Pepco Holdings 10-Q 2009
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarter ended June 30, 2009
Indicate by check mark whether each registrant (1) has 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 and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Pepco, DPL, and ACE meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with reduced disclosure format specified in General Instruction H(2) of Form 10-Q.
THIS COMBINED FORM 10-Q IS SEPARATELY FILED BY PEPCO HOLDINGS, PEPCO, DPL, AND ACE. INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE OTHER REGISTRANTS.
TABLE OF CONTENTS
GLOSSARY OF TERMS
Item 1. FINANCIAL STATEMENTS
Listed below is a table that sets forth, for each registrant, the page number where the information is contained herein.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying Notes are an integral part of these Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PEPCO HOLDINGS, INC.
Pepco Holdings, Inc. (PHI or Pepco Holdings), a Delaware corporation incorporated in 2001, is a diversified energy company that, through its operating subsidiaries, is engaged primarily in two businesses:
PHI Service Company, a subsidiary service company of PHI, provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries. These services are provided pursuant to a service agreement among PHI, PHI Service Company, and the participating operating subsidiaries. The expenses of the PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement.
The following is a description of each of PHIs two principal business operations:
The largest component of PHIs business is Power Delivery. Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each company owns and operates a network of wires, substations and other equipment that is classified either as transmission or distribution facilities. Transmission facilities are high-voltage systems that carry wholesale electricity into, or across, the utilitys service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utilitys service territory. Together the three companies constitute a single segment for financial reporting purposes.
Each company is responsible for the delivery of electricity and, in the case of DPL, natural gas, in its service territory, for which it is paid tariff rates established by the applicable local public service commissions. Each company also supplies electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. The regulatory term for this supply service is Standard Offer Service (SOS) in Delaware, the District of Columbia and Maryland; and Basic Generation Service (BGS) in New Jersey. In this Form 10-Q, these supply services are referred to generally as Default Electricity Supply.
The Competitive Energy business provides competitive generation, marketing and supply of electricity and gas, and related energy management services, primarily in the mid-Atlantic region. PHIs Competitive Energy operations are conducted through Conectiv Energy and Pepco Energy Services, each of which is treated as a separate operating segment for financial reporting purposes.
PHI is continuing to evaluate the retail energy supply business of Pepco Energy Services relative to PHIs strategic objectives with a view toward a possible restructuring, sale or wind down of the business. Among the factors being considered in this analysis is the return PHI earns by investing capital in the retail energy supply business as compared to alternative investments. PHI expects the retail energy supply business to remain profitable based on its existing contract backlog and because the variability of margins has been reduced by entering into corresponding wholesale energy purchase contracts. With the increased cost of capital associated with its collateral obligations factored into its retail pricing, Pepco Energy Services is experiencing reduced retail customer retention levels and reduced levels of new retail customer acquisitions. In March 2009, Pepco Energy Services entered into a credit intermediation arrangement with an investment banking firm, which is more fully described in Note (9), Debt, under the heading Impact of the Recent Capital and Credit Market Disruptions Collateral Requirements of the Competitive Energy Business. The arrangement eliminates the collateral requirements with respect to a portion of Pepco Energy Services wholesale electricity supply contracts.
Other Business Operations
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy sale-leaseback transactions, with a book value at June 30, 2009 of approximately $1.4 billion. This activity constitutes a fourth operating segment for financial reporting purposes, which is designated as Other Non-Regulated.
(2) SIGNIFICANT ACCOUNTING POLICIES
Financial Statement Presentation
Pepco Holdings unaudited consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in PHIs Annual Report on Form 10-K for the year ended December 31, 2008. In the opinion of PHIs management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to present fairly Pepco Holdings financial condition as of June 30, 2009, in accordance with GAAP. The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2009 may not be indicative of PHIs results that will be realized for the full year ending December 31, 2009, since its Power Delivery and Competitive Energy business are seasonal. PHI has evaluated all subsequent events through August 6, 2009, the date of issuance of the consolidated financial statements to which these Notes relate.
Change in Accounting Principle
Since PHIs adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets, PHI has conducted its annual impairment review of goodwill as of July 1. After the completion of the July 1, 2009 impairment test, PHI adopted a new accounting policy whereby PHIs annual impairment review of goodwill will be performed as of November 1 each year. Management believes that the change in PHIs annual impairment testing date is preferable because it better aligns the timing of the test with managements annual update of its long-term financial forecast. The change in accounting principle had no effect on PHIs consolidated financial statements.
Change in Accounting Estimate
In the second quarter of 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of the tax benefits generated from its cross-border energy lease investments. Based on the reassessment, PHI for the quarter ended June 30, 2008, recorded an after-tax charge to net income of $93 million. For additional discussion on this matter, see Notes (7), Leasing Activities and (14), Commitments and Contingencies.
Consolidation of Variable Interest Entities
In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46(R), Consolidation of Variable Interest Entities (FIN 46(R)), Pepco Holdings consolidates those variable interest entities where Pepco Holdings or a subsidiary has been determined to be the primary beneficiary. FIN 46(R) addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of Pepco Holdings have power purchase agreements (PPAs) with a number of entities to which FIN 46(R) applies.
ACE and Pepco PPAs
Pepco Holdings, through its ACE subsidiary, is a party to three PPAs with unaffiliated, non-utility generators (NUGs). Due to a variable element in the pricing structure of the PPAs, Pepco Holdings potentially assumes the variability in the operations of the plants operated by the NUGs and, therefore, has a variable interest in the counterparties. Despite continued efforts to obtain information from these three entities during the three months ended June 30, 2009, PHI was unable to obtain sufficient information to conduct the analysis required under FIN 46(R) to determine whether these three entities were variable interest entities or if the Pepco Holdings subsidiaries were the primary beneficiary. As a result, Pepco Holdings has applied the scope exemption from the application of FIN 46(R) for enterprises that have conducted exhaustive efforts to obtain the necessary information, but have not been able to obtain such information.
Net purchase activities under the PPAs for the three months ended June 30, 2009 and 2008, were approximately $61 million and $82 million, respectively, of which approximately $59 million and $74 million, respectively, consisted of power purchases under the PPAs. Net purchase activities under the PPAs for the six months ended June 30, 2009 and 2008, were approximately $144 million and $171 million, respectively, of which approximately $131 million and $150 million, respectively, consisted of power purchases under the PPAs. Pepco Holdings does not have loss exposure under the PPAs because ACE is able to recover its costs from its customers through regulated rates.
During the third quarter of 2008, Pepco transferred to Sempra Energy Trading LLP (Sempra) an agreement with Panda-Brandywine, L.P. (Panda) under which Pepco was obligated to purchase from Panda 230 megawatts of capacity and energy annually through 2021 (Panda PPA). Net purchase activities under the Panda PPA for the three and six months ended June 30, 2008, were approximately $22 million and $42 million, respectively.
DPL Wind Transactions
PHI, through its DPL subsidiary, has entered into four wind PPAs in amounts up to a total of 350 megawatts. Three of the PPAs are with onshore facilities and one of the PPAs is with an offshore facility. DPL would purchase energy and renewable energy credits (RECs) from the four wind facilities and capacity from one of the wind facilities. The RECs help DPL fulfill a portion of its requirements under the State of Delawares Renewable Energy Portfolio Standards Act, which requires that 20 percent of total load needed in Delaware be produced from renewable sources by 2019. The Delaware Public Service Commission (DPSC) has approved the four agreements, each of which sets forth the prices to be paid by DPL over the life of the respective contracts. Payments under the agreements are currently expected to start in late 2009 for one of the onshore contracts, 2010 for the other two onshore contracts, and 2014 for the offshore contract.
The lengths of the contracts range between 15 and 25 years. DPL is obligated to purchase energy and RECs in amounts generated and delivered by the sellers at rates that are primarily fixed under these agreements. Recent disruptions in the capital and credit markets could result in delays in the construction of the wind facilities and the operational start dates for these wind facilities. If the wind facilities are not operational by specified dates, DPL has the right to terminate the PPAs.
DPL concluded that consolidation is not required for any of these PPAs under FIN 46(R). DPL would need to reassess its accounting conclusions if there were material changes to the contractual arrangements or wind facilities.
Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. Substantially all of Pepco Holdings goodwill was generated by Pepcos acquisition of Conectiv in 2002 and was allocated to Pepco Holdings Power Delivery reporting unit based on the aggregation of its components. Pepco Holdings historically has tested its goodwill for impairment annually as of July 1, and whenever an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Factors that may result in an interim impairment test include, but are not limited to: a change in the identified reporting units; an adverse change in business conditions; a protracted decline in stock price causing market capitalization to fall below book value; an adverse regulatory action; or an impairment of long-lived assets in the reporting unit. PHI performed its annual impairment test as of July 1, 2009 prior to the issuance of the June 30, 2009 Form 10-Q to ensure no impairment charge should be recorded as of June 30, 2009. As described in Note (6), Goodwill, no impairment charge has been recorded. As further described above under the heading Change in Accounting Principle, after the completion of the July 1, 2009 impairment test, PHI changed the annual impairment testing date to November 1, and will perform its next annual impairment test on November 1, 2009.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco Holdings gross revenues were $77 million and $74 million for the three months ended June 30, 2009 and 2008, respectively and $154 million and $148 million for the six months ended June 30, 2009 and 2008, respectively.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to current period presentation.
