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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, 2012
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.
Some of the statements contained in this Quarterly Report on Form 10-Q with respect to Pepco Holdings, Inc. (PHI or Pepco Holdings), Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (DPL) and Atlantic City Electric Company (ACE), including each of their respective subsidiaries, are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), and Section 27A of the Securities Act of 1933, as amended, and are subject to the safe harbor created thereby and by the Private Securities Litigation Reform Act of 1995. These statements include declarations regarding the intents, beliefs, estimates and current expectations of one or more of PHI, Pepco, DPL or ACE (each, a Reporting Company) or their subsidiaries. In some cases, you can identify forward-looking statements by terminology such as may, might, will, should, could, expects, intends, assumes, seeks to, plans, anticipates, believes, projects, estimates, predicts, potential, future, goal, objective, or continue or the negative of such terms or other variations thereof or comparable terminology, or by discussions of strategy that involve risks and uncertainties. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause one or more Reporting Companies or their subsidiaries actual results, levels of activity, performance or achievements to be materially different from any future results, levels of activity, performance or achievements expressed or implied by such forward-looking statements. Therefore, forward-looking statements are not guarantees or assurances of future performance, and actual results could differ materially from those indicated by the forward-looking statements.
The forward-looking statements contained herein are qualified in their entirety by reference to the following important factors, which are difficult to predict, contain uncertainties, are beyond each Reporting Companys or its subsidiaries control and may cause actual results to differ materially from those contained in forward-looking statements:
These forward-looking statements are also qualified by, and should be read together with, the risk factors included in Part I,
Item 1A. Risk Factors and other statements in each Reporting Companys annual report on Form 10-K for the year ended December 31, 2011, as amended to include the executive compensation and other information required by Part III of Form 10-K (which information originally had been omitted as permitted by that form) (2011 Form 10-K), as filed with the Securities and Exchange Commission (SEC), in each Reporting Companys quarterly report on Form 10-Q for the quarter ended March 31, 2012, and in this Form 10-Q, and investors should refer to such risk factors and other statements in evaluating the forward-looking statements contained in this Form 10-Q.
Any forward-looking statements speak only as to the date this Quarterly Report on Form 10-Q for each Reporting Company was filed with the SEC, and none of the Reporting Companies undertakes an obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for a Reporting Company to predict all such factors, nor can the impact of any such factor be assessed on such Reporting Companys or its subsidiaries business (viewed independently or together with the business or businesses of some or all of the other Reporting Companies or their subsidiaries) or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. The foregoing factors should not be construed as exhaustive.
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.
PEPCO HOLDINGS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF EQUITY
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 holding company that, through the following regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas:
Each of PHI, Pepco, DPL and ACE is also a Reporting Company under the Securities Exchange Act of 1934, as amended. Together, Pepco, DPL and ACE constitute the Power Delivery segment, for financial reporting purposes.
Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy savings performance contracting services, primarily to commercial, industrial and government customers. Pepco Energy Services is in the process of winding down its competitive electricity and natural gas retail supply business. Pepco Energy Services constitutes a separate segment, for financial reporting purposes.
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 PHI Service Company are charged to PHI and the participating operating subsidiaries in accordance with cost allocation methodologies set forth in the service agreement.
Each of Pepco, DPL and ACE is a regulated public utility in the jurisdictions that comprise its service territory. Each utility owns and operates a network of wires, substations and other equipment that is classified as transmission facilities, distribution facilities or common facilities (which are used for both transmission and distribution). 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.
Each utility is responsible for the distribution 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 utility 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 in Delaware, the District of Columbia and Maryland, and Basic Generation Service in New Jersey. In these Notes to the consolidated financial statements, these supply service obligations are referred to generally as Default Electricity Supply.
Pepco Energy Services
Pepco Energy Services is engaged in the following businesses:
Pepco Energy Services deactivated its Buzzard Point oil-fired generation facility on May 31, 2012 and its Benning Road oil-fired generation facility on June 30, 2012.
In December 2009, PHI announced the wind-down of the retail energy supply component of the Pepco Energy Services business. Pepco Energy Services is implementing this wind-down by not entering into any new supply contracts while continuing to perform under its existing supply contracts through their respective expiration dates, the last of which is June 1, 2014. The retail energy supply business has historically generated a substantial portion of the operating revenues and net income of the Pepco Energy Services segment. Operating revenues related to the retail energy supply business for the three months ended June 30, 2012 and 2011 were $112 million and $233 million, respectively, while operating income for the same periods was $16 million and $4 million, respectively. Operating revenues related to the retail energy supply business for the six months ended June 30, 2012 and 2011 were $273 million and $543 million, respectively, while operating income for the same periods was $31 million and $16 million, respectively.
In connection with the operation of the retail energy supply business, Pepco Energy Services provided letters of credit of less than $1 million and posted cash collateral of $61 million as of June 30, 2012. These collateral requirements, which are based on existing wholesale energy purchase and sale contracts and current market prices, will decrease as the contracts expire, with the collateral expected to be fully released by June 1, 2014. The energy services business will not be affected by the wind-down of the retail energy supply business.
Other Business Operations
Through its subsidiary Potomac Capital Investment Corporation (PCI), PHI maintains a portfolio of cross-border energy lease investments. This activity constitutes a third operating segment for financial reporting purposes, which is designated as Other Non-Regulated. For a discussion of PHIs cross-border energy lease investments, see Note (8), Leasing Activities Investment in Finance Leases Held in Trust, and Note (15), Commitments and Contingencies PHIs Cross-Border Energy Lease Investments to the consolidated financial statements of PHI.
