including fromJune 30, 2012 Form 10-Q page 85. On October 1, 2012, the National Park Service (NPS). On March 29, 2012, the NPS identified issued a “preferred alternative” for its final Environmental Impact Statement (EIS), under which for the Susquehanna-Roseland line, selecting our and PPL Electric Utilities Corporation's choice of route that follows the existing right of way. On October 15, 2012, several environmental groups filed a complaint in federal court challenging the NPS' issuance of the final EIS, seeking to set aside the EIS and to enjoin implementation of the NPS' decision. If this request for injunctive relief is granted, the construction schedule for the project would followcould be impacted. We have also recently obtained environmental permits for the routeproject from the New Jersey Department of the existing transmission line. This route was the one approved by state regulators including the BPU. The final EIS is expected to be issuedEnvironmental Protection (NJDEP). We have begun construction in October 2012.those areas where necessary permits have been obtained. Currently, the expected in-service date for the Eastern segment of the project is June 2014 and for the Western segment is June 2015, although further delays are possible. Delays in the construction schedule could impact the timing of expected transmission revenues.any of these complaints,this complaint, this matter could set a precedent for FERC-regulated transmission owners with formula rates in place, such as PSE&G.and March 31, 2012 Form 10-Q page 79.79 and June 30, 2012 Form 10-Q page 85. In accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), the SEC and the CFTC are in the process of implementing new rules to effectuate stricter regulation over swaps and derivatives including potentially significant reporting and record-keeping requirements and clearing/collateral requirements. Additionally, the Dodd-Frank Act will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations. The CFTC has issued Notices of Proposed Rulemaking on many of the key issues, including defining swaps and swap dealers; reporting requirements; and margin requirements, as well as Final Rules. Specifically, in May 2012, the CFTC issued a Final Rule regarding the definition of a swap dealer. In addition, in JulyAugust 2012, the CFTC voted to issueissued a Final Rule regarding commercial end users, and the definition of a swap although this ruleand a proposed order regarding exemptions from Commodity Exchange Act provisions for specified Regional Transmission Owners (RTO) / Independent System Operators (ISO) transactions. In September 2012, several industry trade groups filed a request with the CFTC to delay the final implementation dates until all required rules are final. In addition, a federal district court recently vacated the CFTC's rules establishing position limits for trading in certain commodities, such as natural gas. Thus, the effective date of these position limits rules has yet to be published. been delayed indefinitely. The CFTC also issued a series of no action letters in October 2012 which delay various implementation timeframes through the balance of 2012.RatesRetail Gas Transportation RatesDecember 31, 2011 Form 10-K page 24 and March 31,June 30, 2012 Form 10-Q page 80. The BPU commenced a generic proceeding to evaluate the process and standards for all utilities to provide discounts to their gas86delivery customers, culminating in the issuance of an order in 2011.. We along with the other New Jersey gas utilities, filed to implement tariffs with the BPU setting forth their individual processes by which customers can obtain discounts. On May 23, 2012, the BPU approved PSE&G’s tariff filing.Connecticut ProjectPower waswere selected by the Connecticut Public Utilities Regulatory Authority (PURA), formerly the Department of Public Utility Control, in a regulatory process to build 130 MW of gas firedgas-fired peaking capacity. The project was placed in service in June 2012. The first of the annual filings to recover the capital and operating costs of the project was submitted in December 2011 to PURA. PURA issued a final decision in early June 2012, authorizing Powerus to recover $14.5 million for the period June 1, 2012 to December 31, 2012. On July 31, 2012, Powerwe filed a petition and testimony seeking approval from PURA of a 2013 annual fixed revenue requirement of $20.7approximately $20 million, which represents the facility’s fixed operation and maintenance (O&M) costs along with the return of and return on the investment for the calendar year 2013. PURA is expected to issue a final decision before the end of 2012. Variable costs (e.g., fuel, Connecticut’s generation tax, and certain non-fuel O&M expenses) are recovered through a contract for differences.25.25 and June 30, 2012 Form 10-Q page 86. The USF is an energy assistance program mandated by the BPU to provide payment assistance to low income customers. The Lifeline program is a separate mandatedPSE&G,us, filed requests to reset the statewide rates for the USF and the Lifeline program. The filed USF rates were set to recover approximately $226 million on a statewide basis. Of this amount, the statewide electric rates are set to recover $169 million with the remaining $57 million recovered through gas rates. The rates for the Lifeline program were set to recover $66 million, $46 million electric and $20 million gas. The filed rates were subsequently updated and approved effective October 1, 2012. We are currentlyearn no margin on the collection of the USF and Lifeline programs