Income Tax Adjustments
During the second quarter of 2009, DPL recorded an adjustment to correct certain income tax errors related to prior periods. The adjustment, which is not considered material, resulted in a decrease in income tax expense of $1 million for the three and six months ended June 30, 2009.
During the first and second quarters of 2009, ACE recorded adjustments to correct certain income tax errors related to prior periods. These adjustments, which are not considered material, resulted in an increase in income tax expense of $1 million for the three months ended June 30, 2009, and a decrease in income tax expense of $1 million for the six months ended June 30, 2009.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 141(R), Business Combinationsa Replacement of FASB Statement No. 141 (SFAS No. 141 (R))
SFAS No. 141(R) replaces FASB Statement No. 141, Business Combinations, and retains the fundamental requirements that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. However, SFAS No. 141(R) expands the definition of a business and amends FASB Statement No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits that are realizable because of a business combination either in income from continuing operations or directly in contributed capital, depending on the circumstances.
On April 1, 2009, the FASB issued FASB Staff Position (FSP) Financial Accounting Standards (FAS) 141(R)-1, Accounting for Assets and Liabilities Assumed in a Business Combination that Arise from Contingencies (FSP FAS 141(R)-1), to clarify the accounting for the initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. FSP FAS 141(R)-1 requires that assets acquired and liabilities assumed in a business combination that arise from contingencies be measured at fair value if the acquisition date fair value of that asset and liability can be determined during the measurement period in accordance with SFAS No. 157. If the acquisition date fair value cannot be determined, then the asset or liability would be measured in accordance with SFAS No. 5, Accounting for Contingencies, and FIN No. 14, Reasonable Estimate of the Amount of Loss.
SFAS No. 141(R) and the guidance provided in FSP FAS 141(R)-1 applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. PHI adopted SFAS No. 141(R) on January 1, 2009, and it did not have a material impact on PHIs overall financial condition, results of operations, or cash flows.
FSP 157-2, Effective Date of FASB Statement No. 157 (FSP 157-2)
FSP 157-2 deferred the effective date of SFAS No. 157, Fair Value Measurements, (SFAS No. 157) for all nonrecurring fair value measurements of non-financial assets and non-financial liabilities until January 1, 2009 for PHI. The adoption of SFAS No. 157 did not have a material impact on the fair value measurements of PHIs non-financial assets and non-financial liabilities.
SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statementsan Amendment of ARB No. 51 (SFAS No. 160)
SFAS No. 160 establishes new accounting and reporting standards for a non-controlling interest (also called a minority interest) in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be separately reported in the consolidated financial statements.
SFAS No. 160 establishes accounting and reporting standards that require (i) the ownership interests and the related consolidated net income in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated balance sheets within equity, but separate from the parents equity, and presented separately on the face of the consolidated statements of income, (ii) the changes in a parents ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for as equity transactions, and (iii) when a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary must be initially measured at fair value.
SFAS No. 160 is effective prospectively for financial statement reporting periods beginning January 1, 2009 for PHI, except for the financial statement presentation and disclosure requirements which also apply to prior reporting periods presented. As of January 1, 2009, PHI adopted the provisions of SFAS No. 160, and reclassified $6 million of non-controlling interests from the minority interest line item of its balance sheet to a component of equity. Otherwise, SFAS No. 160 did not have a material impact on PHIs overall financial condition, results of operations, or cash flows.
SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activitiesan Amendment of FASB Statement No. 133 (SFAS No. 161)
SFAS No. 161 enhances the disclosure requirements for derivative instruments and hedging activities. Some of the new disclosures include derivative objectives and strategies, derivative volumes by product type, location and gross fair values of derivative assets and liabilities, location and amounts of gains and losses on derivatives and related hedged items, and credit-risk-related contingent features in derivatives.
SFAS No. 161 is effective for financial statement reporting periods beginning January 1, 2009 for PHI. SFAS No. 161 encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. PHI
adopted the provisions of SFAS No. 161 beginning with its March 31, 2009 financial statements with comparative disclosures for prior periods. The disclosures for the current financial statements are included within Footnote (12), Derivative Instruments and Hedging Activities.
FSP Emerging Issues Task Force (EITF) No. 03-6-1, Determining whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1)
In June 2008, the FASB issued FSP EITF 03-6-1, which addresses when unvested instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (EPS) under the two-class method described in SFAS No. 128, Earnings per Share.
FSP EITF 03-6-1 is effective for financial reporting periods beginning January 1, 2009 for PHI. All prior period EPS data presented was adjusted retrospectively to conform with the provisions of FSP EITF 03-6-1. As of January 1, 2009, PHI adopted the provisions of FSP EITF 03-6-1 for the presentation of EPS data in the consolidated statements of income and Footnote (11), Earnings Per Share. The adoption did not result in a change in the reported EPS for prior periods presented therein.
EITF Issue No. 08-5, Issuers Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement (EITF 08-5)
In September 2008, the FASB issued EITF 08-5 to provide guidelines for the determination of the unit of accounting for a liability issued with an inseparable third-party credit enhancement when it is measured or disclosed at fair value on a recurring basis. EITF 08-5 applies to entities that incur liabilities with inseparable third-party credit enhancements or guarantees that are recognized or disclosed at fair value. This would include guaranteed debt obligations, derivatives, and other instruments that are guaranteed by third parties.
The effect of the credit enhancement may not be included in the fair value measurement of the liability, even if the liability is an inseparable third-party credit enhancement. The issuer is required to disclose the existence of the inseparable third-party credit enhancement on the issued liability.
EITF 08-5 is effective on a prospective basis for reporting periods beginning on and after January 1, 2009 for PHI. As of January 1, 2009, PHI adopted the provisions of EITF 08-5, and it did not have a material impact on PHIs overall financial condition, results of operations, or cash flows.
EITF Issue No. 08-6, Equity Method Investment Accounting Consideration (EITF 08-6)
In November 2008, the FASB issued EITF 08-6 to address the accounting for equity method investments including: (i) how an equity method investment should initially be measured, (ii) how it should be tested for impairment, and (iii) how an equity method investees issuance of shares should be accounted for. The EITF provides that the initial carrying value of an equity method investment can be determined using the accumulation model in SFAS 141(R), Business Combination (revised 2007), and other-than-temporary impairments should be recognized in accordance with paragraph 19(h) of Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock.
This EITF is effective for PHI beginning January 1, 2009. As of January 1, 2009, PHI adopted the provisions of EITF 08-6, and concluded that based on its review of equity investments, there is no material impact on PHIs overall financial condition, results of operations, or cash flows.
FSP FAS 107-1 and Accounting Principles Board (APB) 28-1, Interim Disclosures about Fair Value of Financial Instruments (FSP FAS 107-1 and APB 28-1)
In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which require quarterly disclosures of the fair values of financial instruments. This FSP is effective for interim reporting periods ending after June 15, 2009. The disclosures for prior reporting periods are required.
PHI adopted the disclosure requirements in its second quarter 2009 reporting. The primary impact of the new standard is disclosing the fair value of debt issued by PHI and its utilities on a quarterly basis as presented in Footnote (13), Fair Value Disclosures.
FSP FAS 157-4, Determining Whether a Market is Not Active and a Transaction is Not Distressed (FSP FAS 157-4)
In April 2009, the FASB issued FSP FAS 157-4, which outlines a two-step test to identify inactive and distressed markets and provides a fair value application example for financial instruments when both conditions are met. This FSP is effective for interim reporting periods ending after June 15, 2009.
PHI adopted the provisions of this FSP in the second quarter of 2009. The standard would primarily apply to PHIs valuation of its derivatives in the event they were being valued using information from inactive and distressed markets. These market conditions would require management to exercise judgment regarding how the market information is incorporated into the measurement of fair value. FSP FAS 157-4 did not have a material impact on PHIs overall financial condition, results of operations, or cash flows.
FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2)
In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which provided additional guidance on other-than-temporary impairment (OTTI) of debt and equity securities. They require information about the credit and noncredit component of an OTTI event and when an OTTI event has occurred. It requires separate display of losses related to credit deterioration and losses related to other market factors on the statements of income. Market-related losses would be recorded in other comprehensive income if it is not likely that the investor will have to sell the security prior to recovery.
PHI adopted the provisions of this FSP as of April 1, 2009, and concluded that none of its debt and equity securities investments were within its scope. The FSP, therefore, did not have a material impact on PHIs overall financial condition, results of operations, or cash flows.