In April 2010, the Board of Directors approved a plan for the disposition of PHIs competitive wholesale power generation, marketing and supply business, which had been conducted through subsidiaries of Conectiv Energy Holding Company (collectively Conectiv Energy). On July 1, 2010, PHI completed the sale of Conectiv Energys wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energys remaining assets and businesses, consisting of its load service supply contracts, energy hedging portfolio, certain tolling agreements and other assets not included in the Calpine sale, was completed in the first quarter of 2012. The former operations of Conectiv Energy have been accounted for as a discontinued operation and no longer constitute a separate segment for financial reporting purposes.
(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 consolidated financial statements prepared in accordance with GAAP have been omitted. Therefore, these consolidated financial statements should be read along with the annual consolidated financial statements included in PHIs annual report on Form 10-K for the year ended December 31, 2011, as amended to include the executive compensation and other information required by Part III of Form 10-K (which information originally had been omitted as permitted by that form). In the opinion of PHIs management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco Holdings financial condition as of June 30, 2012, in accordance with GAAP. The year-end December 31, 2011 consolidated balance sheet included herein was derived from audited consolidated financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended June 30, 2012 may not be indicative of PHIs results that will be realized for the full year ending December 31, 2012.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities in the consolidated financial statements and accompanying notes. Although Pepco Holdings believes that its estimates and assumptions are reasonable, they are based upon information available to management at the time the estimates are made. Actual results may differ significantly from these estimates.
Significant matters that involve the use of estimates include the assessment of contingencies, the calculation of future cash flows and fair value amounts for use in asset and goodwill impairment calculations, fair value calculations for derivative instruments, pension and other postretirement benefit assumptions, the assessment of the probability of recovery of regulatory assets, accrual of storm restoration costs, accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, accrual of self-insurance reserves for general and auto liability claims, accrual of interest related to income taxes, the recognition of income tax benefits for investments in finance leases held in trust associated with PHIs portfolio of cross-border energy lease investments, and income tax provisions and reserves. Additionally, PHI is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. PHI records an estimated liability for these proceedings and claims, when it is probable that a loss has been incurred and the loss is reasonably estimable.
Storm Restoration Costs
On June 29, 2012, the respective service territories of Pepco, DPL and ACE were affected by a rapidly moving thunderstorm with hurricane-force winds, known as a derecho, which resulted in widespread customer outages in each of the service territories. The derecho caused extensive damage to the electric transmission and distribution systems of Pepco, DPL and ACE. Storm restoration activity commenced immediately following the storm and continued into July 2012, with the majority of the incremental storm restoration costs occurring after the end of the second quarter of 2012.
Total incremental storm restoration costs incurred by PHI through June 30, 2012 were $3.0 million, with $1.8 million incurred for repair work and $1.2 million incurred as capital expenditures. Costs incurred for repair work of $1.5 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey, and $0.3 million was charged to Other operation and maintenance expense. All of these total incremental storm restoration costs have been estimated for the cost of restoration services provided by outside contractors since the invoices for such services had not been received at June 30, 2012. Actual invoices may vary from these estimates.
The total incremental storm restoration costs of PHI associated with the derecho are currently estimated to range between $70 million and $85 million. This range was developed using estimates of costs related to mutual assistance and contractor services, materials and supplies, and other expenses, and actual costs may vary from these estimates. A portion of the costs will be expensed with the balance being charged to capital. A portion of the costs expensed will be deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland and New Jersey. PHIs utility subsidiaries will be pursuing recovery of the incremental storm restoration costs in their respective jurisdictions during the next cycle of distribution base rate cases.
General and Auto Liability
During the second quarter of 2011, PHIs utility subsidiaries reduced their self-insurance reserves for general and auto liability claims by approximately $4 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for each of PHIs utility subsidiaries at June 30, 2011.
Consolidation of Variable Interest Entities
PHI assesses its contractual arrangements with variable interest entities to determine whether it is the primary beneficiary and thereby has to consolidate the entities in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 810. The guidance addresses conditions under which an entity should be consolidated based upon variable interests rather than voting interests. Subsidiaries of PHI have the following contractual arrangements to which the guidance applies.
ACE Power Purchase Agreements
PHI, through its ACE subsidiary, is a party to three power purchase agreements (PPAs) with unaffiliated, non-utility generators (NUGs) totaling 459 megawatts. One of the agreements ends in 2016 and the other two end in 2024. PHI was unable to obtain sufficient information to determine whether these three entities were variable interest entities or if ACE was the primary beneficiary. As a result, PHI applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.
Net purchase activities with the NUGs for the three months ended June 30, 2012 and 2011 were approximately $49 million and $55 million, respectively, of which approximately $47 million and $51 million, respectively, consisted of power purchases under the PPAs. Net purchase activities with the NUGs for the six months ended June 30, 2012 and 2011 were approximately $100 million and $112 million, respectively, of which approximately $98 million and $104 million, respectively, consisted of power purchases under the PPAs. The power purchase costs are recoverable from ACEs customers through regulated rates.
DPL Renewable Energy Transactions
DPL is subject to Renewable Energy Portfolio Standards (RPS) in the state of Delaware that require it to obtain renewable energy credits (RECs) for energy delivered to its customers. DPLs costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of June 30, 2012, PHI, through its DPL subsidiary, has entered into three land-based wind PPAs in the aggregate amount of 128 megawatts and one solar PPA with a 10 megawatt facility. All of the facilities associated with these PPAs are operational, and DPL is obligated to purchase energy and RECs in amounts generated and delivered by the wind facilities and solar renewable energy credits (SRECs) from the solar facility up to certain amounts (as set forth below) at rates that are primarily fixed under the PPAs. PHI has concluded that consolidation is not required for any of these PPAs under the FASB guidance on the consolidation of variable interest entities.
DPL is obligated to purchase energy and RECs from one of the wind facilities through 2024 in amounts not to exceed 50 megawatts, from the second wind facility through 2031 in amounts not to exceed 40 megawatts, and from the third wind facility through 2031 in amounts not to exceed 38 megawatts. DPLs purchases under the three wind PPAs totaled $6 million and $4 million for the three months ended June 30, 2012 and 2011, respectively, and $15 million and $9 million for the six months ended June 30, 2012 and 2011, respectively.
