UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED March 31, 2010
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
FOR THE TRANSITION PERIOD FROM TO
CommissionFile Number
Registrants, State of Incorporation,
Address, and Telephone Number
I.R.S. EmployerIdentification No.
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yesx No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Public Service Enterprise Group Incorporated
PSEG Power LLC
Public Service Electric and Gas Company
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
As of April 15, 2010, Public Service Enterprise Group Incorporated had outstanding 505,952,194 shares of its sole class of Common Stock, without par value.
As of April 15, 2010, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
PSEG Power LLC and Public Service Electric and Gas Company are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
Page
FORWARD-LOOKING STATEMENTS
PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
Notes to Condensed Consolidated Financial Statements
Note 1. Organization and Basis of Presentation
Note 2. Recent Accounting Standards
Note 3. Variable Interest Entities
Note 4. Asset Dispositions
Note 5. Available-for-Sale Securities
Note 6. Pension and Other Postretirement Benefits (OPEB)
Note 7. Commitments and Contingent Liabilities
Note 8. Changes in Capitalization
Note 9. Financial Risk Management Activities
Note 10. Fair Value Measurements
Note 11. Other Income and Deductions
Note 12. Income Taxes
Note 13. Comprehensive Income, Net of Tax
Note 14. Earnings Per Share (EPS)
Note 15. Financial Information by Business Segments
Note 16. Related-Party Transactions
Note 17. Guarantees of Debt
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview of 2010 and Future Outlook
Results of Operations
Liquidity and Capital Resources
Capital Requirements
Accounting Matters
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
PART II. OTHER INFORMATION
Legal Proceedings
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Item 5.
Other Information
Item 6.
Exhibits
Signatures
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Certain of the matters discussed in this report constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those anticipated. Such statements are based on management’s beliefs as well as assumptions made by and information currently available to management. When used herein, the words “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial Statements—Note 7. Commitments and Contingent Liabilities, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the United States Securities and Exchange Commission (SEC). These factors include, but are not limited to:
adverse changes in energy industry law, policies and regulation, including market structures and rules and reliability standards,
any inability of our 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 operations of our generating units,
changes in nuclear regulation and/or developments in the nuclear power industry generally that could limit operations of our nuclear generating units,
actions or activities at one of our nuclear units 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,
availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs,
any inability to realize anticipated tax benefits or retain tax credits,
changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units,
delays or unforeseen cost escalations in our construction and development activities,
increase in competition in energy markets in which we compete,
adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in discount rates and funding requirements, and
changes in technology and increased customer conservation.
Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors.
All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.
The forward-looking statements contained in this report are intended to qualify for the safe harbor provisions of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
2010
2009
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
NET INCOME
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS):
BASIC
DILUTED
EARNINGS PER SHARE:
DIVIDENDS PAID PER SHARE OF COMMON STOCK
See Notes to Condensed Consolidated Financial Statements.
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CONDENSED CONSOLIDATED BALANCE SHEETS
March 31,2010
December 31,2009
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents
Accounts Receivable, net of allowances of $76 and $79 in 2010 and 2009, respectively
Unbilled Revenues
Fuel
Materials and Supplies, net
Prepayments
Restricted Cash of Variable Interest Entities (VIEs)
Derivative Contracts
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
Nuclear Decommissioning Trust (NDT) Funds
Other Special Funds
Goodwill
Other Intangibles
Restricted Cash of VIEs
Total Noncurrent Assets
TOTAL ASSETS
2
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Long-Term Debt Due Within One Year
Securitization Debt of VIEs Due Within One Year
Commercial Paper and Loans
Accounts Payable
Accrued Interest
Accrued Taxes
Clean Energy Program
Obligation to Return Cash Collateral
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
Environmental Costs
Long-Term Accrued Taxes
Total Noncurrent Liabilities
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 7)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt
Securitization Debt of VIEs
Project Level, Non-Recourse Debt
Total Long-Term Debt
SUBSIDIARY’S PREFERRED STOCK WITHOUT MANDATORY REDEMPTION
STOCKHOLDERS’ EQUITY
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2010 and 2009—533,556,660 shares
Treasury Stock, at cost, 2010—27,621,816 shares; 2009—27,567,030 shares
Retained Earnings
Accumulated Other Comprehensive Loss
Total Common Stockholders’ Equity
Noncontrolling Interest
Total Stockholders’ Equity
Total Capitalization
TOTAL LIABILITIES AND CAPITALIZATION
3
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended
March 31,
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
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
Realized and Unrealized Gains on Energy Contracts and Other Derivatives
Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
Over Recovery of Societal Benefits Charge (SBC)
Cost of Removal
Net Realized (Gains) Losses and (Income) Expense from NDT Funds
Net Change in Certain Current Assets and Liabilities
Employee Benefit Plan Funding and Related Payments
Net Cash Provided By Operating Activities
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment
Proceeds from the Sale of Capital Leases and Investments
Proceeds from NDT Funds Sales
Investment in NDT Funds
Restricted Funds
Net Cash 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
Redemption of Preferred Securities
Net Cash 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
Interest Paid, Net of Amounts Capitalized
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PSEG POWER LLC
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
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Accounts Receivable
Accounts Receivable—Affiliated Companies, net
Short-Term Loan to Affiliate
LIABILITIES AND MEMBER’S EQUITY
Short-Term Loan from Affiliate
MEMBER’S EQUITY
Contributed Capital
Basis Adjustment
Accumulated Other Comprehensive Income (Loss)
Total Member’s Equity
TOTAL LIABILITIES AND MEMBER’S EQUITY
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Provision for Deferred Income Taxes and ITC
Net Realized and Unrealized Gains on Energy Contracts and Other Derivatives
Net Change in Certain Current Assets and Liabilities:
Fuel, Materials and Supplies
Margin Deposit Asset
Margin Deposit Liability
Accounts Receivable/Payable-Affiliated Companies, net
Accrued Interest Payable
Other Current Assets and Liabilities
Short-Term Loan—Affiliated Company, net
Issuance of Recourse Long-Term Debt
Cash Dividend Paid
Redemption of Non-Recourse Long-Term Debt
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Preferred Stock Dividends
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISEGROUP INCORPORATED
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
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Accounts Receivable, net of allowances of $76 in 2010 and $78 in 2009, respectively
Materials and Supplies
Deferred Income Taxes
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Accounts Payable—Affiliated Companies, net
Deferred Income Taxes and ITC
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2010 and 2009—795,234 shares
STOCKHOLDER’S EQUITY
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2010 and 2009—132,450,344 shares
Accumulated Other Comprehensive Income
Total Stockholder’s Equity
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Non-Cash Interest Expense
Over Recovery of Electric Energy Costs (BGS and NTC)
Over Recovery of Gas Costs
Over Recovery of SBC
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues
Solar Loan Investments
Net Change in Short-Term Debt
Deferred Issuance Costs
Net Cash Provided By (Used In) Financing Activities
Net Increase (Decrease) In Cash and Cash Equivalents
Income Taxes Received
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G each is only responsible for information about itself and its subsidiaries.
Organization
PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s four principal direct wholly owned subsidiaries are:
Power—which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and marketing and risk management functions through three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.
PSE&G—which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and FERC. Pursuant to applicable BPU orders, PSE&G is also investing in the development of solar generation projects and energy efficiency programs within its service territory.
PSEG Energy Holdings L.L.C. (Energy Holdings)—which owns and operates primarily domestic projects engaged in the generation of energy and has invested in energy-related leveraged leases through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings is also investing in solar generation projects and exploring opportunities for other investments in renewable generation.
PSEG Services Corporation (Services)—which provides management and administrative and general services to PSEG and its subsidiaries.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in the Annual Report on Form 10-K for the year ended December 31, 2009.
The unaudited condensed consolidated financial information furnished herein reflects all adjustments which are, in the opinion of management, necessary to fairly state the results for the interim periods presented. All such adjustments are of a normal recurring nature. The year-end Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included in the Annual Report on Form 10-K for the year ended December 31, 2009.
Reclassifications
Certain reclassifications have been made to the prior period financial statements to conform to the current presentation.
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As a result of new guidance adopted in 2010 on Variable Interest Entities (VIEs), we are required to present certain consolidated amounts related to VIEs separately on the face of our Condensed Consolidated Balance Sheets for PSEG and PSE&G with prior period amounts being reclassified as appropriate. See Note 2. Recent Accounting Standards for additional information.
On October 1, 2009, Energy Holdings distributed the outstanding equity of PSEG Texas, LP (PSEG Texas) to PSEG. PSEG in turn contributed it to Power as an additional equity investment. This transaction was accounted for as a noncash transfer of equity interest between entities under common control with prior period financial statements for Power being retrospectively adjusted to include the earnings related to PSEG Texas. As a result, Power’s Operating Revenues for the three months ended March 31, 2009 increased by $90 million and Power’s Net Income for the same period decreased by $4 million.