Statement of Financial Accounting Standards (SFAS) No. 165, Subsequent Events (SFAS No. 165)
In May 2009, the FASB issued SFAS No. 165 to establish guidelines for the accounting and disclosures of events that occur after the balance sheet reporting date but before the financial statements are issued. The statement has not resulted in any significant changes from U.S. Auditing Standards AU 560, Subsequent Events; however, it places the responsibility on the reporting entity and not just the auditors to assess the impact of subsequent events on the financial statements. The statement was effective for interim or annual financial periods ending after June 15, 2009, which for PHI was the second quarter of 2009. PHI addresses subsequent events in Footnote (2), Significant Accounting Policies.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
FSP FAS 132(R)-1, Employers Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1)
In December 2008, the FASB issued FSP FAS 132(R)-1 to provide guidance on an employers disclosures about plan assets of a defined benefit pension or other postretirement plan. The required disclosures under this FSP would expand current disclosures under SFAS No. 132(R), Employers Disclosures about Pensions and Other Postretirement Benefitsan amendment of FASB Statements No. 87, 88, and 106, to be in line with SFAS No. 157 required disclosures.
The disclosures are to provide users an understanding of: (1) the investment allocation decisions made, (2) factors used in investment policies and strategies, (3) plan assets by major investment types, (4) inputs and valuation techniques used to measure fair value of plan assets, (5) significant concentrations of risk within the plan, and (6) the effects of fair value measurement using significant unobservable inputs (Level 3 as defined in SFAS No. 157) on changes in the value of plan assets for the period.
The new disclosures are required starting with financial statement reporting periods ending December 31, 2009 for PHI and earlier application is permitted. Comparative disclosures under this provision are not required for earlier periods presented. PHI is evaluating the impact that it will have on PHIs financial statement footnote disclosures for year end reporting.
Statement of Financial Accounting Standards (SFAS) No. 166, Accounting for Transfers of Financial Assetsan amendment of SFAS No. 140 (SFAS No. 166)
In June 2009, the FASB issued SFAS No. 166 to remove the concept of a qualifying special-purpose entity (QSPE) from SFAS No. 140 and the QSPE scope exception in FIN 46(R). The statement changes requirements for derecognizing financial assets and requires additional disclosures about a transferors continuing involvement in transferred financial assets.
The new guidance is effective for transfers of financial assets occurring in fiscal periods beginning after November 15, 2009; therefore, this guidance will be effective on January 1, 2010 for PHI. Comparative disclosures are encouraged but not required for earlier periods presented. PHI is evaluating the impact that it will have on its overall financial condition and financial statements.
Statement of Financial Accounting Standards (SFAS) No. 167, Consolidation of Variable Interest Entitiesan amendment of FIN 46(R) (SFAS No. 167)
In June 2009, the FASB issued SFAS No. 167 to amend FIN 46(R), Consolidation of Variable Interest Entities, which eliminates the existing quantitative analysis requirement and adds new qualitative factors to determine whether consolidation is required. The new qualitative factors would be applied on a quarterly basis to interests in variable interest entities. Under the new standard, the holder of the interest with the power to direct the most significant activities of the entity and the right to receive benefits or absorb losses significant to the entity would consolidate. The new standard retained the provision in FIN 46(R) that allowed entities created before December 31, 2003 to be scoped out from a consolidation assessment if exhaustive efforts are taken and there is insufficient information to determine the primary beneficiary.
The new guidance is effective for fiscal periods beginning after November 15, 2009 for existing and newly created entities; therefore, this guidance will be effective on January 1, 2010 for PHI. Comparative disclosures under this provision are encouraged but not required for earlier periods presented. PHI is evaluating the impact that it will have on its overall financial condition and financial statements.
Statement of Financial Accounting Standards (SFAS) No. 168, The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles (SFAS No. 168)
In June 2009, the FASB issued SFAS No. 168 to identify the sources of accounting principles and the framework for selecting the principles used in the preparation of non-governmental financial statements that are presented under U.S. GAAP. In addition, SFAS No. 168 replaces the current reference system for standards and guidance with a new numerical designation system known as the Codification. The Codification will be the single source reference system for all authoritative non-governmental GAAP. The Codification is numerically organized by topic, subtopic, section, and subsection.
SFAS No. 168 replaces SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. There is an option to early adopt beginning with interim periods ending after June 15, 2009. PHI has not elected to early adopt and, therefore, the Codification referencing required by SFAS No. 168 will become effective in its September 30, 2009 financial statements. Entities are not required to revise previous financial statements for the change in references.
The adoption of SFAS No. 168 is not expected to result in a change in accounting for PHI. Therefore, the provisions of SFAS No. 168 are not expected to have a material impact on PHIs overall financial condition, results of operations, or cash flows. However, there will be a change in how accounting standards are referenced in the financial statements.
(5) SEGMENT INFORMATION
Based on the provisions of SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, Pepco Holdings management has identified its operating segments at June 30, 2009 as Power Delivery, Conectiv Energy, Pepco Energy Services, and Other Non-Regulated. Segment information for the three and six months ended June 30, 2009 and 2008, is as follows:
PHIs goodwill balance of $1.4 billion was unchanged during the three and six month period ended June 30, 2009. Substantially all of PHIs goodwill was generated by Pepcos acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit based on the aggregation of its components for purposes of assessing impairment under SFAS No. 142.
PHIs July 1, 2009 annual impairment test completed prior to the issuance of the June 30, 2009 Form 10-Q, indicated that its goodwill was not impaired. PHI performed interim impairment tests as of December 31, 2008 and March 31, 2009, as its market capitalization was below book value at December 31, 2008 and its market capitalization declined further below book value at March 31, 2009. PHI concluded that its goodwill was not impaired at both December 31, 2008 and March 31, 2009, and again at June 30, 2009 with the completion of the July 1, 2009 annual impairment test.
In order to estimate the fair value of its Power Delivery reporting unit, PHI reviews the results from two discounted cash flow models. The models differ in the method used to calculate the terminal value of the reporting unit. One model estimates terminal value based on a constant annual cash flow growth rate that is consistent with Power Deliverys long-term view of the business, and the other model estimates terminal value based on a multiple of earnings before interest, taxes, depreciation, and amortization (EBITDA) that management believes is consistent with EBITDA multiples for comparable utilities. The models use a cost of capital appropriate for a regulated utility as the discount rate for the estimated cash flows associated with the reporting unit. PHI has consistently used this valuation approach to estimate the fair value of Power Delivery since the adoption of SFAS No. 142.
The estimation of fair value is dependent on a number of factors that are sourced from the Power Delivery reporting units business forecast, including but not limited to interest rates, growth assumptions, returns on rate base, operating and capital expenditure requirements, and other factors, changes in which could materially impact the results of impairment testing. Assumptions and methodologies used in the models were consistent with historical experience, including assumptions concerning the recovery of operating costs and capital expenditures. Sensitive, interrelated and uncertain variables that could decrease the estimated fair value of the Power Delivery reporting unit include utility sector market performance, sustained adverse business conditions, changes in forecasted revenues, higher operating and capital expenditure requirements, a significant increase in the cost of capital and other factors.
In addition to estimating the fair value of its Power Delivery reporting unit, PHI estimated the fair value of its other business segments (Conectiv Energy, Pepco Energy Services, Other Non-Regulated, and Corporate & Other) at July 1, 2009. The sum of the fair value of all business segments was reconciled to PHIs market capitalization at July 1, 2009 to further substantiate the estimated fair value of its reporting units.
The sum of the estimated fair values of all segments exceeded the market capitalization of PHI at July 1, 2009. PHI believes that the excess of the estimated fair value of PHIs segments as compared to PHIs market capitalization reflects a reasonable control premium that is comparable to control premiums observed in historical acquisitions in the utility industry during various economic environments. Given the lack of a fundamental change in the Power Delivery reporting units business, PHI does not believe the declines in its stock price in recent periods indicate a commensurate decline in the fair value of PHIs Power Delivery reporting unit. PHIs Power Delivery reporting unit consists of regulated companies with regulated recovery rates and approved rates of return allowing for generally predictable and steady streams of revenues and cash flows over an extended period of time.
With the continuing volatile general market conditions, the sustained period of time that PHIs stock price has been below its book value, and the disruptions in the credit and capital markets, PHI will continue to closely monitor for indicators of goodwill impairment.
(7) LEASING ACTIVITIES
Investment in Finance Leases Held in Trust
As of June 30, 2009 and December 31, 2008, Pepco Holdings had cross-border energy lease investments of $1.4 billion and $1.3 billion, consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks located outside of the United States.
As further discussed in Note (14), Commitments and ContingenciesPHIs Cross-Border Energy Lease Investments, during the second quarter of 2008, PHI reassessed the sustainability of its tax position and revised its assumptions regarding the estimated timing of tax benefits generated from its cross-border energy lease investments. Based on this reassessment, PHI for the quarter ended June 30, 2008, recorded a reduction in its cross-border energy lease investments of $124 million. No further charges were recorded in 2008 or in the first two quarters of 2009.
The components of the cross-border energy lease investments at June 30, 2009 and at December 31, 2008 (reflecting the effects of recording this charge) are summarized below:
Income recognized from cross-border energy lease investments was comprised of the following for the three and six months ended June 30, 2009 and 2008:
(8) PENSIONS AND OTHER POSTRETIREMENT BENEFITS
The following Pepco Holdings information is for the three months ended June 30, 2009 and 2008:
The following Pepco Holdings information is for the six months ended June 30, 2009 and 2008:
Pension and Other Postretirement Benefits
Net periodic benefit cost is included in other operation and maintenance expense, net of the portion of the net periodic benefit cost that is capitalized as part of the cost of labor for internal construction projects. After intercompany allocations, the three utility subsidiaries are generally responsible for approximately 80% to 85% of total PHI net periodic benefit cost.