The term of the agreement with the solar facility is 20 years and DPL is obligated to purchase SRECs in an amount up to 70 percent of the energy output at a fixed price. DPLs purchases under the solar agreement were less than $1 million for the three and six months ended June 30, 2012.
On October 18, 2011, the Delaware Public Service Commission (DPSC) approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to fuel cell facilities totaling 30 megawatts to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL would be an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each megawatt hour of energy produced by the fuel cell facilities over 21 years. DPL would have no liability to the qualified fuel cell provider other than to remit payments collected from its distribution customers pursuant to the tariff. The RPS provides for a reduction in DPLs REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 megawatt fuel cell generation facility was placed into service under the tariff. DPL billed less than $1 million to distribution customers during the three and six months ended June 30, 2012. A 27 megawatt fuel cell generation facility is expected to be placed into service in 5 megawatt increments beginning in January 2013. DPL is accounting for this arrangement as an agency transaction.
Atlantic City Electric Transition Funding LLC
Atlantic City Electric Transition Funding LLC (ACE Funding) was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACEs recoverable stranded costs through the issuance and sale of bonds (Transition Bonds). The proceeds of the sale of each series of Transition Bonds have been transferred to ACE in exchange for the transfer by ACE to ACE Funding of the right to collect non-bypassable transition bond charges (the Transition Bond Charges) from ACE customers pursuant to bondable stranded costs rate orders issued by the New Jersey Board of Public Utilities (NJBPU) in an amount sufficient to fund the principal and interest payments on the Transition Bonds and related taxes, expenses and fees (Bondable Transition Property). ACE collects the Transition Bond Charges from its customers on behalf of ACE Funding and the holders of the Transition Bonds. The assets of ACE Funding, including the Bondable Transition Property, and the Transition Bond Charges collected from ACEs customers, are not available to creditors of ACE. The holders of the Transition Bonds have recourse only to the assets of ACE Funding. ACE owns 100 percent of the equity of ACE Funding and PHI consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.
ACE Standard Offer Capacity Agreements
In April 2011, ACE entered into three Standard Offer Capacity Agreements (SOCAs) by order of the NJBPU, each with a different generation company. The SOCAs were established under a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey. The SOCAs are 15-year, financially settled transactions approved by the NJBPU that allow generation companies to receive payments from, or require them to make payments to, ACE based on the difference between the fixed price in the SOCAs and the price for capacity that clears PJM Interconnection, LLC (PJM). Each of the other electric distribution companies (EDCs) in New Jersey has entered into SOCAs having the same terms with the same generation companies. The annual share of payments or receipts for ACE and the other EDCs is based upon each companys annual proportion of the total New Jersey load attributable to all EDCs, which is currently estimated to be approximately 15 percent for ACE. The NJBPU has approved full recovery from distribution customers of payments made by ACE and the other EDCs, and distribution customers would be entitled to any payments received from the generation companies.
In May 2012, all three generators under the SOCAs bid into the PJM 2015-2016 capacity auction and two of the generators cleared that capacity auction. ACE recorded a derivative asset (liability) for the estimated fair value of each SOCA and recorded an offsetting regulatory liability (asset) as described in more detail in Note (13), Derivative Instruments and Hedging Activities, and Note (14), Fair Value Disclosures. FASB guidance on derivative accounting and the accounting for regulated operations would apply to ACEs obligations under the third SOCA once the related capacity has cleared a PJM auction. The next PJM capacity auction is scheduled for May 2013. PHI has concluded that consolidation is not required for the SOCAs under the FASB guidance on the consolidation of variable interest entities.
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 (now Conectiv, LLC (Conectiv)) in 2002 and is allocated entirely to Power Delivery for purposes of impairment testing based on the aggregation of its components because its utilities have similar characteristics. Pepco Holdings tests its goodwill for impairment annually as of November 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 the carrying amount of its net assets. 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 PHIs 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 concluded that an interim impairment test was not required during the six months ended June 30, 2012.
Taxes Assessed by a Governmental Authority on Revenue-Producing Transactions
Taxes included in Pepco Holdings gross revenues were $93 million and $94 million for the three months ended June 30, 2012 and 2011, respectively, and $184 million and $190 million for the six months ended June 30, 2012 and 2011, respectively.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following reclassifications and adjustments have been recorded and are not considered material either individually or in the aggregate:
Pepco Energy Services Derivative Accounting Adjustments
In the second quarter of 2012, PHI recorded an adjustment to reclassify certain 2011 mark-to-market losses from Operating revenue to Fuel and purchased energy expenses for Pepco Energy Services. The reclassification resulted in an increase in Operating revenue and an increase in Fuel and purchased energy expenses of $3 million and $7 million for the three and six months ended June 30, 2011, respectively. This reclassification did not result in a change to net income.
During the first quarter of 2011, PHI recorded an adjustment associated with an increase in the value of certain derivatives from October 1, 2010 to December 31, 2010, which had been erroneously recorded in other comprehensive income at December 31, 2010. This adjustment resulted in an increase in revenue and pre-tax earnings of $2 million for the six months ended June 30, 2011.
DPL Operating Revenue Adjustment
In the second quarter of 2012, DPL recorded an adjustment to correct an overstatement of unbilled revenue in its natural gas distribution business related to prior periods. The adjustment resulted in a decrease in Operating revenue of $1 million for the three and six months ended June 30, 2012.
DPL Default Electricity Supply Revenue and Cost Adjustments
During the second quarter of 2011, DPL recorded adjustments to correct certain errors associated with the accounting for Default Electricity Supply revenue and costs. These adjustments primarily arose from the under-recognition of allowed returns on the cost of working capital and resulted in a pre-tax decrease in Other operation and maintenance expense of $8 million for the three and six months ended June 30, 2011.