In addition, other-than-temporary impairments related to Power’s credit losses on available-for-sale debt securities in its NDT Funds were reclassified from Other Deductions to a separate line caption in the Consolidated Statements of Operations of PSEG and Power, for the three months ended March 31, 2009.
New Standards Adopted during 2010
During 2010, we have adopted the following new accounting standards. The new standards adopted did not have a material impact on our financial statements. The following is a summary of the requirements and impacts of the new standards.
Accounting for Variable Interest Entities
This accounting standard amends the criteria used to determine which enterprise has a controlling financial interest in a VIE. The amended standard includes the following provisions:
requires an enterprise to qualitatively assess whether it should consolidate a VIE based on whether it has (i) the power to direct the activities of a VIE that most significantly impact the economic performance of a VIE, and (ii) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
requires an ongoing reconsideration of the primary beneficiary,
amends the VIE reconsideration events (triggering events), and
requires additional disclosures for the enterprise that consolidates a VIE (the primary beneficiary)—to present separately on the face of the consolidated balance sheet (i) assets of the consolidated VIE that can be used only to settle obligations of the consolidated VIE and (ii) liabilities of a consolidated VIE for which creditors have no recourse to the general credit of the primary beneficiary.
There was no impact on our financial statements of the initial adoption of the new guidance for VIEs, other than presentation. In accordance with the guidance, we will continuously assess the primary beneficiaries. See Note 3. Variable Interest Entities for further information.
Improving Disclosures about Fair Value Measurements
requires disclosure of transfers between Level 1 and Level 2 and reasons for transfer,
requires disaggregation beyond the financial statement line item when disclosing fair value instruments in the hierarchy table, and
requires gross presentation in level 3 rollforward (purchases, sales, issuances, and settlements) effective January 1, 2011.
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We did not have any transfers between level 1 and 2. We disclose the fair value instruments by appropriate classes, as required by this standard. See Note 10. Fair Value Measurements for further information.
Variable Interest Entities for which PSE&G is the Primary Beneficiary
PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to the trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.
The assets and liabilities of these VIEs are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle the obligations of Transition Funding and Transition Funding II, respectively. The Transition Funding and Transition Funding II creditors do not have any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding and Transition Funding II, respectively.
PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of March 31, 2010 and December 31, 2009. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding and Transition Funding II during the first quarter of 2010 or in 2009. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.
Other Variable Interest
PSE&G has a long-term electricity and capacity purchase agreement with a potential VIE. We have requested the information necessary to determine whether the entity was a VIE and whether PSE&G is the primary beneficiary; however, the information has not been made available. Since the counterparty has not supplied PSE&G with electricity or capacity during the first quarter of 2010 or the 2009 year, we have not been required to make any payments. PSE&G is not subject to any risk of loss.
Variable Interest Entity for which Energy Holdings is the Primary Beneficiary
Energy Holdings has variable interests through its equity investment in a project for renewable energy where it is also the primary beneficiary. Energy Holdings has the power to direct the activities of the entity that most significantly impact the entity’s economic performance. Energy Holdings also has the obligation to fund up to $15 million in operating losses of the VIE through 2011. As of March 31, 2010, $7 million has been extended in the form of a note receivable.
As a result, Energy Holdings consolidates the assets and liabilities of this project which are disclosed below (excluding intercompany balances which are eliminated in consolidation):
As of
December 31,
Current Assets
Noncurrent Assets
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Other than the $15 million obligation to fund operating losses through 2011, Energy Holdings does not have any contractual or other obligation to provide additional financial support to the VIE. There are no third party debt obligations for this VIE.
Leveraged Leases
During the first quarter of 2010, Energy Holdings sold its interest in two leveraged leases, including one international lease for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.
During the first quarter of 2009, Energy Holdings sold its interest in four leveraged leases, including two international leases for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.
Proceeds from sales
Gain (Loss) on the sales, after-tax
Proceeds from the sales of the international leases was used to reduce the tax exposure related to these lease investments. For additional information see Note 7. Commitments and Contingent Liabilities.
NDT Funds
Power maintains an external master nuclear decommissioning trust to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.
Power classifies investments in the NDT Funds as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Funds:
Cost
GrossUnrealizedGains
GrossUnrealizedLosses
EstimatedFairValue
Equity Securities
Debt Securities
Government Obligations
Other Debt Securities
Total Debt Securities
Other Securities
Total Available-for-Sale Securities
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Gross
UnrealizedGains
Unrealized
Losses
The following table shows the value of securities in the NDT Funds that have been in an unrealized loss position for less than and greater than 12 months:
FairValue
Equity Securities(A)
Government Obligations(B)
Other Debt Securities(C)
Debt Securities (Corporate)—Power’s investments in corporate bonds are primarily with investment grade securities. It is not expected that these securities would settle at less than their amortized cost.
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The proceeds from the sales of and the net realized gains on securities in the NDT Funds were:
Three Months EndedMarch 31, 2010
Three Months EndedMarch 31, 2009
Proceeds from Sales
Net Realized Gains (Losses):
Gross Realized Gains
Gross Realized Losses
Net Realized Gains
Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in Power’s Consolidated Statement of Operations. Net unrealized gains of $98 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) in Power’s Condensed Consolidated Balance Sheet as of March 31, 2010.
The available-for-sale debt securities held as of March 31, 2010 had the following maturities:
Time Frame
Fair Value
Less than one year
1 - 5 years
6 - 10 years
11 - 15 years
16 - 20 years
Over 20 years
The cost of these securities was determined on the basis of specific identification.
Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through OCI. In 2010, other-than-temporary impairments of $1 million were recognized on securities in the NDT Funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is 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 detail of the securities.
Rabbi Trusts
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in grantor trusts commonly known as “Rabbi Trusts.”
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PSEG classifies investments in the Rabbi Trusts as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trusts.
EstimatedFair Value
Total PSEG Available-for-Sale Securities
UnrealizedLosses
The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. In the three months ended March 31, 2010 and 2009, proceeds from sales, realized gains and realized losses related to the Rabbi Trusts were immaterial.
The estimated fair value of the Rabbi Trusts related to PSEG, Power and PSE&G are detailed as follows:
Power
PSE&G
Note 6. Pension and OPEB
PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. The following table provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal
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subsidy expected for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. New Federal 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 12. Income Taxes for additional information.
Components of Net Periodic Benefit Costs:
Service Cost
Interest Cost
Expected Return on Plan Assets
Amortization of Net
Transition Obligation
Prior Service Cost
Actuarial Loss
Net Periodic Benefit Cost
Effect of Regulatory Asset
Total Benefit Costs, Including Effect of Regulatory Asset
Pension and OPEB costs for PSEG, Power and PSE&G are detailed as follows:
OPEB
Three Months EndedMarch 31,
Total Benefit Costs
PSEG Contributions to Pension Plans for Calendar Year 2010
Pension Plans
Postretirement Healthcare Plan
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Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
obtain credit.
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
Power believes the probability of this is unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Power is subject to
counterparty collateral calls related to commodity contracts, and
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
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The face value of outstanding guarantees, current exposure and margin positions as of March 31, 2010 and December 31, 2009 are shown below:
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 Received
In the event Power were to lose its investment grade rating:
Additional Collateral That Could be Required
Liquidity Available Under PSEG and Power’s Credit Facilities to Post Collateral
Additional Amounts Posted:
Other Letters of Credit
Power nets receivables and payables with the corresponding net energy contract balances. See Note 9. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Payable.
In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.
In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations.
Environmental Matters
Passaic River
Historic operations by PSEG companies along the Passaic and Hackensack rivers, and the operations of dozens of other companies, are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA and the EPA has determined to perform a study of the entire 17-mile tidal reach of the lower Passaic River.
PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former Manufactured Gas Plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.
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The EPA believes that hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group is presently executing the study. Approximately five percent of the study costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.
In 2007, the EPA released a draft “Focused Feasibility Study” that proposes six options to address the contamination cleanup of the lower eight miles of the Passaic River, with estimated costs from $900 million to $2.3 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study is expected to be released in 2010.
In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.
New Jersey Spill Compensation and Control Act (Spill Act)
In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of hazardous substances into the Passaic River. In February 2009, third party complaints were filed against some 320 third-party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances they allegedly discharged into the Passaic River. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. 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.
Natural Resource Damage Claims
In 2003, the NJDEP directed PSEG, PSE&G and 56 other PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the NJ Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain non-material 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 will continue in 2010.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding this study.
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PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be material.
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface water bodies that have been impacted by hazardous substances from adjoining sites. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant sites for cleanup. One of the sites identified was PSE&G’s former Camden Coke facility.