PHIs funding policy with regard to PHIs non contributory retirement plan (the PHI Retirement Plan) is to maintain a funding level that is at least equal to the funding target as defined under the Pension Protection Act of 2006. During 2009, discretionary tax-deductible contributions totaling $300 million have been made to the PHI Retirement Plan which are expected to bring plan assets to at least the funding target level for 2009 under the Pension Protection Act. Of this amount, $220 million was contributed prior to June 30, 2009, through tax-deductible contributions from Pepco, ACE and DPL in the amounts of $150 million, $60 million and $10 million, respectively. The remaining $80 million contribution was made in July 2009 through tax-deductible contributions from Pepco of $20 million and $60 million from the PHI Service Company. No contributions were made in 2008.
PHIs principal credit source is an unsecured $1.5 billion syndicated credit facility, which can be used by PHI and its utility subsidiaries to borrow funds, obtain letters of credit and support the issuance of commercial paper. This facility is in effect until May 2012 and consists of commitments from 17 lenders, no one of which is responsible for more than 8.5% of the total $1.5 billion commitment. PHIs credit limit under the facility is $875 million. The credit limit of each of Pepco, DPL and ACE is the lesser of $500 million and the maximum amount of debt the company is permitted to have outstanding by its regulatory authorities, except that the aggregate amount of credit used by Pepco, DPL and ACE at any given time collectively may not exceed $625 million.
In November 2008, PHI entered into a second unsecured credit facility in the amount of $400 million with a syndicate of nine lenders. Under the facility, PHI may obtain revolving loans and swingline loans over the term of the facility, which expires on November 6, 2009. The facility does not provide for the issuance of letters of credit. These two facilities are referred to collectively as PHIs primary credit facilities.
PHI and its utility subsidiaries historically have issued commercial paper to meet their short-term working capital requirements. As a result of the disruptions in the commercial paper market in 2008, the companies borrowed under the $1.5 billion credit facility to create a cash reserve for future short-term operating needs. At June 30, 2009, PHI had an outstanding loan of $150 million and DPL had an outstanding loan of $50 million under the credit facility. DPL repaid its loan in July 2009.
At June 30, 2009 and December 31, 2008, the amount of cash, plus borrowing capacity under PHIs primary credit facilities available to meet the future liquidity needs of PHI on a consolidated basis totaled $1.5 billion, of which the combined cash and borrowing capacity under the $1.5 billion credit facility of PHIs utility subsidiaries was $549 million and $843 million, respectively.
Other Financing Activities
During the three months ended June 30, 2009, the following financing activities occurred:
Subsequent to June 30, 2009, the following financing activities occurred:
In July 2009, ACE Funding made principal payments of $5.2 million on Series 2002-1 Bonds, Class A-2, $1.4 million on Series 2003-1 Bonds, Class A-1, and $0.7 million on Series 2003-1 Bonds, Class A-2.
In July 2009, DPL repaid, at maturity, the remaining $100 million of its original $150 million short-term loan.
In July 2009, PHIs utility subsidiaries entered into a $30 million line of credit that can be used by these entities for equipment leasing through July 2010.
In July 2009, DPL redeemed the $15 million Series 2003 A and $18.2 million Series 2003 B Delaware Economic Development Authority tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.
In July 2009, ACE redeemed the $25 million Series 2004 A and $6.5 million Series 2004 B Pollution Control Financing Authority of Cape May County tax exempt bonds that were repurchased in 2008 due to the disruptions in the tax exempt capital markets.
Collateral Requirements of the Competitive Energy Business
In conducting its retail energy supply business, Pepco Energy Services, during periods of declining energy prices, has been exposed to the asymmetrical risk of having to post collateral under its wholesale purchase contracts without receiving a corresponding amount of collateral from its retail customers. To partially address these asymmetrical collateral obligations, Pepco Energy Services, in the first quarter of 2009, entered into a credit intermediation arrangement with Morgan Stanley Capital Group, Inc. (MSCG). Under this arrangement, MSCG, in consideration for the payment to MSCG of certain fees, (i) has assumed by novation certain electricity purchase obligations of Pepco Energy Services in years 2009 through 2011 under several wholesale purchase contracts and (ii) has agreed to supply electricity to Pepco Energy Services on the same terms as the novated transactions, but without imposing on Pepco Energy Services any associated collateral obligations. As of June 30, 2009, approximately 32% of Pepco Energy Services wholesale electricity purchase obligations (measured in megawatt hours) were covered by this credit intermediation arrangement with MSCG. The fees incurred by Pepco Energy Services in the amount of $25 million are being amortized into expense in declining amounts over the life of the arrangement based on the fair value of the underlying contracts at the time of novation. For the three and six months ended June 30, 2009, approximately $7 million and $8 million, respectively, of the fees have been amortized.
In addition to Pepco Energy Services retail energy supply business, Conectiv Energy and Pepco Energy Services in the ordinary course of business enter into various other contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce their financial exposure to changes in the value of their assets and obligations due to energy price fluctuations. These contracts also typically have collateral requirements.
Depending on the contract terms, the collateral required to be posted by Pepco Energy Services and Conectiv Energy can be of varying forms, including cash and letters of credit. As of June 30, 2009, the Competitive Energy business (including Pepco Energy Services retail energy supply business) had posted net cash collateral of $443 million and letters of credit of $182 million. At December 31, 2008, the Competitive Energy business had posted net cash collateral of $331 million and letters of credit of $558 million.
At June 30, 2009 and December 31, 2008, the amount of cash, plus borrowing capacity under PHIs primary credit facilities available to meet the future liquidity needs of the Competitive Energy business totaled $915 million and $684 million, respectively.
(10) INCOME TAXES
A reconciliation of PHIs consolidated effective income tax rate is as follows:
PHIs effective tax rates for the three months ended June 30, 2009 and 2008 were 34.2% and 65.3%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy lease investments described in Note (7), and corresponding state tax benefits related to the charge, a 2008 benefit for interest received on a state income tax refund, and a 2009 change in deductions related to deferred compensation funding.
PHIs effective tax rates for the six months ended June 30, 2009 and 2008 were 34.6% and 41.4%, respectively. The decrease in the rate resulted from the second quarter 2008 charge related to the cross-border energy lease investments described in Note (7) and corresponding state tax benefits related to the charge.
In March 2009, the Internal Revenue Service (IRS) issued a Revenue Agents Report (RAR) for the audit of PHIs consolidated federal income tax returns for the calendar years 2003 to 2005. The IRS has proposed adjustments to PHIs tax returns, including adjustments to PHIs deductions related to cross-border energy lease investments, the capitalization of overhead costs for tax purposes and the deductibility of certain casualty losses. PHI has appealed certain of the proposed adjustments and believes it has adequately reserved for the adjustments included in the RAR. See Note (14) Commitments and Contingencies PHIs Cross-Border Energy Lease Investments for additional discussion.
During the second quarter of 2009, as a result of filing amended state returns, PHIs uncertain tax benefits related to prior year tax positions increased by $18 million.
(11) EARNINGS PER SHARE
Reconciliations of the numerator and denominator for basic and diluted EPS of common stock calculations are shown below:
(12) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
PHI accounts for its derivative activities in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS No. 133) as amended by subsequent pronouncements.
PHIs Competitive Energy business uses derivative instruments primarily to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. The derivative instruments used by the Competitive Energy business include forward contracts, futures, swaps, and exchange-traded and over-the-counter options. The Competitive Energy business also manages commodity risk with contracts that are not classified and not accounted for as derivatives. The two primary risk management objectives are (i) to manage the spread between the cost of fuel used to operate electric generating facilities and the revenue received from the sale of the power produced by those facilities, and (ii) to manage the spread between retail sales commitments and the cost of supply used to service those commitments to ensure stable cash flows and lock in favorable prices and margins when they become available.
Conectiv Energy purchases energy commodity contracts in the form of futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas, oil and coal to fuel its generation assets for sale to customers. Conectiv Energy also purchases energy commodity contracts in the form of electricity swaps, options and forward contracts to hedge price risk in connection with the purchase of electricity for delivery to requirements-load customers. Conectiv Energy sells electricity swaps, options and forward contracts to hedge price risk in connection with electric output from its generation fleet. Conectiv Energy accounts for most of its futures, swaps and certain forward contracts as cash flow hedges of forecasted transactions. Derivative contracts purchased or sold in excess of probable amounts of forecasted hedge transactions are marked-to-market through current earnings. All option contracts are marked-to-market through current earnings. Certain natural gas and oil futures and swaps are used as fair value hedges to protect physical fuel inventory. Some forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting under SFAS No. 133.