Income Tax Expense Adjustments
In the second quarter of 2012, Pepco recorded an adjustment to reduce Income tax expense as a result of the reversal of interest expense erroneously recorded on certain effectively settled income tax positions in the first quarter of 2012. This adjustment resulted in a decrease to Income tax expense of $1 million for the three months ended June 30, 2012.
During the first quarter of 2011, Pepco recorded an adjustment to correct certain income tax errors related to prior periods associated with interest on uncertain tax positions. The adjustment resulted in an increase in Income tax expense of $1 million for the six months ended June 30, 2011.
(3) NEWLY ADOPTED ACCOUNTING STANDARDS
Fair Value Measurements and Disclosures (ASC 820)
The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with PHIs March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on PHIs consolidated financial statements and the new disclosure requirements are in Note (14), Fair Value Disclosures, of PHIs consolidated financial statements.
Comprehensive Income (ASC 220)
The FASB issued new disclosure requirements for reporting comprehensive income that were effective beginning with PHIs March 31, 2012 consolidated financial statements. PHI did not have to change the presentation of its comprehensive income because it had already reported comprehensive income in two separate but consecutive statements of income and comprehensive income. PHI also has provided the new required disclosures of the income tax effects of items in other comprehensive income or amounts reclassified from other comprehensive income to income on a quarterly basis in Note (16), Accumulated Other Comprehensive Loss.
Goodwill (ASC 350)
The FASB issued new guidance that changes the annual and interim assessments of goodwill for impairment. The new guidance modifies the required annual impairment test by giving entities the option to perform a qualitative assessment of whether it is more likely than not that goodwill is impaired before performing a quantitative assessment. The new guidance also amends the events and circumstances that entities should assess to determine whether an interim quantitative impairment test is necessary. As of January 1, 2012, PHI has adopted the new guidance and concluded it did not have a material impact on its consolidated financial statements.
(4) RECENTLY ISSUED ACCOUNTING STANDARDS, NOT YET ADOPTED
Balance Sheet (ASC 210)
In December 2011, the FASB issued new disclosure requirements for financial assets and liabilities, such as derivatives, that are subject to contractual netting arrangements. The new disclosures will include information about the gross exposures of the instruments and the net exposure of the instruments under contractual netting arrangements, how the exposures are presented in the financial statements, and the terms and conditions of the contractual netting arrangements. The new disclosures are effective beginning with PHIs March 31, 2013 consolidated financial statements. PHI is evaluating the impact of this new guidance on its consolidated financial statements.
(5) SEGMENT INFORMATION
Pepco Holdings management has identified its operating segments at June 30, 2012 as Power Delivery, Pepco Energy Services and Other Non-Regulated. In the tables below, the Corporate and Other column is included to reconcile the segment data with consolidated data and includes unallocated Pepco Holdings (parent company) capital costs, such as financing costs. Segment financial information for continuing operations for the three and six months ended June 30, 2012 and 2011 is as follows:
PHIs goodwill balance of $1.4 billion was unchanged during the six months ended June 30, 2012. Substantially all of PHIs goodwill balance was generated by Pepcos acquisition of Conectiv in 2002 and is allocated entirely to the Power Delivery reporting unit based on the aggregation of its regulated public utility company components for purposes of assessing impairment under FASB guidance on goodwill and other intangibles (ASC 350).
PHIs annual impairment test as of November 1, 2011 indicated that goodwill was not impaired. For the six months ended June 30, 2012, PHI concluded that there were no events requiring it to perform an interim goodwill impairment test. PHI will perform its next annual impairment test as of November 1, 2012.
(7) REGULATORY MATTERS
Over the last several years, PHIs utility subsidiaries have proposed in each of their respective jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date:
Under the BSA, customer distribution rates are subject to adjustment (through a credit or surcharge mechanism), depending on whether actual distribution revenue per customer exceeds or falls short of the revenue-per-customer amount approved by the applicable public service commission. The MFVRD approved in concept in Delaware provides for 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 distribution revenue decoupling mechanism.
In an effort to reduce the shortfall in revenues due to the delay in time or lag between when costs are incurred and when they are reflected in rates (regulatory lag), Pepco and DPL have proposed, in each of their respective jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco or DPL in each year would collect through a surcharge the amount of its reliability-related capital expenditures based on its budget for that year. The budgeted amount would be reconciled with actual capital expenditures on an annual basis and any over-recovery or under-recovery would be reflected in the next years surcharge. The work undertaken pursuant to the RIM would be subject to a prudency review by the applicable state regulatory commission in the next base rate case or at more frequent intervals as determined by such commission. Pepcos or DPLs respective operation and maintenance costs and other capital expenditures would remain subject to recovery through the traditional ratemaking process. The status of these proposals is discussed below in connection with the discussions of DPLs and Pepcos respective electric distribution base rate proceedings.
Pepco and DPL also have each requested, in each of their respective jurisdictions, public service commission approval of the use of fully forecasted test years in future rate cases. Traditionally, past test years with actual historical costs are used for ratemaking purposes; however, fully forecasted test years would be comprised of forward-looking costs. If approved, the use of such fully forecasted test years in lieu of historical test years would be more reflective of current costs and would mitigate the effects of regulatory lag. The status of these proposals is discussed below in connection with the discussions of DPLs and Pepcos respective electric distribution base rate proceedings.
Gas Cost Rates
DPL makes an annual Gas Cost Rate (GCR) filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2011, DPL made its 2011 GCR filing. The filing includes the second year of the effect of a two-year amortization of under-recovered gas costs proposed by DPL in its 2010 GCR filing (the settlement approved by the DPSC in its 2010 GCR case included only the first year of the proposed two-year amortization). The rates proposed in the 2011 GCR would result in a GCR decrease for the typical retail natural gas customer of 5.6% in the level of GCR. On September 20, 2011, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2011, subject to refund and pending final DPSC approval. The parties to the 2011 GCR proceeding have executed a settlement agreement that recommends approval of the 2011 GCR as filed. A DPSC decision on the settlement agreement is expected during the third quarter of 2012.