During the second quarter of 2009, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $704 million and $804 million from June 30, 2009 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $704 million in its Consolidated Balance Sheet as of June 30, 2009. Subsequent expenditures reduced the liability to $690 million as of March 31, 2010. Of this amount, $42 million was recorded in Other Current Liabilities and $648 million was reflected as Environmental Costs in Noncurrent Liabilities. As such, PSE&G has recorded a $690 million Regulatory Asset with respect to these costs.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act, require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The federal government may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.
In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Power’s generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter and mercury. The remaining projects necessary to implement this program are expected to be completed by the end of 2010 at an estimated cost of $200 million to $250 million for Mercer and $750 million to $800 million for Hudson, of which $793 million has been spent on both projects as of March 31, 2010.
In January 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were made at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.
Mercury Regulation
In 2005, the EPA established a limit for nickel emissions from oil fired electric generating units and a cap-and-trade program for mercury emissions from coal fired electric generating units.
In 2008, the United States Court of Appeals for the District of Columbia Circuit rejected the EPA’s mercury emissions program and required the EPA to develop standards for mercury and nickel emissions that adhere to
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the Maximum Available Control Technology (MACT) provisions of the Clean Air Act. In 2009, the EPA indicated that it intended to move forward with a rule-making process to develop MACT standards consistent with the Court’s ruling and agreed to finalize them by November 2011.
The full impact to PSEG of these developments is uncertain. It is expected that new MACT requirements will require more stringent control than the cap-and-trade program struck down by the D.C. Circuit Court; however, the costs of compliance with mercury MACT standards will have to be compared with the existing state mercury control requirements, as described below.
Pennsylvania
In 2007, Pennsylvania finalized its “state-specific” requirements to reduce mercury emissions from coal fired electric generating units. These requirements were more stringent than the EPA’s vacated Clean Air Mercury Rule but not as stringent as would be required by a MACT process. In 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it was inconsistent with the Clean Air Act. On December 23, 2009, the Commonwealth Court’s decision was affirmed by the Supreme Court of Pennsylvania. Unless the law in Pennsylvania is changed requiring the regulation of mercury by the Pennsylvania Department of Environmental Protection, then our Pennsylvania generating stations likely will be subject to regulation under the EPA’s MACT rule. It is uncertain whether the Keystone and Conemaugh generating stations will be able to achieve the necessary reductions at these stations with currently planned capital projects under a MACT regulation.
Connecticut
Mercury emissions control standards were effective in July 2008 and require coal fired power plants to achieve either an emissions limit or 90% mercury removal efficiency through technology installed to control mercury emissions. With the recently installed activated carbon injection and baghouse at Bridgeport Unit 3, Power has demonstrated that it complies with the mercury limits in these standards.
New Jersey
New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.
Power has achieved or will achieve the required reductions with mercury control technologies that are part of Power’s multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.
NOx Reduction
In April 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel fired electric generation units. The rule 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 five older New Jersey steam electric generation units (approximately 800 MW) by April 30, 2015.
Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time for it to address the retirement of electric generation units. Power cannot predict the financial impact resulting from compliance with this rulemaking.
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Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. On April 30, 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.
New Jersey Industrial Site Recovery Act (ISRA)
Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which is included in Environmental Costs in Power’s and PSEG’s Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009.
Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NPDES) permits expire within 5 years of their effective date. In order to renew these permits, but allow the plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. Power has filed or will be filing applications for permits in a variety of states that require discharge.
Pursuant to a consent decree with environmental groups, the EPA was required to promulgate rules governing cooling water intake structures under Section 316(b) of the FWPCA. In 2004, the EPA published a rule which did not mandate the use of cooling towers at large existing generating plants. Rather, the rule provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.
One of the most significant NPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the Phase II 316(b) rules published in 2004, which govern cooling water intake structures at large electric generating facilities. Power had historically used restoration and/or a site-specific cost-benefit test in applications it had filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer. However, the 316(b) rules would also have been applicable to Bridgeport, and possibly, Sewaren and New Haven stations. In addition to the Salem renewal application, permit renewal applications have been submitted to the NJDEP for Hudson and Sewaren and to the Connecticut Department of Environmental Protection for Bridgeport.
Portions of the 316(b) rule were challenged by certain northeast states, environmentalists and industry groups. In January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision that remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. In April 2009, the U.S. Supreme Court reversed the Second Circuit’s opinion, concluding that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations. The matter was sent back to the Second Circuit for further proceedings consistent with the Supreme Court’s opinion. In September 2009, the Second Circuit issued an order remanding the matter to the EPA in light of the Supreme Court’s opinion.
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The Supreme Court’s ruling allows the EPA to continue to use the site-specific cost-benefit test in determining best technology available for minimizing adverse environmental impact. However, the results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants could be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.
The EPA has stated that it anticipates proposing a rule in September 2010, and publishing a final rule in July 2012. Until a new rule governing cooling water intake structures at existing power generating stations is finalized, the EPA and states implementing the FWPCA have been instructed to issue permits on a case-by-case basis using the agency’s best professional judgment.
In addition to the anticipated EPA rulemaking, several states have begun setting policies that may require closed cycle cooling. It is unknown how these policies will ultimately be adopted and the impact of these state policies on 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. The draft permit is subject to public comment and review prior to being finalized by the NJDEP. We 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.
Stormwater
In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has determined that Hudson is no longer eligible to utilize this general permit and must apply for an individual NJPDES permit for stormwater discharges. While the full extent of these requirements remains unclear, to the extent Power may be required to reduce or eliminate the exposure of coal to stormwater, or be required to construct technologies preventing the discharge of stormwater to surface water or groundwater, those costs could be material.
New Generation and Development
Nuclear
Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at Peach Bottom Units 2 and 3. Completion of these upgrades is expected to result in an increase of Power’s share of nominal capacity by 32 MW (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). Total expenditures through March 31, 2010 are $28 million and are expected to continue through 2012. Power anticipates expenditures in pursuit of additional output through an extended power uprate of its co-owned Peach Bottom nuclear plants. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Power’s share of the increased capacity is expected to be 133 MW with an anticipated cost of approximately $400 million.
Power has been selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval has been received and construction is expected to
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commence in June 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $130 million to $140 million. Total capitalized expenditures through March 31, 2010 are $15 million, which are included in Property, Plant and Equipment in the Condensed Consolidated Balance Sheets of PSEG and Power.
PJM Interconnection L.L.C. (PJM)
Power plans to construct 178 MW of gas fired peaking capacity at the Kearny site. This capacity was bid into and has cleared the PJM RPM base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to commence in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $160 million to $200 million. Total capitalized expenditures through March 31, 2010 are $8 million which are included in Property, Plant and Equipment in Power’s and PSEG’s Condensed Consolidated Balance Sheets.
PSE&G—Solar
In January 2010, PSE&G announced that it has entered into contracts with four developers for 12 MW of solar capacity to be developed on land it owns in Edison, Linden, Trenton and Hamilton. The projects represent an investment of approximately $50 million. Construction is expected to start in the second quarter of 2010 pending receipt of necessary approvals.
Solar Source
Energy Holdings has developed a solar project in western New Jersey and has acquired two additional solar projects currently under construction in Florida and Ohio, which together have a total capacity of approximately 29 MW. Completion of the additional projects is expected by the third quarter of 2010. Energy Holdings has issued guarantees of up to $28 million for payment of obligations related to the construction of these two projects. These guarantees will terminate upon successful completion of the projects. The total investment for the three projects will be approximately $114 million.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above. In addition to the BGS-related contracts, Power also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.
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PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:
2007
2008
36-Month Terms Ending
Load (MW)
$ per kWh
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 16. Related-Party Transactions.
Minimum Fuel Purchase Requirements
Power has various long-term fuel purchase commitments for coal and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.
Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
Power’s strategy is to maintain certain levels of uranium concentrates and uranium hexafluoride in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below may include estimated quantities to be purchased that deviate from contractual nominal quantities.
Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2011 and a portion for 2012, 2013 and 2014 at Salem, Hope Creek and Peach Bottom.
As of March 31, 2010, the total minimum purchase requirements included in these commitments are as follows:
Fuel Type
Commitmentsthrough 2014
Power’s Share
Nuclear Fuel
Uranium
Enrichment
Fabrication
Natural Gas
Coal/Oil
Included in the $806 million commitment for coal and oil above is $503 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. There have been no cancellations in 2010.
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The Texas generation facilities also have a contract for low BTU content gas which commenced in late 2009 with a term of 15 years and a minimum volume of approximately 13 MMbtus per year. The gas must meet an availability and quality specification. Power has the right to cancel delivery of the gas at a minimal cost.
Regulatory Proceedings
Competition Act
In April 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.
In July 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In July 2007, PSE&G filed a motion to dismiss the amended Complaint, which was granted in October 2007. In November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Division’s decision.
In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition, which remains pending. PSE&G cannot predict the outcome of the action pending at the BPU.