Pepco Energy Services purchases energy commodity contracts in the form of electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for delivery to customers. Pepco Energy Services accounts for its futures and swap contracts as cash flow hedges of
forecasted transactions. Certain commodity contracts that do not qualify as cash flow hedges of forecasted transactions or do not meet the requirements for normal purchase and normal sale accounting are marked-to-market through current earnings. Forward contracts are accounted for using standard accrual accounting since these contracts meet the requirements for normal purchase and normal sale accounting under SFAS No. 133.
In the Power Delivery business, DPL uses derivative instruments in the form of forward contracts, futures, swaps, and exchange-traded and over-the-counter options primarily to reduce gas commodity price volatility and limit its customers exposure to increases in the market price of gas. DPL also manages commodity risk with physical natural gas and capacity contracts that are not classified as derivatives. All premiums paid and other transaction costs incurred as part of DPLs natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, until recovered based on the fuel adjustment clause approved by the DPSC.
PHI and its subsidiaries also use derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt incurred in connection with the operation of their businesses. In June 2002, PHI entered into several treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in July 2002.
The tables below identify the balance sheet location and fair values of derivative instruments as of June 30, 2009 and December 31, 2008:
Under FSP FIN 39-1, PHI offsets the fair value amounts recognized for derivative instruments and the fair value amounts recognized for related collateral positions executed with the same counterparty under master netting agreements. The amount of cash collateral that was offset against these derivative positions is as follows:
As of June 30, 2009 and December 31, 2008, PHI had no cash collateral pledged or received related to derivative instruments accounted for at fair value that it was not entitled to offset under master netting agreements.
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
For energy commodity contracts that are designated and qualify as cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive (loss) income (AOCL) and is reclassified into income in the same period or periods during which the hedged transactions affect income. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current income. This information for the activity during the three and six months ended June 30, 2009 and 2008 is provided in the tables below:
Included in the above table is a loss of $1 million for the three months ended June 30, 2009, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable.
Included in the above table is a loss of $3 million for the six months ended June 30, 2009, which was reclassified from AOCL to income because the forecasted hedged transactions were deemed no longer probable.
As of June 30, 2009 and December 31, 2008, PHIs Competitive Energy business had the following types and volumes of energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.
As described above, all premiums paid and other transaction costs incurred as part of DPLs natural gas hedging activity, in addition to all gains and losses related to hedging activities, are deferred under SFAS No. 71 until recovered based on the fuel adjustment clause approved by the DPSC. The following table indicates the amounts deferred as regulatory assets or liabilities and the location in the consolidated statements of income of amounts reclassified to income through the fuel adjustment clause for the three and six months ended June 30, 2009 and 2008:
As of June 30, 2009 and December 31, 2008, Power Delivery had the following outstanding commodity forward contracts that were entered into to hedge forecasted transactions:
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
The table below provides details regarding effective cash flow hedges under SFAS No. 133 included in PHIs consolidated balance sheet as of June 30, 2009. Under SFAS No. 133, cash flow hedges are marked-to-market on the balance sheet with corresponding adjustments to AOCL. The data in the table indicate the cumulative net gain (loss) after-tax related to effective cash flow hedges by contract type included in AOCL, the portion of AOCL expected to be reclassified to income during the next 12 months, and the maximum hedge or deferral term:
Fair Value Hedges
In connection with its energy commodity activities, the Competitive Energy business designates certain derivatives as fair value hedges. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk is recognized in current income. For the three and six months ended June 30, 2009 and 2008, the amount of the derivative net gain (loss) on energy commodity contracts recognized for hedges, by consolidated statements of income line item, is as follows:
As of June 30, 2009 and December 31, 2008, PHIs Competitive Energy business had the following outstanding commodity forward contracts volumes and net position on derivatives that were accounted for as fair value hedges of fuel inventory and natural gas transportation:
Other Derivative Activity
Competitive Energy Business
In connection with its energy commodity activities, the Competitive Energy business holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value through income with corresponding adjustments on the balance sheet.
For the three and six months ended June 30, 2009 and 2008, the amount of the derivative gain (loss) in the Competitive Energy business recognized in income is provided in the table below:
As of June 30, 2009 and December 31, 2008, PHIs Competitive Energy business had the following net outstanding commodity forward contract volumes and net position on derivatives that did not qualify for hedge accounting:
DPL holds certain derivatives that do not qualify as hedges. Under SFAS No. 133, these derivatives are recorded at fair value on the balance sheet with the gain or loss recorded in income. In accordance with SFAS No. 71, offsetting regulatory assets or regulatory liabilities are recorded on the balance sheet and the recognition of the gain or recovery of the loss is deferred. For the three and six months ended June 30, 2009 and 2008, the amount of the derivative gain (loss) recognized by line item in the consolidated statements of income is provided in the table below:
As of June 30, 2009 and December 31, 2008, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:
Contingent Credit Risk Features
The primary contracts used by the Competitive Energy and Power Delivery businesses for derivative transactions are entered into under the International Swaps and Derivatives Association Master Agreement (ISDA) or similar agreements that closely mirror the principal credit provisions of the ISDA. The ISDAs include a Credit Support Annex (CSA) that governs the mutual posting and administration of collateral security. The failure of a party to comply with an obligation under the CSA, including an obligation to transfer collateral security when due or the failure to maintain any required credit support, constitutes an event of default under the ISDA for which the other party may declare an early termination and liquidation of all transactions entered into under the ISDA, including foreclosure against any collateral security. In addition, some of the ISDAs have cross default provisions under which a default by a party under another commodity or derivative contract, or the breach by a party of another borrowing obligation in excess of a specified threshold, is a breach under the ISDA.
The collateral requirements under the ISDA or similar agreements generally work as follows. The parties establish a dollar threshold of unsecured credit for each party in excess of which the party would be required to post collateral to secure its obligations to the other party. The amount of the unsecured credit threshold varies according to the senior, unsecured debt rating of the respective parties or that of a guarantor of the partys obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet under SFAS No. 133. If the aggregate fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The obligations of the Competitive Energy business are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHIs or DPLs credit rating were to fall below investment grade, the unsecured credit threshold would typically be set at zero and collateral would be required for the entire net loss position. Exchange-traded contracts do not contain this contingent credit risk feature related to credit rating as they are fully collateralized.
The gross fair value of PHIs derivative liabilities, excluding the impact of offsetting transactions or collateral under master netting agreements, with credit risk-related contingent features on June 30, 2009, was $475 million. As of that date, PHI had posted cash collateral of $42 million in the normal course of business against the gross derivative liability resulting in a net liability of $433 million before giving effect to offsetting transactions that are encompassed within master netting agreements that would reduce this amount. PHIs net settlement amount in the event of a downgrade of PHI and DPL below investment grade as of June 30, 2009, would have been approximately $295 million after taking into consideration the master netting agreements. The offsetting transactions or collateral that would reduce PHIs obligation to the net settlement amount include derivatives and normal purchase and normal sale contracts in a gain position as well as letters of credit already posted as collateral.
PHIs primary sources for posting cash collateral or letters of credit are its primary credit facilities. At June 30, 2009, the aggregate amount of cash plus borrowing capacity under the primary credit facilities available to meet the future liquidity needs of PHI totaled $1.5 billion, of which $915 million was available for the Competitive Energy business.
(13) FAIR VALUE DISCLOSURES
Fair Value of Assets and Liabilities Excluding Debt
Effective January 1, 2008, PHI adopted SFAS No. 157 which established a framework for measuring fair value and expanded disclosures about fair value measurements.
As defined in SFAS No. 157, 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 (exit price). PHI utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Accordingly, PHI utilizes valuation techniques that maximize the use of observable inputs and
minimize the use of unobservable inputs. PHI is able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:
Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using broker quotes in liquid markets, and other observable pricing data. Level 2 also includes those financial instruments that are valued using internally developed methodologies that have been corroborated by observable market data through correlation or by other means. Significant assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 Pricing inputs include significant inputs that are generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies. Level 3 instruments classified as derivative liabilities are primarily natural gas options. Some non-standard assumptions are used in their forward valuation to adjust for the pricing; otherwise, most of the options follow NYMEX valuation. A few of the options have no significant NYMEX components, and have to be priced using internal volatility assumptions. Some of the options do not expire until December 2011. All of the options are part of the natural gas hedging program approved by the Delaware Public Service Commission.
Level 3 instruments classified as executive deferred compensation plan assets and liabilities are life insurance policies that are valued using the cash surrender value of the policies. Since these values do not represent a quoted price in an active market they are considered Level 3.
The following tables set forth by level within the fair value hierarchy PHIs financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009 and December 31, 2008. As required by SFAS No. 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. PHIs assessment of the significance of a particular input to the fair value measurement requires the exercise of judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Reconciliations of the beginning and ending balances of PHIs fair value measurements using significant unobservable inputs (Level 3) for the six months ended June 30, 2009 and 2008 are shown below:
Fair Value of Debt Instruments
The estimated fair values of PHIs non-derivative financial instruments at June 30, 2009 and December 31, 2008 are shown below:
The methods and assumptions described below were used to estimate, as of June 30, 2009 and December 31, 2008, the fair value of each class of non-derivative financial instruments shown above for which it is practicable to estimate a value.