Electric Distribution Base Rates
On December 2, 2011, DPL submitted an application with the DPSC to increase its electric distribution base rates. The filing seeks approval of an annual rate increase of approximately $31.8 million, based on a requested return on equity (ROE) of 10.75%, and requests approval of implementation of the MFVRD. DPL requested that the rates become effective on January 31, 2012. The filing includes a request for DPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On January 10, 2012, the DPSC entered an order suspending the full increase and allowing a temporary rate increase of $2.5 million to go into effect on January 31, 2012, subject to refund and pending final DPSC approval. Under Delaware law, DPL had the right to place the remainder of approximately $29.3 million of the requested increase into effect on or after July 2, 2012, subject to refund and pending final DPSC order. However, pursuant to an agreement with DPSC staff, DPL has placed only $22.3 million of the requested amount into effect on July 3, 2012, subject to refund and pending final DPSC order. Although DPL agreed to put the lesser amount into effect at this time, the amount of DPLs annual rate increase request ($31.8 million) has not changed. The final DPSC order is expected by the end of 2012, unless the case is ultimately settled. Hearings before the DPSC, which were to begin July 30, 2012, have been postponed indefinitely as the parties are currently engaged in settlement negotiations. There can be no assurance as to whether the parties will reach a settlement in this case.
District of Columbia
On July 8, 2011, Pepco filed an application with the District of Columbia Public Service Commission (DCPSC) to increase its electric distribution base rates by approximately $42 million annually, based on a requested ROE of 10.75%. The filing includes a request for DCPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. A decision by the DCPSC is expected in the third quarter of 2012.
DPL Electric Distribution Base Rates
On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $25.2 million (subsequently reduced by DPL to $23.5 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. On July 20, 2012, the MPSC issued an order setting forth its decision authorizing an annual rate increase of approximately $11.3 million, based on an ROE of 9.81%. The MPSC reduced DPLs depreciation rates, which are expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPLs request to implement a RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. The order also authorizes DPL to recover in rates over a five-year period $4.3 million of the $4.6 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by DPL. The new revenue rates and lower depreciation rates were effective on July 20, 2012. DPL is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.
Pepco Electric Distribution Base Rates
On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing sought approval of an annual rate increase of approximately $68.4 million (subsequently reduced by Pepco to $66.2 million), based on a requested ROE of 10.75%. The filing included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. On July 20, 2012, the MPSC issued an order setting forth its decision authorizing an annual rate increase of approximately
$18.1 million, based on an ROE of 9.31%. The MPSC also directed Pepco to reduce the amount of the rate increase by the annual costs of certain energy advisory programs and seek recovery of these annual costs through the Empower Maryland Program. This reduction is currently estimated at $1.5 million. The MPSC reduced Pepcos depreciation rates, which are expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepcos request to implement a RIM and did not endorse the use by Pepco of fully forecasted test years in future rate cases. The order authorizes Pepco to recover in rates over a five-year period $18.5 million of incremental storm restoration costs associated with major weather events in 2011, including $9.7 million of the $9.9 million of incremental storm restoration costs associated with Hurricane Irene that had been deferred previously as a regulatory asset by Pepco and $8.8 million of incremental storm restoration costs incurred by Pepco associated with a severe winter storm in the first quarter of 2011 that had been expensed previously through other operation and maintenance expense in 2011. The incremental storm restoration costs of $8.8 million will be reversed and deferred as a regulatory asset in the third quarter of 2012. The new revenue rates and lower depreciation rates were effective on July 20, 2012. Pepco is currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.
Major Storm Damage Recovery Proceedings
In February 2011, the MPSC initiated proceedings involving Pepco and DPL, as well as unaffiliated utilities in Maryland, for the purpose of reviewing how the BSA operates to recover revenues lost as a result of major storm outages. On January 25, 2012, the MPSC issued an order modifying the BSA to prevent the Maryland utilities, including Pepco and DPL, from collecting lost utility revenue through the BSA if electric service is not restored to the pre-major storm levels within 24 hours of the start of a major storm (defined by the MPSC as a weather-related event during which more than the lesser of 10% or 100,000 of an electric utilitys customers have a sustained outage for more than 24 hours). The period for which the lost utility revenue may not be collected through the BSA commences 24 hours after the start of the major storm and continues until all major storm-related outages are restored. The MPSC stated that waivers permitting collection of BSA revenues would be granted in rare and extraordinary circumstances where a utility can show that an outage was not due to inadequate emphasis on reliability and restoration efforts were reasonable under the circumstances. A similar provision excluding revenues lost as a result of major storm outages from the calculation of future BSA adjustments also is included in the BSA for Pepco in the District of Columbia as approved by the DCPSC. The financial impact of service interruptions due to a major storm as a result of this MPSC order would generally depend on the scope and duration of the outages.
Electric Distribution Base Rates
On August 5, 2011, ACE filed a petition with the NJBPU to increase its electric distribution rates by the net amount of approximately $58.9 million (which was increased to approximately $80.2 million on February 24, 2012, to reflect the 2011 test year), based on a requested ROE of 10.75% (the ACE 2011 Base Rate Case). The modified net increase consists of a rate increase proposal of approximately $90.3 million, less a deduction from base rates of approximately $17 million attributable to excess depreciation expenses, plus approximately a $6.3 million increase in sales-and-use taxes and an upward adjustment of approximately $0.6 million in the Regulatory Asset Recovery Charge. A decision in the electric distribution rate case is expected by the end of 2012.