BPU Deferral Audit
The BPU Energy and Audit Division conducts audits of deferred balances under various adjustment clauses. A draft Deferral Audit Phase II report relating to the 12-month period ended July 31, 2003 was released to the BPU in April 2005.
That report, which addresses Societal Benefits Charges (SBC), Market Transition Charge (MTC) and non-utility generation (NUG) deferred balances, found that the Phase II deferral balances complied in all material respects with applicable BPU Orders. It also noted that the BPU Staff had raised certain questions with respect to the reconciliation method PSE&G had employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition period. The matter was referred to the Office of Administrative Law. The amount in dispute is $114 million, which if required to be refunded to customers with interest through March 2010, would be $142 million.
In January 2009, the administrative law judge (ALJ) issued a decision which upheld PSE&G’s central contention that the 2004 BPU Order approving the Phase I settlement resolved the issues being raised by the Staff and the NJ Division of Rate Counsel, and that these issues should not be subject to re-litigation in respect of the first three years of the transition period. The ALJ’s decision stated that the BPU could elect to convene a separate proceeding to address the fourth and final year reconciliation of MTC recoveries. The amount in dispute with respect to this Phase II period is approximately $50 million.
By order dated September 3, 2009, the BPU rejected the ALJ’s initial decision, elected to maintain jurisdiction over the matter and established a schedule for briefing on the merits of the question whether any MTC-related refunds are due. Generally, the BPU rejected the claims that the matters at issue had been fairly and finally litigated. Briefing has been completed and the matter is now pending before the BPU.
New Jersey Clean Energy Program
In 2008, the BPU approved funding requirements for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2
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billion for all years. PSE&G’s share is $705 million. PSE&G has recorded a discounted liability of $527 million as of March 31, 2010. Of this amount, $178 million was recorded as a current liability and $349 million as a noncurrent liability. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC.
Leveraged Lease Investments
The Internal Revenue Service (IRS) has issued reports with respect to its audits of PSEG’s federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.
PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, four of which were decided in favor of the government. An appeal of one of these decisions was affirmed. The fifth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.
In order to reduce the cash tax exposure related to these leases, Energy Holdings is pursuing opportunities to terminate international leases with lessees that are willing to meet certain economic thresholds. Energy Holdings has terminated a total of 14 of these leasing transactions since December 2008 and reduced the related cash tax exposure by $740 million. As of March 31, 2010 and December 31, 2009, PSEG’s total gross investment in such transactions was $278 million and $347 million, respectively.
Cash Impact
As of March 31, 2010, an aggregate of approximately $600 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, reducing its potential cash exposure to $280 million. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $70 million to $90 million of tax would be due for tax positions through March 31, 2010.
As of March 31, 2010, penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at the rate of $6 million per quarter during 2010.
PSEG currently anticipates that it may be required to pay between $110 million and $290 million in tax, interest and penalties for the tax years 1997-2000 during 2010 and subsequently commence litigation to recover those amounts. Further it is possible that an additional payment of between $210 million and $530 million could be required during 2010 for tax years 2001-2003 followed by further litigation to recover those amounts. These amounts are in addition to tax deposits already made.
Earnings Impact
PSEG’s current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer proposed by the IRS, would result in an additional earnings charge of $140 million to $160 million.
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The following capital transactions occurred in the first three months of 2010:
converted $44 million of its senior Notes servicing and securing the 4.00% Pollution Control Bonds of the Pennsylvania Economic Development Authority (PEDFA) to variable rate in January 2009 when the PEDFA Bonds were converted to variable rate demand bonds. Power reacquired the PEDFA Bonds in December 2009. In January 2010, Power caused the PEDFA Bonds to be converted from Alternative Minimum Tax (AMT) to non-AMT status and to be remarketed as variable rate demand bonds backed by a letter of credit expiring in January 2011.
paid a cash dividend of $175 million to PSEG in March.
redeemed all of its $80 million of outstanding preferred stock in March,
paid $300 million of floating rate (Libor + .875%) First and Refunding Mortgage Bonds at maturity in March,
issued $300 million of 5.50% Medium-Term Notes (MTNs), Series G due March 2040 in March, and
paid $44 million of Transition Funding’s securitization debt.
Energy Holdings
paid $1 million of nonrecourse project debt.
In April 2010, Power issued $300 million of 2.50% unsecured Senior Notes due April 2013 and $250 million of 5.125% unsecured Senior Notes due April 2020. Power used a portion of the proceeds from these transactions to redeem its $161 million of 6.50% MTNs due 2014 and $48 million of 6.00% MTNs due 2013.
Also in April 2010, Power completed an exchange offer with eligible holders of its 7.75% Senior Notes due 2011 in order to manage long-term debt maturities. Under this transaction, an aggregate principal amount of $195 million of Power’s 7.75% Senior Notes was exchanged for total consideration from Power of $208 million. The $208 million was comprised of $156 million in newly issued 5.125% Senior Notes due April 2020 and cash payments of $52 million. Since the debt exchange was treated as a debt modification, the resulting premium of $13 million was deferred and will be amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on Power’s Condensed Consolidated Balance Sheet.
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Commodity Prices
The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events.
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Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists. The financial effect of using such modeling techniques is not material to PSEG’s or Power’s financial statements.
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps, futures and firm transmission right contracts to hedge
forecasted energy sales from its generation stations and the related load obligations and
the price of fuel to meet its fuel purchase requirements.
These derivative transactions are designated and effective as cash flow hedges. As of March 31, 2010 and December 31, 2009, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:
Fair Value of Cash Flow Hedges
Impact on Accumulated Other Comprehensive Income (Loss) (after tax)
The expiration date of the longest-dated cash flow hedge at Power is in 2012. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the 12 months ending March 31, 2011 and March 31, 2012 are $167 million and $93 million, respectively. Ineffectiveness associated with these hedges was $(2) million at March 31, 2010.
Trading Derivatives
In general, the main purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Power does engage in some trading of electricity and energy-related products where such transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned generation. Such trading activities represent approximately one percent of Power’s gross margin.
Other Derivatives
Power enters into other contracts that are derivatives, but do not qualify for cash flow hedge accounting. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Prior to June 2009, some of the derivative contracts were also used in Power’s NDT Funds. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of March 31, 2010 and December 31, 2009 was $105 million and $8 million, respectively.
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed through the use of fixed and floating rate debt and interest rate derivatives.
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Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. In January 2010, we entered into a series of interest rate swaps totaling $600 million converting $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and $300 million of Power’s $600 million of 6.95% of Senior Notes due June 2012 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. In 2009 PSEG had entered into three interest rate swaps also designated as fair value hedges. As of March 31, 2010 and December 31, 2009, the fair value of all the underlying hedges was $5 million and $(3) million, respectively.
PSEG, Power, PSE&G and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of March 31, 2010, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of March 31, 2010 and December 31, 2009. The Accumulated Other Comprehensive Loss related to interest rate derivatives designated as cash flow hedges was $(4) million as of each of March 31, 2010 and December 31, 2009.
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments in the Consolidated Balance Sheets:
Balance Sheet Location
Total Mark-to-Market Derivative Assets
Current Liabilities
Noncurrent Liabilities
Total Mark-to-Market Derivative (Liabilities)
Total Net Mark-to-Market Derivative Assets (Liabilities)
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The aggregate fair value of derivative contracts in a liability position as of March 31, 2010 that contain triggers for additional collateral was $773 million. This potential additional collateral is included in the $968 million discussed in Note 7. Commitments and Contingent Liabilities.
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The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended March 31, 2010 and 2009:
Derivatives in SFAS 133Cash Flow HedgingRelationships
PSEG
Energy-Related Contracts
Interest Rate Swaps
Total PSEG
PSEG Power
Total Power
The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis:
Balance as of December 31, 2009
Gain Recognized in AOCI (Effective Portion)
Less: Gain Reclassified into Income (Effective Portion)
Balance as of March 31, 2010
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The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months ended March 31, 2010 and 2009:
Derivatives Not Designated as Hedges
PSEG and Power
Derivatives in NDT Funds
Total PSEG and Power
Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of those contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load.
In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges for the three months ended March 31, 2010 was to reduce interest expense by approximately $6 million.
The following reflects the gross volume, on an absolute value basis, of derivatives as of March 31, 2010 and December 31, 2009:
Type
Notional
Total
As of March 31, 2010
Electricity
Capacity
FTRs
Emissions Allowances
Oil
Renewable Energy Credits
As of December 31, 2009
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Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.
In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s financial condition, results of operations or net cash flows. As of March 31, 2010, 97% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Power’s operations was with investment grade counterparties.
The following table provides information on Power’s credit risk from others, net of collateral, as of March 31, 2010. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the quality of the company’s credit risk by credit rating of the counterparties.
Rating
CurrentExposure
Securitiesheld asCollateral
NetExposure
Number ofCounterparties>10%
Net Exposure ofCounterparties>10%
Investment Grade—External Rating
Non-Investment Grade—External Rating
Investment Grade—No External Rating
Non-Investment Grade—No External Rating
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 March 31, 2010, Power had 200 active counterparties.