The fair value of long-term debt issued by PHI and its utility subsidiaries was based on actual trade prices as of June 30, 2009 and December 31, 2008, or bid prices obtained from brokers if actual trade prices were not available. The fair values of Long-Term Debt and Transition Bonds issued by ACE Funding, including amounts due within one year, were derived based on current market prices, or were based on discounted cash flows using current rates for similar issues with similar credit ratings, terms, and remaining maturities for issues with no market price available.
The fair value of the Redeemable Serial Preferred Stock, excluding amounts due within one year, was derived based on quoted market prices or discounted cash flows using current rates for preferred stock with similar terms.
The carrying amounts of all other financial instruments in Pepco Holdings accompanying financial statements approximate fair value.
(14) COMMITMENTS AND CONTINGENCIES
Regulatory and Other Matters
Proceeds from Settlement of Mirant Bankruptcy Claims
In 2000, Pepco sold substantially all of its electricity generating assets to Mirant Corporation (Mirant). As part of the sale, Pepco and Mirant entered into a back-to-back arrangement, whereby Mirant agreed to purchase from Pepco the 230 megawatts of electricity and capacity that Pepco was obligated to purchase annually through 2021 from Panda under the Panda PPA at the purchase price Pepco was obligated to pay to Panda. In 2003, Mirant commenced a voluntary bankruptcy proceeding in which it sought to reject certain obligations that it had undertaken in connection with the asset sale. As part of the settlement of Pepcos claims against Mirant arising from the bankruptcy, Pepco agreed not to contest the rejection by Mirant of its obligations under the back-to-back arrangement in exchange for the payment by Mirant of damages corresponding to the estimated amount by which the purchase price that Pepco was obligated to pay Panda for the energy and capacity exceeded the market price. In 2007, Pepco received as damages $414 million in net proceeds from the sale of shares of Mirant common stock issued to it by Mirant. In September 2008, Pepco transferred the Panda PPA to Sempra, along with a payment to Sempra, thereby terminating all further rights, obligations and liabilities of Pepco under the Panda PPA. In November 2008, Pepco filed with the District of Columbia Public Service Commission (DCPSC) and the Maryland Public Service Commission (MPSC) proposals to share with customers the remaining balance of proceeds from the Mirant settlement in accordance with divestiture sharing formulas approved previously by the respective commissions.
In March 2009, the DCPSC issued an order approving Pepcos sharing proposal for the District of Columbia under which approximately $24 million was distributed to District of Columbia customers as a one-time billing credit. As a result of this decision, Pepco recorded a pre-tax gain of approximately $14 million for the quarter ended March 31, 2009.
On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland office of Peoples Counsel (the Maryland OPC) and the MPSC staff under which Pepco will distribute approximately $39 million to Maryland customers during the billing month of August 2009 through a one-time billing credit. As a result of this decision, Pepco expects to record a pre-tax gain between $26 million and $28 million in the quarter ending September 30, 2009.
As of June 30, 2009, approximately $64 million in remaining proceeds from the Mirant settlement was accounted for as restricted cash and as a regulatory liability. In the third quarter of 2009, the restricted cash will be released and the regulatory liability will be extinguished as a consequence of the MPSC order.
In recent electric service and natural gas distribution base rate cases, PHIs utility subsidiaries have proposed the adoption of a bill stabilization adjustment mechanism (BSA) for retail customers. To date:
Under the BSA, customer delivery rates are subject to adjustment (through a surcharge or credit mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the approved revenue-per-customer amount. The BSA increases rates if actual distribution revenues fall below the level approved by the applicable commission and decreases rates if actual distribution revenues are above the approved level. The result is that, over time, the utility collects its authorized revenues for distribution deliveries. As a consequence, a BSA decouples revenue from unit sales
consumption and ties the growth in revenues to the growth in the number of customers. Some advantages of the BSA are that it (i) eliminates revenue fluctuations due to weather and changes in customer usage patterns and, therefore, provides for more predictable utility distribution revenues that are better aligned with costs, (ii) provides for more reliable fixed-cost recovery, (iii) tends to stabilize customers delivery bills, and (iv) removes any disincentives for the regulated utilities to promote energy efficiency programs for their customers, because it breaks the link between overall sales volumes and delivery revenues. The MFVRD adopted in Delaware relies primarily upon a fixed customer charge (i.e., not tied to the customers volumetric consumption) to recover the utilitys fixed costs, plus a reasonable rate of return. Although different from the BSA, PHI views the MFVRD as an appropriate revenue decoupling mechanism.
In August 2008, DPL submitted its 2008 Gas Cost Rate (GCR) filing to the DPSC, requesting an increase in the level of GCR. In September 2008, the DPSC issued an initial order approving the requested increase, which became effective on November 1, 2008, subject to refund pending final DPSC approval after evidentiary hearings. Due to a significant decrease in wholesale gas prices, in January 2009, DPL submitted to the DPSC an interim GCR filing, requesting a decrease in the level of GCR. The proposed decrease, when combined with the increase that became effective November 1, 2008, would have the net effect of a 13.8% increase in the level of GCR. On February 5, 2009, the DPSC issued an initial order approving the net increase, effective on March 1, 2009, subject to refund pending final DPSC approval after evidentiary hearings. A hearing was held on May 27, 2009, during which a settlement agreement among DPL, DPSC staff and the Delaware Public Advocate was submitted to the Hearing Examiner. The settlement agreement provided that the proposed net increase would become final and no longer subject to refund. The Hearing Examiners report recommending approval of the settlement agreement was issued on July 21, 2009. DPSC approval of the settlement agreement is pending.
On June 25, 2009, DPL filed two applications requesting approval of the MFVRD for electric distribution rates and gas distribution rates, respectively. These filings are based on revenues established in DPLs last electric and gas distribution base rate cases, and accordingly are revenue neutral.
District of Columbia
In December 2006, Pepco submitted an application to the DCPSC to increase electric distribution base rates, including a proposed BSA. In January 2008, the DCPSC approved, effective February 20, 2008, a revenue requirement increase of approximately $28 million, based on an authorized return on rate base of 7.96%, including a 10% return on equity (ROE). However, the DCPSC did not approve the BSA at that time. While finding a BSA to be an appropriate ratemaking concept, the DCPSC cited potential statutory problems in its authority to implement the BSA. In February 2008, the DCPSC established a Phase II proceeding to consider these implementation issues. In August 2008, the DCPSC issued an order concluding that it has the necessary statutory authority to implement the BSA proposal and that further evidentiary proceedings are warranted to determine whether the BSA is just and reasonable. On January 2, 2009, the DCPSC issued an order designating the issues and establishing a procedural schedule for the BSA proceeding. Hearings were held on May 12, 2009, followed by post-hearing briefs filed on May 29, 2009 and June 12, 2009. A decision by the DCPSC is pending.
In June 2008, the District of Columbia Office of Peoples Counsel (the DC OPC), citing alleged errors by the DCPSC, filed with the DCPSC a motion for reconsideration of the January 2008 order granting Pepcos rate increase. The DC OPCs motion was denied by the DCPSC and, in August 2008, the DC OPC filed with the District of Columbia Court of Appeals a petition for review of the DCPSCs order denying its motion for reconsideration. Briefs have been filed by the parties and oral argument was held on March 23, 2009. Pepco expects a decision by the end of the third quarter 2009.
On May 22, 2009, Pepco submitted an application to the DCPSC to increase electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $52 million, based on a requested ROE of 11.50% (or, if the BSA is approved in Phase II of the rate case filed in December 2006, the requested rate increase would be reduced to approximately $50 million, based on an ROE of 11.25%). The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $3 million. Hearings are scheduled for mid-November 2009 and a decision is expected from the DCPSC in early 2010.
In July 2007, the MPSC issued orders in the electric service distribution rate cases filed by DPL and Pepco, each of which included approval of a BSA. The DPL order approved an annual increase in distribution rates of approximately $15 million (including a decrease in annual depreciation expense of approximately $1 million). The Pepco order approved an annual increase in distribution rates of approximately $11 million (including a decrease in annual depreciation expense of approximately $31 million). In each case, the approved distribution rate reflects an ROE of 10%. The rate increases were effective as of June 16, 2007, and remained in effect for an initial period until July 19, 2008, pending a Phase II proceeding in which the MPSC considered the results of audits of each companys cost allocation manual, as filed with the MPSC, to determine whether a further adjustment to the rates was required. In July 2008, the MPSC issued one order covering the Phase II proceedings for both DPL and Pepco, denying any further adjustment to the rates for each company, thus making permanent the rate increases approved in the July 2007 orders. The MPSC also issued an order in August 2008, further explaining its July 2008 order.
DPL and Pepco each appealed the MPSCs July 2007, July 2008 and August 2008 orders. The case currently is pending before the Circuit Court for Baltimore City, which issued an order consolidating the appeals on January 27, 2009. In a consolidated brief filed on March 9, 2009, Pepco and DPL each contend that the MPSC erred in failing to implement permanent rates in accordance with Maryland law, and in its denial of their respective rights to recover an increased share of the PHI Service Company costs and the costs of performing a MPSC-mandated management audit. The MPSC and OPC filed briefs on April 23, 2009 and oral arguments were held on May 12, 2009. A decision by the Circuit Court is pending.