resulting in the discovery phase of this proceeding.25.PSE&G’s25 and June 30, 2012 Form 10-Q page 86. Our WNC is a rate mechanism that allows PSE&Gus to increase itsour rates to compensate for lower revenues it receiveswe receive from customers as a result of warmer-than-normal winters and to decrease itsour rates to make up for higher revenues it receiveswe receive as a result of colder-than-normal winters. The payments and refunds are subject to certain limitations and rate caps. Unrecovered balances associated with application of the rate cap are deferred until the next recovery period.PSE&Gus to calculate, at the end of each October – May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred. On June 27, 2012, we filed a petition and testimony with the BPU seeking BPU approval to recover $56.6 million in deficiency revenues through the WNC,WNC. On September 13, 2012,the BPU approved our recovery of which $40.7 million in deficiency revenues which would be recovered from our customers during the 2012-2013 Winter Period (October 1 – May 31). The remaining estimated $16$15.9 million expected to be recovered will be applied to the 2013-2014 Winter Period, pursuant to the WNC tariff provisions approved by the BPU on July 9, 2010, as part of the Stipulation of Settlement of PSE&G’s 2009 Rate Case.25.25 and June 30, 2012 Form 10-Q page 86. On July 2, 2012, we filed a petition with the BPU requesting an increase in the Solar/EE Recovery Charge seeking to recover approximately $61.6 million in electric revenue and $8.5 million in gas revenue on an annual basis. These changes are the result of adjustments in the components of the Solar/EE Recovery Charges including: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic Extension Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All) and Solar Loan II Program. The discovery phase of this proceeding is underway and in October 2012 the matter was assigned to an Administrative Law Judge (ALJ).and March 31, 2012 Form 10-Q page 80.80 and June 30, 2012 Form 10-Q page 87.In November 2011, we filed a RAC 19 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $8.9 million and $10.1 million, respectively. We are currently inOn October 11, 2012, we received the settlement phaseAdministrative Law Judge's (ALJ) Initial Decision allowing full recovery of RAC 19 costs including costs of the proceeding.Passaic River and Newark Bay superfund (CERCLA) matters and the Occidental litigation that were allocated to PSE&G and included in this request. On October 23, 2012, the BPU issued a final Order approving the ALJ's Initial Decision.BGSSand March 31, 2012 Form 10-Q page 80.80 and June 30, 2012 Form 10-Q page 87.On June 1, 2012, PSE&Gwe made itsour annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $70.7 million, excluding sales and use tax, to be effective October 1, 2012. This represents a reduction of approximately 5.2% for a typical residential gas heating customer. This BGSS reduction will be the ninth consecutive reduction since January 2009. A DraftWe entered into a Stipulation has been circulatedwith the parties which would put the requested lower BGSS rate into effect as filed on October 1, 2012 on a provisional basis. A final decision is expected in early 2013.and March 31, 2012 Form 10-Q page 80.The BPU has concluded a generic proceeding examining whether existing utility rate-based solar programs, including ours, should be expanded, modified or discontinued once the current programs expire or the authorized level of solar installations has been achieved. On May 23,80 and June 30, 2012 the BPU issued an order ruling that the capacity of utility “financing” programs, which includes PSE&G’s Solar Loan Program, may be increased by a total of 180 MW (allocated to all of the electric utilities) over the next three years.Form 10-Q pagePSE&Gwe filed for an extension of itsour Solar 4 All program. In this filing, PSE&G iswe are seeking BPU approval for up to $690PSE&G proposeswe propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets.Also, consistent with the BPU’s generic proceeding on solar, PSE&GPSE&G iswe are seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, the projects are built and the loans are closed.29.29 and June 30, 2012 Form 10-Q page 87.In 2009, the BPU, in accordance with New Jersey statutes, initiated audits of PSE&G with respect to the effectiveness of its management and its compliance with rules governing PSE&G’s interactions with its affiliated companies. The audits were conducted on a combined basis by a consultant who was retained by the BPU. On May 23, 2012, the BPU issued the consultant’s audit report forwill endended on September 28, 2012. Thereafter, theThe BPU is expected to issue an order addressing the audit report’sreport's findings and recommendations.and March 31, 2012 Form 10-Q page 81.81 and June 30, 2012 Form 10-Q page 88. On July 6, 2011, the EPA issued the final CSAPR. CSAPR which limits power plant emissions of Sulfur Dioxide (SO2) and annual and ozone season NOX in 28 states that contribute to the ability of downwind states to attain and/or maintain current particulate matter and ozone National Ambient Air Quality Standards. Technical revisions to the CSAPR were finalized on February 7, 2012. The EPA increased New Jersey’s allocation of annual NOX and ozone season NOX allowances beyond what was proposed. The EPA also finalized the increase in New Jersey’s allocation of SO2 allowances from the October proposal. The additional increases in NOX allocations are favorable to PSEG, since both PSEG and New Jersey as a whole are