Infrastructure Investment Program
In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACEs Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of its infrastructure investment capital expenditures through a special rate outside the normal rate recovery mechanism of a base rate filing. The IIP was designed to stimulate the New Jersey economy and provide incremental employment in ACEs service territory by increasing the
infrastructure expenditures to a level above otherwise normal budgeted levels. In an October 18, 2011 petition (subsequently amended December 16, 2011) filed with the NJBPU, ACE has requested an extension and expansion to the IIP under which ACE proposes to spend approximately $63 million, $94 million and $81 million in calendar years 2012, 2013 and 2014, respectively, on non-revenue reliability-related capital expenditures. As proposed, capital expenditures related to the proposed special rate would be subject to annual reconciliation and approval by the NJBPU. A decision by the NJBPU on ACEs IIP filing is expected by the end of 2012.
Update and Reconciliation of Certain Under-Recovered Balances
In February 2012, ACE filed a petition with the NJBPU seeking to reconcile and update several pass-through charges related to (i) the recovery of above-market costs associated with ACEs long-term power purchase contracts with the NUGs, (ii) costs related to surcharges that fund several statewide social programs and ACEs uncollected accounts, and (iii) operating costs associated with ACEs residential appliance cycling program. The filing proposes to recover the projected deferred under-recovered balance related to the NUGs of $113.8 million as of May 31, 2012 through a four-year amortization schedule. The net impact of adjusting the charges as proposed (including both the annual impact of the proposed four-year amortization of the historical under-recovered balances related to the NUGs and the going-forward cost recovery of all the other components for the period June 1, 2012 through May 31, 2013, and including associated changes in sales-and-use taxes) is an overall annual rate increase of approximately $55.3 million. On June 12, 2012, the parties to the proceeding signed a Stipulation of Settlement, which provided for provisional rates to go into effect on July 1, 2012. The NJBPU approved the Stipulation of Settlement on June 18, 2012. The rates have been deemed provisional because ACEs filing will not be updated for actual revenues and expenses (if necessary) for May and June 2012 until after July 1, 2012 and a review of the final underlying costs for reasonableness and prudency will be completed after such filing.
Maryland Public Service Commission New Generation Contract Requirement
On September 29, 2009, the MPSC initiated an investigation into whether the EDCs in Maryland should be required to enter into long-term contracts with entities that construct, acquire or lease, and operate, new electric generation facilities in Maryland.
On April 12, 2012, the MPSC issued an order determining that there is a need for one new power plant in the range of 650 to 700 MW beginning in 2015. The order requires Pepco, DPL and Baltimore Gas and Electric Company (BG&E) to negotiate and enter into a contract with the winning bidder in amounts proportionate to their relative loads for the supply of electricity at regulated rates to their respective retail customers who do not elect to purchase electricity from a competitive supplier, otherwise known as standard offer service (SOS). Under the contract, the winning bidder will construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with a commercial operation date of June 1, 2015. The order acknowledges certain of the EDCs concerns about the requirements of the contract and directs them to negotiate with the winning bidder and submit any proposed changes in the contract to the MPSC for approval. The order further specifies that the EDCs entering into the contract will recover the associated costs from their respective SOS customers through surcharges. PHI is evaluating the impact of the order on each of Pepco and DPL, and, at this time, cannot predict (i) the extent of the negative effect that the order and, once finalized, the contract for new generation, may have on PHIs, Pepcos and DPLs balance sheets, as well as their respective credit metrics, as calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepcos and DPLs ability to recover their associated costs of the contract for new generation if a significant number of SOS customers elect to buy their energy from alternative energy suppliers, and (iii) the effect of the order on the financial condition, results of operations and cash flows of each of PHI, Pepco and DPL. On April 27, 2012, a group of generators operating in the PJM region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSCs order on the grounds that such order violated the commerce clause and the supremacy clause of the U.S. Constitution. On May 4, 2012, Pepco, DPL, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSCs order.
ACE Standard Offer Capacity Agreements
In April 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company, as more fully described in Note (2), Significant Accounting Policies Consolidation of Variable Interest Entities ACE Standard Offer Capacity Agreements and Note (13), Derivative Instruments and Hedging Activities. ACE and the other New Jersey EDCs entered into the SOCAs under protest based on concerns about the potential cost to distribution customers. In May 2011, the NJBPU denied a joint motion for reconsideration of its order requiring each of the EDCs to enter into the SOCAs. In June 2011, ACE and the other EDCs filed appeals related to the NJBPU orders with the Appellate Division of the New Jersey Superior Court. On March 5, 2012, the court remanded the case to the NJBPU with instructions to refer the case to an Administrative Law Judge for further consideration. The matter has been transmitted by the NJBPU to the Office of Administrative Law.
In February 2011, ACE joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the New Jersey law under which the SOCAs were established. ACE and the other plaintiffs filed a motion for summary judgment with the United States District Court for the District of New Jersey in December 2011. Cross motions for summary judgment were filed in January 2012. The motions remain pending.
In October 2011 and January 2012, respectively, two of the three generation companies sent notices of dispute under the SOCA to ACE. The notices of dispute allege that certain actions taken by PJM will have an adverse effect on the generation companys ability to clear the PJM auction, which is required for payment under the SOCA. As of February 2012, the two generation companies had filed petitions with the NJBPU seeking to amend their respective SOCAs. One of the generation companies sought to postpone the effective date of the SOCA (currently expected to be in 2015) until the litigation is complete. The other generation company proposed to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company alleged may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. In April 2012, the NJBPU issued an order consolidating the two matters. On May 1, 2012 (memorialized in a May 7, 2012 order), the NJBPU denied all of the generation companies requests without prejudice to their right to raise the issues at a later date.