On May 6, 2009, DPL filed a distribution base rate case in Maryland. The filing seeks approval of an annual rate increase of approximately $14 million, based on a requested ROE of 11.25%. The filing also proposes recovery of pension expenses and uncollectible costs through a surcharge mechanism. If the proposed surcharge mechanism is approved, the requested annual rate increase would be reduced by approximately $4 million. Hearings are scheduled for September 21 through September 24, 2009, with a decision expected from the MPSC in December 2009.
On February 20, 2009, ACE filed an application with the New Jersey Board of Public Utilities (NJBPU) (supplemented on February 23, 2009), which included a proposal for the implementation of a BSA. Under New Jersey law, the NJBPU is required to approve, modify or deny the application within 180 days. The NJBPU has advised ACE that the 180-day period commenced on February 23, 2009 and, therefore, unless otherwise extended by the parties by consent, ACE anticipates that NJBPU will act on ACEs application by late August 2009.
District of Columbia
In June 2000, the DCPSC approved a divestiture settlement under which Pepco is required to share with its District of Columbia customers the net proceeds realized by Pepco from the sale of its generation-related assets. An unresolved issue relating to the application filed with the DCPSC by Pepco to implement the divestiture settlement is whether Pepco should be required to share with customers the excess deferred income taxes (EDIT) and accumulated deferred investment tax credits (ADITC) associated with the sold assets and, if so, whether such sharing would violate the normalization provisions of the Internal Revenue Code and its implementing regulations. As of June 30, 2009, the District of Columbia allocated portions of EDIT and ADITC associated with the divested generating assets were approximately $6 million each. Other issues in the divestiture proceeding deal with the treatment of internal costs and cost allocations as deductions from the gross proceeds of the divestiture.
Pepco believes that a sharing of EDIT and ADITC would violate the IRS normalization rules. Under these rules, Pepco could not transfer the EDIT and the ADITC benefit to customers more quickly than on a straight line basis over the book life of the related assets. Since the assets are no longer owned by Pepco, there is no book life over which the EDIT and ADITC can be returned. If Pepco were required to share EDIT and ADITC and, as a result, the normalization rules were violated, Pepco would be unable to use accelerated depreciation on District of Columbia allocated or assigned property. In addition to sharing with customers the generation-related EDIT and ADITC balances, Pepco would have to pay to the IRS an amount equal to Pepcos District of Columbia jurisdictional generation-related ADITC balance ($6 million as of June 30, 2009), as well as its District of Columbia jurisdictional transmission and distribution-related ADITC balance ($3 million as of June 30, 2009) in each case as those balances exist as of the later of the date a DCPSC order is issued and all rights to appeal have been exhausted or lapsed, or the date the DCPSC order becomes operative.
In March 2008, the IRS approved final regulations, effective March 20, 2008, which allow utilities whose assets cease to be utility property (whether by disposition, deregulation or otherwise) to return to its utility customers the normalization reserve for EDIT and part or all of the normalization reserve for ADITC. This ruling applies to assets divested after December 21, 2005. For utility property divested on or before December 21, 2005, the IRS stated that it would continue to follow the holdings set forth in private letter rulings prohibiting the flow through of EDIT and ADITC associated with the divested assets. Pepco made a filing in April 2008, advising the DCPSC of the adoption of the final regulations and requesting that the DCPSC issue an order consistent with the IRS position. If the DCPSC issues the requested order, no accounting adjustments to the gain recorded in 2000 would be required.
As part of the proposal filed with the DCPSC in November 2008 concerning the sharing of the proceeds of the Mirant settlement, as discussed above under Proceeds from Settlement of Mirant Bankruptcy Claims, Pepco again requested that the DCPSC rule on all of the issues related to the divestiture of Pepcos generating assets that remain outstanding. On March 5, 2009, the DCPSC issued an order approving Pepcos proposal for sharing the remaining balance of the proceeds from the Mirant settlement; however, the DCPSC did not rule on the other outstanding issues concerning the divestiture of Pepcos generating assets.
Pepco believes that its calculation of the District of Columbia customers share of divestiture proceeds is correct. However, depending on the ultimate outcome of this proceeding, Pepco could be required to make additional gain-sharing payments to District of Columbia customers, including the payments described above related to EDIT and ADITC. Such additional payments (which, other than the EDIT and ADITC related payments, cannot be estimated) would be charged to expense in the quarter and year in which a final decision is rendered and could have a material adverse effect on Pepcos and PHIs results of operations for those periods. However, neither PHI nor Pepco believes that additional gain-sharing payments, if any, or the ADITC-related payments to the IRS, if required, would have a material adverse impact on its financial position or cash flows.
Pepco filed its divestiture proceeds plan application with the MPSC in April 2001. The principal issue in the Maryland case is the same EDIT and ADITC sharing issue that has been raised in the District of Columbia case. See the discussion above under Divestiture Cases District of Columbia. On July 2, 2009, the MPSC approved a settlement agreement among Pepco, the Maryland OPC and the MPSC staff with respect to all of the open divestiture plan issues. Under the settlement agreement, Pepco is permitted to retain the entire amount of the Maryland allocated portions of EDIT and ADITC (approximately $9 million and $10 million, respectively) associated with Pepcos divested generating assets. As a result of the settlement, no accounting adjustments to the gain recorded in 2000 are required.
ACE Sale of B.L. England Generating Facility
In February 2007, ACE completed the sale of the B.L. England generating facility to RC Cape May Holdings, LLC (RC Cape May), an affiliate of Rockland Capital Energy Investments, LLC. In July 2007, ACE received a claim for indemnification from RC Cape May under the purchase agreement in the amount of $25 million. RC Cape May contends that one of the assets it purchased, a contract for terminal services (TSA) between ACE and Citgo Asphalt Refining Co. (Citgo), has been declared by Citgo to have been terminated due to a failure by ACE to renew the contract in a timely manner. The claim for indemnification seeks payment from ACE in the event the TSA is held not to be enforceable against Citgo.
RC Cape May commenced an arbitration proceeding against Citgo seeking a determination that the TSA remains in effect and notified ACE of the proceedings. On July 1, 2009, the arbitrator issued its interim award, ruling that the TSA remains in effect and is enforceable by RC Cape May against Citgo. PHI believes this ruling invalidates RC Cape Mays indemnification claim against ACE, but cannot predict whether RC Cape May will continue to pursue indemnification.
In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince Georges County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as In re: Personal Injury Asbestos Case. Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepcos property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings are not entirely clear, it appears that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant.
Since the initial filings in 1993, additional individual suits have been filed against Pepco, and significant numbers of cases have been dismissed. As a result of two motions to dismiss, numerous hearings and meetings and one motion for summary judgment, Pepco has had approximately 400 of these cases successfully dismissed with prejudice, either voluntarily by the plaintiff or by the court. As of June 30, 2009, there are approximately 180 cases still pending against Pepco in the State Courts of Maryland, of which approximately 90 cases were filed after December 19, 2000, and were tendered to Mirant for defense and indemnification pursuant to the terms of the Asset Purchase and Sale Agreement between Pepco and Mirant under which Pepco sold its generation assets to Mirant in 2000.
While the aggregate amount of monetary damages sought in the remaining suits (excluding those tendered to Mirant) is approximately $360 million, PHI and Pepco believe the amounts claimed by the remaining plaintiffs are greatly exaggerated. The amount of total liability, if any, and any related insurance recovery cannot be determined at this time; however, based on information and relevant circumstances known at this time, neither PHI nor Pepco believes these suits will have a material adverse effect on its financial position, results of operations or cash flows. However, if an unfavorable decision were rendered against Pepco, it could have a material adverse effect on Pepcos and PHIs financial position, results of operations or cash flows.
PHI, through its subsidiaries, is subject to regulation by various federal, regional, state, and local authorities with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitations on land use. In addition, federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or unremediated hazardous waste sites. PHIs subsidiaries may incur costs to clean up currently or formerly owned facilities or sites found to be contaminated, as well as other facilities or sites that may have been contaminated due to past disposal practices. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of the operating utilities, environmental clean-up costs incurred by Pepco, DPL and ACE would be included by each company in its respective cost of service for ratemaking purposes.