PSEG, Power and PSE&G adopted accounting guidance for “Fair Value Measurements” for financial assets and liabilities effective January 1, 2008 and for nonrecurring fair value measurements of non-financial assets and liabilities effective January 1, 2009. The fair value measurements guidance defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that
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distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1—measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.
Level 2—measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3—measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various financial transmission rights, other longer term capacity and transportation contracts and certain commingled securities.
In addition to establishing a measurement framework, the fair value measurement guidance nullified the prior guidance which did not allow an entity to recognize an unrealized gain or loss at the inception of a derivative instrument unless the fair value of that instrument was obtained from a quoted market price in an active market or was otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique incorporating observable market data.
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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 at March 31, 2010 and December 31, 2009, 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.
Recurring Fair Value Measurements as of March 31, 2010
Description
CashCollateralNetting(E)
Quoted
Market
PricesforIdentical
Assets(Level 1)
SignificantOtherObservableInputs(Level 2)
SignificantUnobservableInputs
(Level 3)
Assets:
Derivative Contracts:
Energy-Related Contracts(A)
Interest Rate Swaps(B)
NDT Funds:(C)
Debt Securities—Govt Obligations
Debt Securities—Other
Rabbi Trusts—Mutual Funds(C)
Other Long-Term Investments(D)
Liabilities:
NDT Funds(C)
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Recurring Fair Value Measurements as of December 31, 2009
Quoted MarketPrices ofIdentical Assets(Level 1)
Interest Rate Swaps (B)
Debt Securities-Government
Obligations
Debt Securities-Other
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 midpoint 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
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We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.
Power’s investments in fixed income securities are primarily with investment grade corporate bonds and US Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities. (primarily Level 2). Short-term investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2). Certain commingled cash equivalents included in temporary investment funds are measured with significant unobservable inputs and internal assumptions (primarily Level 3). The Rabbi Trust mutual funds are mainly invested in a US Bond Index fund, an S&P 500 Index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).
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A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended March 31, 2010
Included inIncome(A)
Included inRegulatory Assets/Liabilities(B)
Net Derivative Assets
Rabbi Trust Funds
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis for the Three Months Ended March 31, 2009
Included inIncome(C)
Net Derivative Liabilities
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As of March 31, 2010, PSEG carried approximately $1.694 billion of net assets that are measured at fair value on a recurring basis, of which approximately $285 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers between levels during the three months ended March 31, 2010.
As of March 31, 2009, PSEG carried approximately $943 million of net assets that are measured at fair value on a recurring basis, of which approximately $203 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEG’s total assets and there were no significant transfers in or out of Level 3 during the three months ended March 31, 2009.
Fair Value of Debt
The estimated fair values were determined using market quotations or values of instruments with similar terms, credit ratings, remaining maturities, and redemptions as of March 31, 2010 and December 31, 2009.
PSEG (Parent)
Transition Funding (PSE&G)
Transition Funding II (PSE&G)
Energy Holdings:
Senior Notes
Project Level, Non-Recourse
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NDT Fund Gains, Interest, Dividend and Other Income
Total Other Income
NDT Fund Losses and Expenses
Total Other Deductions
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Effective Tax Rate
The change in PSEG’s and Power’s effective tax rates were due primarily to the impacts of new health care legislation enacted in March 2010 and increased earnings related to the NDT Funds. The new legislation includes various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. Although this change does not take effect immediately, the accounting impact must be recognized when the legislation is signed. As a result, in the first quarter of 2010, PSEG recorded noncash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G’s income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.
Unrecognized Tax Benefits
As ofMarch 31, 2010
Possible Increase (Decrease) in Total Unrecognized
Tax Benefits Including interest
Over the next12 Months
Services
PSEG and PSE&G have unrecognized tax benefits as of March 31, 2010. PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to the Long-Term Accrued Taxes in PSEG’s Condensed Consolidated Balance Sheets, but are not reflected in the PSEG unrecognized tax benefits. PSEG materially reduced its unrecognized tax benefits by terminating some leases involved in the IRS lease issue. (see Note 7. Commitments and Contingent Liabilities).
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It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 7. Commitments and Contingent Liabilities will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase or decrease. It is not possible to predict the magnitude, timing or direction of any such change.
It is reasonably possible that the total unrecognized tax benefits (including interest) at PSEG will decrease within the next 12 months due to either agreement with various taxing authorities upon audit or the expiration of the Statute of Limitations.
Comprehensive Income
Other Comprehensive Income
Balance as ofDecember 31, 2009
Balance as ofMarch 31, 2010
Three Months Ended March 31, 2010
Pension and OPEB Plans
Accumulated Other Income (Loss)
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Balance as ofDecember 31, 2008
Balance as ofMarch 31, 2009
Three Months Ended March 31, 2009
Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
Basic
Diluted
EPS Numerator (Millions):
EPS Denominator (Thousands):
Weighted Average Common Shares Outstanding
Effect of Stock Options
Effect of Stock Performance Share Units
Effect of Restricted Stock Units
Total Shares
EPS:
Three Months Ended
Dividend payments on Common Stock
Per Share
in Millions
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EnergyHoldings
Other(A)
Consolidated
Total Operating Revenues
Preferred Securities Dividends
Segment Earnings
Gross Additions to Long-Lived Assets
Net Income (Loss)
Segment Earnings (Loss)
Total Assets
Investments in Equity Method Subsidiaries
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The following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
The financial statements for Power include transactions with related parties presented as follows:
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
March 31, 2010
December 31, 2009
Receivables from PSE&G through BGS and BGSS Contracts(A)
Receivables from PSE&G Related to Gas Supply Hedges for BGSS(A)
Payable to Services(B)
Tax Sharing Payable to PSEG(C)
Current Unrecognized Tax Receivable from PSEG(C)
Payable to PSEG
Short-Term Loan to (from) Affiliate (Demand Note to (from) PSEG)(D)
Long-Term Accrued Taxes Receivable(C)
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The financials statements for PSE&G include transactions with related parties presented as follows:
Billings From Power through BGSS(A)
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)
Tax Sharing Receivable from (Payable to) PSEG(C)
Receivable from PSEG
Working Capital Advances to Services(E)
Long-Term Accrued Taxes Payable(C)
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Each series of Power’s Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). The following table presents condensed financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries.
Operating Revenues
Operating Expenses
Operating Income
Equity Earnings (Losses) of Subsidiaries
Income Tax Benefit (Expense)
Net Cash Provided By (Used In) Operating Activities
Net Cash Provided By (Used In) Investing Activities
Operating Income (Loss)
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Property, Plant and Equipment, net
Investment in Subsidiaries
Member’s Equity
Total Liabilities and Member’s Equity
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This combined MD&A is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG’s business consists of three reportable segments, which are:
Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid Atlantic U.S.,
PSE&G, our public utility company which provides transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and
Energy Holdings, which owns our energy-related leveraged leases and other investments.
Our business discussion in Part I Item 1 Business of our 2009 Annual Report on Form 10-K provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets. The following supplements that discussion and the discussion included in the Overview of 2009 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2010 and any changes to the key factors that we expect will drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2009 Annual Report on Form 10-K.
OVERVIEW OF 2010 AND FUTURE OUTLOOK
During 2010, our business continues to face many of the same challenges experienced in 2009, including lower sales volumes, resulting primarily from milder weather and current economic conditions, and low natural gas prices.
Milder weather in the first quarter of 2010 as compared to the same period in the prior year resulted in an overall reduction of approximately 11% in Power’s BGSS sales volumes.
Recent market conditions resulted in an increasing number of customers choosing to contract with independent electric suppliers rather than remain under the BGS contracts which has negatively affected generation margin. This trend began toward the second half of 2009 and increased throughout last year. Migration levels have been relatively stable in 2010. This migration away from BGS could be sustained or increase if energy prices continue to be lower than the energy price component of the BGS contracts.
Our distribution operations were also impacted by the mild weather conditions in 2010. Our gas and electric delivery volumes for 2010 declined by 7% and 1%, respectively. Heating degree days, as a measure of winter weather in 2010, were 10.5% lower than in 2009.
Current economic conditions have also caused deterioration in certain customer payment patterns resulting in a higher portion of our accounts receivable balances remaining outstanding for more than 180 days. However, customer payment patterns have modestly improved during 2010 with such balances representing 10% of total customer accounts receivable as of March 31, 2010 as compared to 14% as of December 31, 2009. We are focusing our efforts on the oldest and largest accounts to expedite collections. We believe we have sufficient liquidity to manage these delays in customer payments.
There have also been significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted.