(8) LEASING ACTIVITIES
Investment in Finance Leases Held in Trust
PHI has a portfolio of cross-border energy lease investments (the lease portfolio) consisting of hydroelectric generation facilities, coal-fired electric generation facilities and natural gas distribution networks located outside of the United States. Each lease investment is comprised of a number of leases. As of June 30, 2012 and December 31, 2011, the lease portfolio consisted of seven investments with an aggregate book value of $1.4 billion and $1.3 billion, respectively.
During the second quarter of 2011, PHI entered into early termination agreements with two lessees involving all of the leases comprising one of the eight lease investments and a small portion of the leases comprising a second lease investment. The early terminations of the leases were negotiated at the request of the lessees and were completed in June 2011. PHI received net cash proceeds of $161 million (net of a termination payment of $423 million used to retire the non-recourse debt associated with the terminated leases) and recorded a pre-tax gain of $39 million, representing the excess of the net cash proceeds over the carrying value of the lease investments.
With respect to the terminated leases, PHI had previously made certain business assumptions regarding foreign investment opportunities available at the end of the full lease terms. Because the leases were terminated earlier than full term, management decided not to pursue these opportunities and certain income tax benefits recognized previously were reversed in the amount of $22 million. As part of the negotiations with the lessees, the company required an early termination payment sufficient to provide a gain on the early termination of the leases. The after-tax gain on the lease terminations was $3 million, reflecting an income tax provision at the statutory federal rate of $14 million and the income tax benefit reversal of $22 million. PHI has no intent to terminate early any other leases in the lease portfolio. With respect to certain of these remaining leases, managements assumption continues to be that the foreign earnings recognized at the end of the lease term will remain invested abroad.
The components of the cross-border energy lease investments as of June 30, 2012 and December 31, 2011 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, 2012 and 2011:
To ensure credit quality, PHI regularly monitors the financial performance and condition of the lessees under its cross-border energy lease investments. Changes in credit quality are also assessed to determine if they should be reflected in the carrying value of the leases. PHI compares each lessees performance to annual compliance requirements set by the terms and conditions of the leases. This includes a comparison of published credit ratings to minimum credit rating requirements in the leases for lessees with public credit ratings. In addition, PHI routinely meets with senior executives of the lessees to discuss their company and asset performance. If the annual compliance requirements or minimum credit ratings are not met, remedies are available under the leases. At June 30, 2012, all lessees were in compliance with the terms and conditions of their lease agreements.
The table below shows PHIs net investment in these leases by the published credit ratings of the lessees as of June 30, 2012 and December 31, 2011:
(9) PENSION AND OTHER POSTRETIREMENT BENEFITS
The following Pepco Holdings information is for the three months ended June 30, 2012 and 2011:
The following Pepco Holdings information is for the six months ended June 30, 2012 and 2011:
Pension and Other Postretirement Benefits
Net periodic benefit cost related to continuing operations 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 responsible for substantially all of PHIs total net periodic pension and other postretirement benefit costs related to continuing operations.
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 target liability as defined under the Pension Protection Act of 2006. In the first quarter of 2012, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $85 million, $85 million and $30 million, respectively, which is expected to bring the PHI Retirement Plan assets to the funding target level for 2012 under the Pension Protection Act. In the first quarter of 2011, Pepco, DPL and ACE made discretionary tax-deductible contributions to the PHI Retirement Plan in the amounts of $40 million, $40 million and $30 million, which brought plan assets to the funding target level for 2011 under the Pension Protection Act.
PHI, Pepco, DPL and ACE maintain an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. On August 1, 2011, PHI, Pepco, DPL and ACE entered into an amended and restated credit agreement with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, the credit agreement was amended to extend the term of the credit facility to August 1, 2017 and to amend the pricing schedule to decrease certain fees and interest rates payable to the lenders under the facility.
The aggregate borrowing limit under the amended and restated credit facility is $1.5 billion, all or any portion of which may be used to obtain loans and up to $500 million of which may be used to obtain letters of credit. The facility also includes a swingline loan sub-facility, pursuant to which each company may make same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan must be repaid by the borrower within fourteen days of receipt. The initial credit sublimit for PHI is $750 million and $250 million for each of Pepco, DPL and ACE. The sublimits may be increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease must equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI may not exceed $1.25 billion and (b) each of Pepco, DPL or ACE may not exceed the lesser of $500 million and the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations may not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds is, at the borrowing companys election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties must be true and correct, and the borrower must be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excludes from the
definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contains certain covenants and other customary agreements and requirements that, if not complied with, could result in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder. Each of the borrowers was in compliance with all covenants under this facility as of June 30, 2012.
The absence of a material adverse change in PHIs business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.
At June 30, 2012 and December 31, 2011, the amount of cash plus unused borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its utility subsidiaries on a consolidated basis totaled $969 million and $994 million, respectively. PHIs utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of $586 million and $711 million at June 30, 2012 and December 31, 2011, respectively.
PHI, Pepco, DPL and ACE maintain on-going commercial paper programs to address short-term liquidity needs. As of June 30, 2012, the maximum capacity available under these programs was $875 million, $500 million, $500 million and $250 million, respectively, subject to available borrowing capacity under the credit facility. Although PHIs Board of Directors had approved in January 2012 an increase in PHIs commercial paper program limit to align it with PHIs borrowing limits under the credit facility, PHI intends to maintain this limit at its current level.
PHI, Pepco and ACE had $365 million, $108 million and $74 million, respectively, of commercial paper outstanding at June 30, 2012. DPL had no commercial paper outstanding at June 30, 2012. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ACE during the six months ended June 30, 2012 was 0.81%, 0.41%, 0.41% and 0.41%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ACE during the six months ended June 30, 2012 was thirteen, four, five and two days, respectively.
Other Financing Activities
In April 2012, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.