Delilah Road Landfill Site. In 1991, the New Jersey Department of Environmental Protection (NJDEP) identified ACE as a potentially responsible party (PRP) at the Delilah Road Landfill site in Egg Harbor Township, New Jersey. In 1993, ACE, along with two other PRPs, signed an administrative consent order with NJDEP to remediate the site. The soil cap remedy for the site has been implemented and in August 2006, NJDEP issued a No Further Action Letter (NFA) and Covenant Not to Sue for the site. Among other things, the NFA requires the PRPs to monitor the effectiveness of institutional (deed restriction) and engineering (cap) controls at the site every two years. In September 2007, NJDEP
approved the PRP groups petition to conduct semi-annual, rather than quarterly, ground water monitoring for two years and deferred until the end of the two-year period a decision on the PRP groups request for annual groundwater monitoring thereafter. In August 2007, the PRP group agreed to reimburse the costs of the U.S. Environmental Protection Agency (EPA) in the amount of $81,400 in full satisfaction of EPAs claims for all past and future response costs relating to the site (of which ACEs share is one-third). Effective April 2008, EPA and the PRP group entered into a settlement agreement which will allow EPA to reopen the settlement in the event of new information or unknown conditions at the site. Based on information currently available, ACE anticipates that its share of additional cost associated with this site for post-remedy operation and maintenance will be approximately $555,000 to $600,000. On November 23, 2008, Lenox, Inc., a member of the PRP group, filed a bankruptcy petition under Chapter 11 of the U.S. Bankruptcy Code. ACE has filed a proof of claim in the Lenox bankruptcy seeking damages resulting from the rejection by Lenox, Inc., of its cost sharing obligations to ACE. ACE believes that its liability for post-remedy operation and maintenance costs will not have a material adverse effect on its financial position, results of operations or cash flows regardless of the impact of the Lenox bankruptcy.
Frontier Chemical Site. In June 2007, ACE received a letter from the New York Department of Environmental Conservation (NYDEC) identifying ACE as a PRP at the Frontier Chemical Waste Processing Company site in Niagara Falls, N.Y. based on hazardous waste manifests indicating that ACE sent in excess of 7,500 gallons of manifested hazardous waste to the site. ACE has entered into an agreement with the other parties identified as PRPs to form a PRP group and has informed NYDEC that it has entered into good faith negotiations with the PRP group to address ACEs responsibility at the site. ACE believes that its responsibility at the site will not have a material adverse effect on its financial position, results of operations or cash flows.
Franklin Slag Pile Site. On November 26, 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a PRP that may have liability with respect to the site. If liable, ACE would be responsible for reimbursing EPA for clean-up costs incurred and to be incurred by the agency and for the costs of implementing an EPA-mandated remedy. The EPAs claims are based on ACEs sale of boiler slag from the B.L. England generating facility to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983 (ACE owned B.L. England at that time and MDC formerly operated the Franklin Slag Pile site). EPA further claims that the boiler slag ACE sold to MDC contained copper and lead, which are hazardous substances under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (CERCLA), and that the sales transactions may have constituted an arrangement for the disposal or treatment of hazardous substances at the site, which could be a basis for liability under CERCLA. The EPAs letter also states that as of the date of the letter, EPAs expenditures for response measures at the site exceed $6 million. EPA estimates approximately $6 million as the cost for future response measures it recommends. ACE understands that the EPA sent similar general notice letters to three other companies and various individuals.
ACE believes that the B.L. England boiler slag sold to MDC was a valuable material with various industrial applications, and therefore, the sale was not an arrangement for the disposal or treatment of any hazardous substances as would be necessary to constitute a basis for liability under CERCLA. ACE intends to contest any such claims made by the EPA. In a May 2009 decision arising under CERCLA, which did not involve ACE, the U.S. Supreme Court rejected an EPA argument that the sale of a useful product constituted an arrangement for disposal or treatment of hazardous substances. While this decision is helpful to ACEs position, at this time ACE cannot predict how EPA will proceed with respect to the Franklin Slag Pile site, or what portion, if any, of the Franklin Slag Pile site response costs EPA would seek to recover from ACE.
Peck Iron and Metal Site. EPA informed Pepco in a May 20, 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, or for costs EPA has incurred in cleaning up the site. EPAs letter alleges that Pepco arranged for disposal or treatment of hazardous substances sent to the site. Pepco has advised the EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales are entitled to the recyclable material exemption from CERCLA liability. At this time Pepco cannot predict how EPA will proceed regarding this matter, or what portion, if any, of the Peck Iron and Metal Site response costs EPA would seek to recover from Pepco.
Ward Transformer Site. In April 2009, a group of PRPs at the Ward Transformer site in Raleigh, North Carolina, filed a complaint in the U.S. District Court for the Eastern District of North Carolina, alleging that the group has cost recovery and/or contribution claims against ACE, DPL and Pepco with respect to past and future response costs incurred in performing a removal action at the site. ACE, DPL and Pepco have not yet been served with the complaint.
Deepwater Generating Facility. In December 2005, NJDEP issued a Title V operating permit (the 2005 Permit) to Deepwater generating facility (Deepwater) owned by Conectiv Energy. In January 2006, Conectiv Energy filed an appeal with the New Jersey Office of Administrative Law (OAL) challenging several provisions of the 2005 Permit, including newly imposed limits on unit heat input (which is energy introduced to the boiler in the form of fuel). In an October 2007 order, the OAL granted a summary decision in favor of Conectiv Energy, finding that hourly heat input may not be used as a basis to condition or limit Conectiv Energys electric generating operations. In January 2008, NJDEP issued a revised Deepwater Title V operating permit (the 2008 Permit), which included the challenged conditions from the 2005 Permit, in response to which Conectiv Energy filed a second appeal with the OAL. In a December 2008 order, the OAL resolved Conectiv Energys challenge to the 2005 and 2008 Permits provision limiting annual fuel use in favor of Conectiv Energy and resolved Conectiv Energys challenge to an annual stack test requirement in favor of NJDEP. In May 2009, NJDEP and Conectiv Energy entered into a Stipulation of Partial Settlement (the Stipulation) that would resolve all of Conectiv Energys challenges to the terms of the 2005 Permit and the 2008 Permit, other than the three permit provisions relating to heat input, annual fuel use, and annual stack testing that the OAL had resolved. On July 23, 2009, the OAL amended its October 2007 order in favor of Conectiv Energy to clarify that neither annual nor hourly heat input may be used as a basis to condition or limit Conectiv Energys electric generating operations. On July 29, 2009, the OAL issued its initial recommended decision incorporating its October 2007 order (as amended July 23, 2009) and the Stipulation, and transmitting the matter back to the NJDEP Commissioner for a final decision adopting, rejecting or modifying the OAL recommended decision. The OALs July 29 recommended decision resolves all of the outstanding issues that were the subject of Conectiv Energy appeals, subject to the final decision from the NJDEP Commissioner.
In April 2007, NJDEP issued an Administrative Order and Notice of Civil Administrative Penalty Assessment (the April 2007 Order) alleging that Deepwater Unit 1 exceeded the maximum allowable heat input in calendar year 2005 and that Unit 6/8 exceeded its maximum allowable heat input in calendar years 2005 and 2006. The April 2007 Order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels, assessed a penalty of approximately $1 million and requested that Conectiv Energy provide additional information about heat input to Units 1 and 6/8. In May 2007, NJDEP issued a second Administrative Order and Notice of Civil Administrative Penalty Assessment (the May 2007 Order) alleging that Units 1 and 6/8 exceeded their maximum allowable heat input in calendar year 2004. The May 2007 Order required the cessation of operation of Units 1 and 6/8 above the alleged permitted heat input levels and assessed a penalty of $811,600. Conectiv Energy requested contested case hearings challenging the issuance of the April 2007 Order and the May 2007 Order. The OAL has placed these matters on inactive status until December 1, 2009.
In February 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the February 2008 Revocation Order) revoking the 2008 Permit. The February 2008 Revocation Order contended that Deepwater Unit 6/8 operated in violation of its emission limit for hydrogen chloride (HCl) and total suspended particles (TSP) during a December 2007 stack test, and assessed a $20,000 penalty for the alleged HCl incident and a $10,000 penalty for the alleged TSP incident. In September 2008, NJDEP issued an Administrative Order of Revocation and Notice of Civil Administrative Penalty Assessment (the September 2008 Revocation Order) requiring Conectiv Energy to operate Deepwater Unit 6/8 in compliance with its HCl limit or in the alternative revoking Unit 6/8s 2008 Permit. The September 2008 Revocation Order contended that Unit 6/8 violated the HCl limit on 106 days between December 2007 and April 2008 stack tests, and assessed a penalty of approximately $5 million. Conectiv Energy filed timely appeals of the February 2008 Revocation Order and the September 2008 Revocation Order with the OAL. In January 2009, Conectiv Energy and NJDEP entered into a settlement agreement with the NJDEP to resolve the $10,000 penalty for the TSP violations alleged in the February 2008 Revocation Order (the TSP Settlement). Under the terms of the TSP Settlement, NJDEP agreed to not assess an additional $16,000 administrative penalty for an alleged violation of the TSP limit during an April 4, 2008 stack test and Conectiv Energy agreed to pay a $20,800 penalty. On May 29, 2009, Conectiv Energy entered into a settlement agreement with NJDEP to resolve the HCl violations alleged in the February
2008 Revocation Order and the September 2008 Revocation Order (the HCl Settlement). Under the terms of the HCl Settlement, Deepwater Unit 6/8 is required to (1) utilize hydrated lime injection technology to control HCl emissions, (2) comply with the agreed upon hourly HCl emission limit, (3) demonstrate compliance with that limit for each stack test run without averaging stack test re