One of the new issues impacting our business during the quarter was the passage of new health care legislation in March. This legislation includes various health care related provisions which will go into effect over the next several years including, but not limited to, expanding insurance coverage
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eligibility, prohibiting denial of coverage based on pre-existing conditions and prohibiting restrictive annual and lifetime coverage limits. This legislation also eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. Although this tax change does not take effect immediately, we were required to recognize the full accounting impact in our financial statements when the legislation was signed. As a result, in the first quarter of 2010, we recorded noncash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&G’s income tax expense since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods. We are still evaluating the other potential impacts of this legislation as well as any actions we could take to offset any resulting increases to our health care costs.
There are also continuing discussions regarding various legislative proposals that have been made with the intention of enacting stricter regulation over derivatives in light of the financial market issues experienced last year, largely caused by derivative trading in connection with mortgage loans. It is difficult to predict what the final legislation might contain. If the final legislation required all trading to be done over an exchange, we would expect to see our collateral requirements increase substantially to support our activities.
Our future success will also depend on our ability to respond to the challenges and opportunities presented by these and other regulatory and legislative initiatives.
Operational Excellence
While BGS sales volumes were down for Power as compared to prior year due to migration and weather impacts, these reductions were offset with sales under new contracts and in the spot market. As a result, generation volumes at Power in 2010 were approximately 7% higher than in 2009, primarily at its combined cycle facilities. Migration has resulted and could continue to result in reduced margins as volumes that were previously sold to satisfy obligations under the BGS contracts are replaced with spot market sales at lower prices. Looking forward, continued lower market prices and reduced demands are likely to result in lower margins for our business.
During 2010, PSE&G continued to demonstrate its commitment to system reliability by limiting customer outages. However, in mid-March, PSE&G experienced the worst storm in its history. The storm caused severe damage to our system downing more than 1,000 poles throughout our service territory and disrupting service to about 635,000 customers. With the assistance of mutual aid crews from other utilities, PSE&G’s associates worked to fully restore service to all of its customers within one week. Total storm related costs during the first quarter of 2010 were over $41 million, including $16 million of capitalized costs and $9 million of incremental costs for which PSE&G will be seeking deferral and recovery.
We have looked, and are continuing to look, for ways to reduce our operating costs while maintaining our safety, reliability and environmental standards.
Financial Strength
Our businesses continued to generate strong cash from operations in 2010. We used these funds combined with external financing to:
contribute $332 million into our qualified pension plans through April 2010,
fund our capital expenditures, and
continue funding our shareholder dividends.
In February 2010, the Board of Directors approved an increase in the first quarter dividend from $0.3325 per share to $0.3425 per share of Common Stock.
We also completed several financing transactions during 2010, including paying our maturing debt obligations, redeeming PSE&G’s preferred stock and completing a debt exchange at Power to manage long-term debt maturities. See Note 8. Changes in Capitalization for additional information.
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Disciplined Investment
We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include responding to climate change, upgrading critical energy infrastructure and providing new energy supplies in markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance and meet environmental commitments.
We are continuing to pursue obtaining the necessary regulatory approvals for the estimated $750 million Susquehanna-Roseland transmission project. Subject to obtaining certain environmental approvals, PSE&G plans to begin construction of the eastern portion of the project this summer. The eastern portion of the project is currently expected to be in service by June 2012. Construction of the western portion of the project toward the Delaware River would begin at a later time, subject to necessary regulatory approvals, with a targeted completion date of the end of 2013. Any failure to obtain necessary approvals on a timely basis, however, could delay the project’s completion date.
We made additional investments in our solar initiatives. As of March 31, 2010 we have provided $49 million in loans for 78 projects representing 13.3 MW under our solar loan program. As of March 31, 2010, 2.7 MW of solar panels had been installed on distribution poles under our Solar 4 All program with total expenditures of $23 million. In January 2010, we announced that we had entered into contracts with four developers for 12 MW of solar capacity to be developed on land we own in Edison, Linden, Trenton and Hamilton. The projects represent an investment of approximately $50 million. Construction is expected to start in the second quarter following receipt of necessary approvals.
We made additional expenditures under our Capital Economic Stimulus and Energy Efficiency Economic Stimulus programs. As of March 31, 2010, total expenditures since inception of these projects were $240 million and $15 million, respectively.
We continued various construction activities at Power, including installation of back end technology at our Mercer and Hudson stations, a steam path retrofit and extended power uprate at Peach Bottom and construction of new gas fired peaking at Kearny and in Connecticut (see Note 7. Commitments and Contingent Liabilities for additional information). Work has also continued on preparing an application for an Early Site Permit (ESP) for a new nuclear generating station to be located at the current site of the Salem and Hope Creek generating stations. We anticipate submitting the application to the NRC for the ESP in the second quarter of 2010.
We continued construction of two solar projects in Florida and Ohio totaling 27 MW (see Note 7. Commitments and Contingent Liabilities for additional information).
There is no guarantee that these or future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals and funding of construction or development costs.
We receive immediate recovery of our transmission investments and costs through our FERC-approved formula transmission rate. The formula rate mechanism provides for an annual setting of our transmission rates, as well as an annual true up, to ensure timely recovery of the actual costs of providing transmission service and PSE&G’s approved return on equity. Approximately $23 million in increased revenues was accepted as part of our 2010 transmission rates.
In March 2010, we filed briefs in our base rate case supporting an increase in electric and gas distribution base rates totaling $204 million. The New Jersey Division of Rate Counsel has filed a brief in March recommending that PSE&G receive a total increase of $20 million in electric and gas distribution rates. A reply brief filed by the BPU Staff in April 2010 supported the New Jersey Division of Rate Counsel’s recommendations. We are currently conducting settlement discussions with the parties involved. If a settlement is not reached, we expect to receive a decision from the Administrative Law Judge later in May with a final BPU decision expected around mid-year. Inability to obtain an adequate return on our investments would have a material adverse impact on our current business and our future investment plans.
We anticipate that any current spending under the Capital Economic Stimulus Program will be included in our rate base with the expected decision in our Base Rate Case and that we will continue to receive
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contemporaneous recovery of future expenditures under this program with the return on equity adjusted to reflect the rate allowed in the Base Rate Case. The recovery mechanisms approved by the BPU for our Solar 4 All, Solar Loan, Energy Efficiency and Demand Response programs are scheduled to be reset on January 1 of each year, with the return on equity to be adjusted to reflect the rate allowed in the Base Rate Case at the time of the BPU Order.
RESULTS OF OPERATIONS
The results for PSEG, PSE&G, Power and Energy Holdings for the three months ended March 31, 2010 and 2009 are presented below:
Earnings (Losses)
PSEG Income from Continuing Operations
PSEG Net Income
Earnings Per Share (Diluted)
Our results include the realized gains, losses and earnings on Power’s NDT Funds and other related activity. This includes the net realized gains and other-than-temporary impairments, as well as interest and dividend income and other costs related to the NDT Funds which are recorded in Other Income and Deductions. This also includes the interest accretion expense on Power’s nuclear asset retirement obligation, which is recorded in Operation and Maintenance Expense and the Depreciation expense related to the asset retirement obligation.
Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity.
The quarter-over-quarter increases in our Income from Continuing Operations reflect the changes related to NDT and MTM shown in the chart below:
NDT Fund Income (Expense)
Non-Trading Mark-to-Market Gains (Losses)
Offsetting these increases were
lower earnings on generation sales reflecting lower prices realized, as reduced volumes sold under BGS contracts were replaced by comparatively lower prices realized on increased volumes being sold into the various power pools and under new wholesale contracts entered into during 2010,
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losses on certain wholesale electric energy supply contracts, and
lower gas sales volumes and pricing due to milder weather and economic conditions.
Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, donations and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 16. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below.
Increase/(Decrease)
2010 vs 2009
Other Income and (Deductions)
As discussed in Note 1. Organization and Basis of Presentation, Power’s results have been retrospectively adjusted to include the earnings related to PSEG Texas for prior periods.
Income from Continuing Operations
For the three months ended March 31, 2010, the primary reasons for the $50 million increase in Income from Continuing Operations were
favorable amounts related to our NDT and MTM activity discussed previously, and
lower interest expense due to higher capitalization of interest related to projects in 2010,
partially offset by lower earnings on generation sales reflecting lower prices realized, as reduced volumes sold under BGS contracts were replaced by comparatively lower prices realized on increased volumes being sold into the various power pools and under new wholesale contracts entered into during 2010,
losses on certain wholesale electric energy supply contracts,
lower gas sales volumes and pricing due to milder weather and economic conditions, and
higher maintenance costs due to higher outage work in 2010 at certain of our fossil stations.
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The quarter-over-quarter details for these variances are discussed below:
For the three months ended March 31, 2010 as compared to 2009
Operating Revenues decreased $161 million due to
Gas Supply revenues decreased $245 million
including a net decrease of $215 million resulting from sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales caused by milder weather in 2010 and lower net gains on financial hedging transactions in 2010, and
a net decrease of $30 million due to reduced sales volumes to third party customers.