projected to be very tight on NOX allowances (both ozone season and annual).United States Court of Appeals for the D.C. circuit issued a ruling to stay CSAPR pending judicial review. Until a final decision is reached,CSAPR. On August 21, 2012 the court hasvacated CSAPR and ordered that the existing Clean Air Interstate Rule requirements continue temporarily. PSEGremain in effect until an appropriate substitute rule has intervened in this litigation, along with Calpine and Exelon, in support of the rule. Oral argument occurred on April 13, 2012. A final decision on the merits is expected in the summer of 2012.Climate ChangeRegional Greenhouse Gas Initiative (RGGI)December 31, 2011 Form 10-K page 31.In response to concerns over global climate change, some states have developed initiatives to stimulate national climate legislation through CO2 emission reductions in the electric power industry. Ten northeastern states, including New Jersey, New York and Connecticut, originally established RGGI to cap and reduce CO2 emissions in the region. In general, these states adopted state-specific rules to enable the RGGI regulatory mandate in each state.Applicable rules make allowances available throughbeen promulgated. On October 5, 2012, EPA filed a regional auction whereby generators may acquire allowances that are each equal to one ton of CO2 emissions. Generators are required to submit an allowancerequest for each ton emitted over a three year period (e.g. 2009, 2010, and 2011). Allowances are available through the auction or through secondary markets and are required to be submitted to states by March 2012 for the first compliance period.Pricing for the allowances vary based on future allowance market conditions and electric generation market conditions. For the first three-year compliance period, we have acquired sufficient allowances to compensate for CO2 emissions from affected sources.In May 2011, the Governor of New Jersey announced his intent to withdraw New Jersey from RGGI beginning in 2012. Therefore, our New Jersey facilities are no longer obligated to acquire CO2 emission allowances, but our generation facilities in New York and Connecticut remain subject to RGGI.On June 6, 2012, the Natural Resources Defense Council and Environment New Jersey filed suit against NJDEP claiming that New Jersey’s withdrawal from RGGI did not follow proper legal procedure.CO2 Regulation under the Clean Air Act (CAA)December 31, 2011 Form 10-K page 32.In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate GHG emissions from certain motor vehicles (Motor Vehicle Rule). Under the CAA, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to CAA permitting for new facilities and major facilitymodifications that increase the emission of GHGs, including CO2. However, guidance issued by the EPA in March 2010 interpreted the CAA to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule was scheduled to take effect in January 2011. In May 2010, the EPA finalized a “Tailoring Rule” that would phase in, beginning in 2011, the application of this permitting requirement to facilities such as ours.rehearing. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the owner of the facility would need to evaluate and perhaps install best available control technology (BACT) for GHG emissions.In November 2010, the EPA published guidance to state and local permitting authorities to undertake BACT determinations for new and modified emission sources. The guidance does not define the specific technology or technologies that should be considered BACT. The guidance does emphasize the use of energy efficiency, and specifically states that the technology of storing CO2 under the earth, also known as carbon capture and storage, is not yet mature enough to be considered a viable alternative at this stage. On April 13, 2012, the EPA published the proposed New Source Performance Standards (NSPS) for GHGs for new power plants and refineries. New or modified sources must employ BACT which is defined on a case-by-case basis and can be no less stringent than the applicable NSPS. Thus, for new power plants where the proposed NSPS identifies the applicable standard, if adopted as proposed, all permit decisions regarding BACT and application completeness should be made to reflect at least the level of stringency contained in those standards.CO2 LitigationDecember 31, 2011 Form 10-K page 32. On June 26, 2012, the US Court of Appeals for the DC Circuit upheld the EPA finding that GHGs could reasonably be expected to endanger public health and welfare. However, the Court dismissed the action brought by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted GHGs, causing global climate change resulting in a variety of damages. Plaintiffs are expected to appeal to the US Supreme Court.Water Pollution ControlDecember 31, 2011 Form 10-K page 33 and March 31, 2012 Form 10-Q page 81.Section 316(b) of the FWPCA requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling through the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant engineering challenges and significant costs, which can affect the economic viability of a particular plant. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012.In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the BTA (e.g. closed-cycle cooling). Instead, the proposed rule established marine life mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. We reviewed the proposed rule, assessed the potential impact on our generating facilities and used this information to develop our comments to the EPA which were filed in August 2011. On June 11, 2012, the EPA posted a Notice of Data Availability (NODA) requesting comment on a series of technical issues related to the impingement mortality proposed standards. On June 12, 2012, the EPA posted a second NODA outlining its plans to finalize a “Willingness to Pay” survey it initiated to develop non-use benefits data in support of the April 2011 rule proposal. PSEG and industry trade associations submitted comments on both NODAs in early July. In July 2012, the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.If the rule were to be adopted as proposed, the impact on us would be material since the majority of our electric generating stations would be affected. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material. See Note 8. Commitments and Contingent Liabilities for additional information.Nuclear Fuel DisposalDecember 31, 2011 Form 10-K page 34.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. Under the contracts, the U.S. Department of Environmental Protection (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998 but has not yet done so. The Nuclear Waste Policy Act of 1982 requires the DOE to perform an annual review of the Nuclear Waste Fee to determine whether that fee is set appropriately to fund the national nuclear waste disposal program. In October 2009, the DOE stated that the current fee of 1/10 cent per kWh was adequate to recover program costs. In March 2011, we joined the Nuclear Energy Institute (NEI) and fifteen other nuclear plant operators in a lawsuit seeking suspension of the Nuclear Waste Fee. On June 1, 2012, The U.S. Court of Appeals for the District of Columbia ruled that the DOE failed to justify continued payments by electricity consumers into the Nuclear Waste Fund. The court ordered the DOE to conduct a complete reassessment of this fee within six months. While the court did not order the DOE to suspend the fee payments, the court rejected the DOE’s bases for continuing to collect the fees and therefore the DOE must provide clear justification to continue to collect the Nuclear Waste Fund fee at the present level.The Nuclear Waste Fee litigation is not expected to have any effect on our September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which we will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition. A similar settlement agreement was reached related to Peach Bottom in 2004.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. We have on-site storage facilities that are expected to satisfy the storage needs of Salem 1, Salem 2, Hope Creek, Peach Bottom 2 and Peach Bottom 3 through the end of their operating licenses.and March 31, 2012 Form 10-Q page 82.82 and June 30, 2012 Form 10-Q page 90.On April 5, 2012, several environmental organizations and CCR marketers (Environmental and Marketer Plaintiffs) brought a citizens’citizens' suit against the EPA in federal court arguing that the EPA has a non-discretionary duty to issue the CCR rules by a certain date. On May 15, 2012, the Utility Solid Waste Activities Group (USWAG) Policy Committee filed a Motion to Intervene in order to be in alignment with the EPA in defending against the environmental organizations’organizations' action. After May 2012, all parties agreed to a schedule for submitting briefs in this case. Motions for summary judgment remain pending.ITEM 6. EXHIBITS a. PSEG:a. PSEG: Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 31: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 31.1: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.1: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 101.INS: XBRL Instance Document Exhibit 101.SCH: XBRL Taxonomy Extension Schema Exhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase Exhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase Exhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase Exhibit 101.DEF: XBRL Taxonomy Extension Definition Document b. Power:b. Power: Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.2: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 31.3: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32.2: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.3: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 101.INS: XBRL Instance Document*DocumentExhibit 101.SCH: XBRL Taxonomy Extension Schema*SchemaExhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase*LinkbaseExhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase*LinkbaseExhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase*LinkbaseExhibit 101.DEF: XBRL Taxonomy Extension Definition Document*Documentc. PSE&G:c. PSE&G: Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements Exhibit 31.4: Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 31.5: Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act Exhibit 32.4: Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.5: Certification by Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 101.INS: XBRL Instance Document*DocumentExhibit 101.SCH: XBRL Taxonomy Extension Schema*SchemaExhibit 101.CAL: XBRL Taxonomy Extension Calculation Linkbase*LinkbaseExhibit 101.LAB: XBRL Taxonomy Extension Labels Linkbase*LinkbaseExhibit 101.PRE: XBRL Taxonomy Extension Presentation Linkbase*LinkbaseExhibit 101.DEF: XBRL Taxonomy Extension Definition Document*Document*XBRL information is furnished, not filed.PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED(Registrant)By:(Registrant) AugustNovember 2, 2012PSEG POWER LLC(Registrant)By:(Registrant) AugustNovember 2, 2012PUBLIC SERVICE ELECTRIC AND GAS COMPANY(Registrant)By:(Registrant) AugustNovember 2, 201294