Generation revenues increased $109 million due primarily to
higher revenues of $119 million resulting from higher volumes of generation sold at lower prices in PJM and the NY power pool, higher prices on a relatively level volume of generation sold in the Texas power pool (ERCOT), and favorable results from financial hedging transactions, partially offset by lower prices on a lower volume of generation sold in the NE power pool,
an increase of $40 million from new wholesale load contracts commencing in 2010 partially offset by the expiration of certain previously existing wholesale load contracts,
$22 million of increased revenues from operating reserves mainly in the PJM region and various ancillary services, and $12 million of higher capacity payments largely due to changes in PJM’s capacity market,
partially offset by a net decrease of $74 million due to a lower volume of electricity sold under our BGS contracts partially offset by higher prices, and
a decrease of $9 million in auction revenue rights reflecting lower rates in PJM and migration of customers to alternative suppliers in 2010.
Trading revenues decreased $25 million due primarily to losses on certain electric energy supply contracts.
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased by $200 million due to
Gas costs decreased $235 million, reflecting net decreases of $216 million and $19 million related to Power’s obligations under the BGSS contract and sales to third party customers, respectively, reflecting lower demand due mainly to warmer average temperatures during the winter heating season in 2010 and lower inventory costs.
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Generation costs increased by $35 million due to $63 million of higher fossil fuel costs, primarily reflecting the utilization of higher volumes of natural gas and coal and $15 million for increased power purchases, partly offset by net gains of $44 million from financial hedging transactions.
Operation and Maintenance increased $11 million due primarily to
a net increase of $20 million due to planned outage costs in 2010 at the Guadalupe and Bethlehem Energy Center fossil stations in Texas and New York, respectively, partially mitigated by lower planned maintenance at certain of our other fossil stations,
partially offset by a $9 million net decrease primarily related to lower ARO accretion and reduced labor and fringe benefit costs.
Depreciation and Amortization decreased $3 million due to
a decrease of $6 million due to an increase in the remaining useful lives of the Mercer and Hudson generating facilities resulting from significant plant upgrades,
partially offset by an increase of $3 million due to pollution control equipment being placed into service in May through October of 2009 at our Burlington, Essex and Keystone stations.
Other Income and (Deductions)-Net Other Income increased $5 million due primarily to higher earnings related to our NDT Fund.
Other-Than-Temporary Impairments decreased $59 million due to the lower charges in 2010 related to the NDT Fund securities.
Interest Expense decreased $10 million due to
higher capitalized interest of $6 million due primarily to increased projects under construction in 2010 at Nuclear and Fossil, and
lower interest expense of $9 million due to the maturity of $250 million of 3.75% Notes in April 2009 and redemption of PSEG Texas project loans in February 2009,
partially offset by $5 million of higher interest expense in 2010 related to the issuance of $209 million of medium-term notes in January 2009 and $303 million of notes issued in September 2009 as part of a debt exchange with Energy Holdings.
Income Tax Expenseincreased $55 million in 2010 due primarily to
an increase of $43 million due to higher pre-tax income,
an increase of $8 million due to the impacts of new health care legislation (see Note 12. Income Taxes), and
an increase of $5 million related to higher earnings related to the NDT Funds.
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For the three months ended March 31, 2010, the primary reasons for the $6 million decrease in Income from Continuing Operations were
lower revenues due to lower customer demand due primarily to milder weather, and
higher Operation and Maintenance expense, primarily related to storm costs,
partially offset by a transmission formula rate increase.
Operating Revenues decreased $291 million due primarily to
Commodity Revenue decreased $319 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 $189 million due to decreased BGSS prices of $112 million and lower BGSS volumes of $77 million due to weather and economic conditions. The average price of gas was 12% lower in 2010 than 2009.
Electric revenues decreased $130 million due primarily to $138 million in lower BGS revenues, partially offset by $9 million in higher non-utility generation (NUG) revenue due to higher prices and volume. BGS sales were down 16% due primarily to large customer migration to Third Party Suppliers (TPS), in contrast delivery sales were only down 2% due to the weather and economic conditions.
Delivery Revenues increased $20 million due primarily to an increase in prices for electric distribution and transmission partially offset by a decrease in gas distribution.
Electric distribution revenues were up $12 million due primarily to rate increases of $16 million, partially offset by lower sales volumes of $4 million. The volumes were down due to weather and economic conditions. Rates were up due primarily to an increase in Regional Greenhouse Gas Initiative (RGGI) revenues, $7 million, and stimulus revenues, $7 million.
Transmission revenues were up $14 million due primarily to net rate increases.
Gas distribution revenues were down $6 million due primarily to lower sales volumes of $15 million partially offset by increased RGGI revenues of $3 million and revenues from our capital stimulus program of $8 million.
Other Operating Revenues increased $3 million due primarily to increased revenues from our appliance repair business.
Clause Revenues increased by $5 million due to higher Securitization Transition Charge (STC) $15 million, which was offset by interest and amortization charges, partially offset by lower Societal Benefits Charges (SBC) of $10 million, which was entirely offset by the amortization of related costs (Regulatory Assets) into the Operation and Maintenance accounts, and the Depreciation and Amortization accounts. PSE&G earns no margins on SBC or STC collections.
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Energy Costs decreased $319 million. This is entirely offset by Commodity Revenue. Details are as follows:
Gas costs decreased $189 million due to $112 million or 11% in lower prices and by $77 million or 8% in lower sales volumes due primarily to weather and economic conditions.
Electric costs decreased $130 million due to $124 million or 15% in lower BGS and NUG volumes due to large customer migration to TPS, weather and economic conditions and $6 million in lower BGS and NUG prices.
Operation and Maintenance increased $19 million due primarily to
higher expenses related to RGGI and Capital Adjustment Charges (CAC) of $19 million, and
$15 million of higher labor and benefits, primarily increased storm restoration work, partially offset by lower pension expense,
partially offset by decreases in electric and gas Universal Service Fund (USF) expenses of $16 million.
Depreciation and Amortization increased $28 million due to
an increase of $23 million for amortization of regulatory assets,
an increase of $3 million for additional plant in service, and
an increase of $2 million in software amortization.
Other Income and (Deductions)-Net Other Income increased $4 million due primarily to higher investment income.
Interest Expense decreased by $2 million due primarily to lower average debt balances.
Income Tax Expense decreased by $5 million due primarily to lower pre-tax income.
For the three months ended March 31, 2010, the primary reasons for the $4 million decrease in Income from Continuing Operations were
lower gains on the sales of leveraged lease assets, and
lower income from equity method investments,
partially offset by lower interest expense due primarily to lower debt balances following the debt exchange with Power in 2009.
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Operating Revenues decreased $8 million due primarily to lower gains on the sale and termination of leveraged lease assets and the resultant loss of revenues previously generated by such assets.
See Note 7. Commitments and Contingent Liabilities for additional information.
Income from Equity Method Investments decreased $7 million due primarily to lower pre-tax earnings at GWF Power and reserves against GWF Energy.
Interest Expense decreased $10 million due primarily to lower debt balances following the debt exchange with Power.
Income Tax Expense decreased $3 million due primarily to lower pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.
Operating Cash Flows
Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund capital expenditures and shareholder dividend payments.
For the three months ended March 31, 2010, our operating cash flow decreased by $317 million as compared to the same period in 2009. The net change was due primarily to net changes from Power and PSE&G, as discussed below.
Power’s operating cash flow decreased $292 million from $1,240 million to $948 million for the three months ended March 31, 2010, as compared to the same period in 2009, due primarily to lower margins realized on generation and gas sales combined with a decrease of $104 million in net cash collateral receipts. Also contributing to the decrease was a reduction of $98 million related primarily to lower volumes and pricing of fuel inventories used to satisfy our gas supply obligations.
PSE&G’s operating cash flow decreased $56 million from $216 million to $160 million for the three months ended March 31, 2010, as compared to the same period in 2009, due primarily to lower recovery of deferred energy costs.
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Short-Term Liquidity
We have been managing our liquidity to assure that we continue to have sufficient access to cash to operate our businesses. We are also monitoring the financial condition and concentration of lenders in our bank facilities. There is no provision in any of the credit facilities that would require other lenders in a facility to assume loan commitments of any financial institution that fails to meet its loan commitments. As of March 31, 2010, no single institution represented more than 11% of the commitments in our credit facilities.
Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of March 31, 2010 were as follows:
Primary Purpose
Company/Facility
TotalFacility
Usage
AvailableLiquidity
ExpirationDate
PSEG:
5-year Credit Facility(A)
Uncommitted Bilateral Agreement
Power:
2-year Credit Facility
PSE&G:
Total PSE&G
On March 16, 2010, a $100 million bilateral credit facility at Power expired. We continually monitor our available liquidity and seek to add capacity as needed to meet our liquidity requirements. As of March 31, 2010, our total credit facility capacity continued to be in excess of our anticipated maximum liquidity requirements through 2010.
Long-Term Debt Financing
For a discussion of our long-term debt transactions during 2010, see Note 8. Changes in Capitalization.
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Common Stock Dividends and Repurchases
Dividend payments on common stock for the three months ended March 31, 2010 were $0.3425 per share and totaled $173 million.
Dividend payments on common stock for the three months ended March 31, 2009 were $0.3325 per share and totaled $168 million.
We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. In March 2010, S&P affirmed the ratings and outlooks of PSEG, Power and PSE&G.
Moody’s(A)
S&P(B)
Fitch(C)
Outlook
Commercial Paper
Mortgage Bonds
CAPITAL REQUIREMENTS
We expect that the majority of funding for our capital requirements over the next three years will come from a combination of internally generated funds and external financings. Our projected construction and investment expenditures through 2012 are consistent with the amounts disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.
During the three months ended March 31, 2010, Power made $142 million of capital expenditures (excluding $32 million for nuclear fuel), related primarily to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 7. Commitments and Contingent Liabilities.
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During the three months ended March 31, 2010, PSE&G made $223 million of capital expenditures, including $217 million of investment in plant, primarily for reliability of transmission and distribution systems and $6 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $19 million, which are included in operating cash flows.
ACCOUNTING MATTERS
For information related to recent accounting matters, see Note 2. Recent Accounting Standards.
The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading mark-to-market (MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities. The MTM derivatives that are not hedges are included in the trading VaR.
The VaR models used are variance/covariance models adjusted for the change of positions with a 95% confidence level and a one-day holding period for the MTM trading and non-trading activities, and a 95% confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
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As of March 31, 2010, trading VaR was $2 million. As of December 31, 2009, trading VaR was $1 million.
For the Three Months Ended March 31, 2010
TradingVaR
Non-TradingMTM VaR
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:
See Note 9. Financial Risk Management Activities for a discussion of credit risk.
Disclosure Controls and Procedures
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the first quarter of 2010 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
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We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2009 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 7. Commitments and Contingent Liabilities and Item 5. Other Information, Federal Regulation.
There are no additional Risk Factors to be added to those disclosed in Part I Item 1A of our 2009 Annual Reports on Form 10-K.
In July 2008, our Board of Directors authorized the repurchase of up to $750 million of our common stock to be executed over 18 months beginning August 1, 2008. We repurchased 2,382,200 shares of our common stock for $92 million under this authorization. We did not repurchase any shares under this plan during 2009 or through the plan’s expiration date of February 1, 2010. The plan has not been renewed.
The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation award grants during the first quarter of 2010:
Total Numberof SharesPurchased
AveragePrice Paidper Share
Certain information reported under the 2009 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2009 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed.
FEDERAL REGULATION
Greenhouse Gas—CO2
In April 2010, the EPA and the National Highway Transportation Safety Board (NHTSB) jointly issued a final rule to regulate greenhouse gas (GHG) emissions from certain motor vehicles (Motor Vehicle Rule). Under the Clean Air Act, the adoption of the Motor Vehicle Rule would have automatically subjected many emission sources, including ours, to Clean Air Act permitting for major facility modifications that increase the emission of GHGs, including CO2. However, guidance issued by the EPA in March 2010 interpreted the Clean Air Act to require permitting for GHGs at other facilities, such as ours, only when the Motor Vehicle Rule takes effect in January 2011. Moreover, during 2009 the EPA proposed rules that would phase in, beginning in 2011, the application of this permitting requirement to facilities such as ours. The significance of the permitting requirement is that, in cases where a permit is required, the owner of the facility would need to install best available control technology (BACT) for GHG emissions, which has not yet been defined by the EPA. The outcome of the EPA’s rulemaking, including any determination of what EPA will consider as BACT for GHG, can not be predicted.
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FERC
Transmission Expansion
2009 Form 10-K, Page 19. In December 2008, PJM approved a 500 kV transmission project, originating in Branchburg and ending in Hudson County, New Jersey. This project is still in the design phase and will require the receipt of numerous regulatory approvals prior to construction. In October 2009, we filed a petition with FERC seeking incentive rates for the planned project. In December 2009, FERC granted our request for incentive rate treatment. We will receive a Return on Equity (ROE) adder of 125 basis points above our base ROE, recovery of 100% of Construction Work in Progress in rate base and authorization to recover 100% of all prudently-incurred development and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond our control. The estimated cost of the project is approximately $1.1 billion. PJM has specified a June 2013 in-service date for this project, though PJM has publicly indicated that the in-service date may be delayed and that alternatives to the project are being considered.
STATE REGULATION
Rates
Electric and Gas Base Rate Case
2009 Form 10-K, page 21. In May 2009, we filed briefs in our base rate case supporting an increase in electric and gas distribution base rates. We filed an update in March 2010 requesting an increase of $140 million and $64 million for electric and gas, respectively. The New Jersey Division of Rate Counsel has filed a brief recommending a $21 million increase in PSE&G’s electric distribution rates and a $1 million decrease in gas distribution rates. The BPU Staff filed a reply brief in April 2010 supporting this recommendation. We are currently conducting settlement discussions with the parties involved. If a settlement is not reached, we expect to receive a decision from the Administrative Law Judge (ALJ) later in May with a final BPU decision expected around mid-year. No assurances can be given regarding the outcome of this proceeding.
SBC/NGC
2009 Form 10-K, Page 22. In February 2009, we filed a petition requesting a decrease in our electric SBC/NGC rates of $18.9 million and an increase in gas SBC rates of $3.7 million. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas, respectively. The electric increase was due to increased non-utility generation (NUG) contract costs. The ALJ issued an initial decision in April 2010. The recommended decision approved a revenue increase of $119 million and a disallowance of approximately $254,000 in the NGC and approximately $540,000 in the electric SBC. PSE&G is reviewing the ALJ decision and will be filing Exceptions with the BPU. The BPU is expected to issue a final decision mid-year. No assurances can be provided as to the outcome of these proceedings.
Energy Policy
Susquehanna-Roseland BPU Petition
2009 Form 10-K, Page 22. In January 2009, we filed a Petition with the BPU seeking authorization to construct the New Jersey portion of the Susquehanna-Roseland line. The New Jersey portion of the line spans approximately 45 miles and crosses through 16 municipalities. The Petition sought a finding from the BPU that municipal land use and zoning ordinances do not apply to this line. On February 11, 2010, the BPU granted approval to PSE&G to construct the New Jersey portion of this project. On April 21, 2010, the BPU issued a written order memorializing the action taken on February 11, which will enable PSE&G to commence condemnation proceedings if necessary to acquire certain property rights. Regarding environmental approvals, in June 2009, the New Jersey Highlands Council provided a favorable applicability determination with respect to the portion of the project crossing the Highlands region and the New Jersey Department of Environmental Protection (NJDEP) approved this determination on January 15, 2010. Subject to obtaining certain
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environmental approvals, PSE&G plans to begin construction of the eastern portion of the project this summer. The eastern portion of the project is currently expected to be in service by June 2012. Construction of the western portion of the project toward the Delaware River would begin at a later time and is subject to receiving approval from, among other agencies, the National Park Service. The targeted completion date for this portion of the project is the end of 2013, though any failure to obtain all necessary approvals on a timely basis could delay the project’s completion date.
ENVIRONMENTAL MATTERS
Piles Creek and South Branch Creek Natural Resource Damage Assessment
On April 29, 2010, we were one of several companies that received a letter from the National Oceanic and Atmospheric Administration (NOAA) inviting us to participate in a Natural Resource Damage Assessment for Piles Creek and South Branch Creek which are located in Union County, New Jersey. NOAA requested that the companies consider entering into a Cooperative Assessment Agreement for the sampling and analysis plan for the study area. We are evaluating whether to participate in the assessment. The costs, if any, of participating in this study and any potential remediation, if necessary, are not yet reasonably estimable.
Fuel and Waste Disposal
2009 Form 10-K, Page 28. 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 US Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The Nuclear Waste Policy Act 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 April 2010, we joined the Nuclear Energy Institute and fifteen other nuclear plant operators in petitioning the United States Court of Appeals for the District of Columbia District to review the DOE decision to continue to collect the Nuclear Waste Fee at the current rate. The Nuclear Waste Fee litigation is not expected to have any effect on Power’s September 2009 settlement agreement with DOE applicable to Salem and Hope Creek under which Power will be reimbursed for past and future reasonable and allowable costs resulting from the DOE delay in accepting spent nuclear fuel for permanent disposition.
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A listing of exhibits being filed with this document is as follows:
a. PSEG:
b. Power:
c. PSE&G:
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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
By:
/S/ DEREK M. DIRISIO
Derek M. DiRisio
Vice President and Controller
(Principal Accounting Officer)
Date: May 6, 2010
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