On April 4, 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. Net proceeds from the issuance of the long-term debt were primarily used (i) to repay Pepcos outstanding commercial paper that was issued to temporarily fund capital expenditures and working capital, (ii) to fund the redemption, prior to maturity, of all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds due in 2024 issued by the Industrial Development Authority of the City of Alexandria, Virginia (IDA), on Pepcos behalf and (iii) for general corporate purposes.
On June 26, 2012, DPL issued $250 million of 4.00% first mortgage bonds due June 1, 2042. Net proceeds from the issuance of the long-term debt were used primarily (i) to repay $215 million of DPLs outstanding commercial paper that was issued (a) to temporarily fund capital expenditures and working capital and (b) to fund the redemption in June 2012, prior to maturity, of $65.7 million in aggregate principal amount of three series of outstanding tax-exempt pollution control refunding revenue bonds issued by The Delaware Economic Development Authority (DEDA) for DPLs benefit; (ii) to fund the redemption, prior to maturity, of all of the $31 million in aggregate principal amount of outstanding tax-exempt bonds issued by DEDA for DPLs benefit; and (iii) for general corporate purposes.
On April 30, 2012, all of the $38.3 million of the outstanding 5.375% pollution control revenue refunding bonds issued by IDA for Pepcos benefit were redeemed. In connection with such redemption, Pepco redeemed all of the $38.3 million outstanding of its 5.375% first mortgage bonds due in 2024 that secured the obligations under such pollution control bonds.
On June 1, 2012, DPL funded the redemption by DEDA, prior to maturity, of $65.7 million in aggregate principal amount of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPLs benefit, as described above. Of the pollution control refunding revenue bonds redeemed, $34.5 million in aggregate principal amount bore interest at 0.75% per year and matured in 2026, $15.0 million in aggregate principal amount bore interest at 1.80% per year and matured in 2025, and $16.2 million in aggregate principal amount bore interest at 2.30% per year and matured in 2028. In connection with such redemption, on June 1, 2012, DPL redeemed, prior to maturity, all of the $34.5 million in aggregate principal amount outstanding of its 0.75% first mortgage bonds due 2026 that secured the obligations under one of the series of pollution control refunding revenue bonds redeemed by DEDA.
Term Loan Agreement
On April 24, 2012, PHI entered into a $200 million term loan agreement, pursuant to which PHI has borrowed (and may not reborrow) $200 million at a rate of interest equal to the prevailing Eurodollar rate, which is determined by reference to LIBOR with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHIs Eurodollar borrowings under the loan agreement may be converted into floating rate loans under certain circumstances, and, in that event, for so long as any loan remains a floating rate loan, interest would accrue on that loan at a rate per year equal to (i) the highest of (a) the prevailing prime rate, (b) the federal funds effective rate plus 0.5%, or (c) the one-month Eurodollar rate plus 1%, plus (ii) a margin of 0.875%. As of June 30, 2012, outstanding borrowings under the loan agreement bore interest at an annual rate of 1.125%, which is subject to adjustment from time to time. All borrowings under the loan agreement are unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement, must be repaid in full on or before April 23, 2013.
PHI used the net proceeds of the borrowings under the term loan agreement to repay outstanding commercial paper obligations and for general corporate purposes. Under the terms of the term loan agreement, PHI must maintain compliance with specified covenants, including (i) the requirement that PHI maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the loan agreement, which calculation excludes from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) a restriction on sales or other dispositions of assets, other than certain permitted sales and dispositions, and (iii) a restriction on the incurrence of liens (other than liens permitted by the loan agreement) on the assets of PHI or any of its significant subsidiaries. The loan agreement does not include any rating triggers. PHI was in compliance with all covenants under this agreement as of June 30, 2012.
Financing Activities Subsequent to June 30, 2012
On June 28, 2012, DPL directed DEDA to redeem, prior to maturity, all of the $31 million in aggregate principal amount of outstanding tax-exempt pollution control refunding revenue bonds issued by DEDA for DPLs benefit. The pollution control refunding revenue bonds to be redeemed by DEDA bear interest at 5.20% per year and were to mature in 2019. Contemporaneously with such redemption, DPL will redeem, prior to maturity, all of the $31 million in aggregate principal amount of its outstanding 5.20% first mortgage bonds due in 2019 that secure the obligations under such pollution control bonds. This redemption is anticipated to be completed in August 2012.
In July 2012, ACE Funding made principal payments of $6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.
Collateral Requirements of Pepco Energy Services
In the ordinary course of its retail energy supply business, which is in the process of being wound down, Pepco Energy Services entered into various contracts to buy and sell electricity, fuels and related products, including derivative instruments, designed to reduce its financial exposure to changes in the value of its assets and obligations due to energy price fluctuations. These contracts typically have collateral requirements. Depending on the contract terms, the collateral required to be posted by Pepco Energy Services can be of varying forms, including cash and letters of credit.
As of June 30, 2012, Pepco Energy Services had posted net cash collateral of $61 million and letters of credit of less than $1 million. At December 31, 2011, Pepco Energy Services had posted net cash collateral of $112 million and letters of credit of $1 million.
At June 30, 2012 and December 31, 2011, the amount of cash, plus borrowing capacity under PHIs credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $383 million and $283 million, respectively.
(11) INCOME TAXES
A reconciliation of PHIs consolidated effective income tax rate from continuing operations is as follows:
Three Months Ended June 30, 2012 and 2011
PHIs consolidated effective tax rates for the three months ended June 30, 2012 and 2011 were 36.1% and 36.2%, respectively. The effective tax rates for the three months ended June 30, 2012 and 2011 were substantially the same, however, the rate for 2011 reflects the reversal of income tax benefits associated with cross-border energy lease investments in the second quarter of 2011, offset by benefits recorded in 2011 in connection with estimates and interest related to uncertain and effectively settled tax positions, as described further below.
As discussed further in Note (8), Leasing Activities, during the second quarter of 2011, PHI terminated its interest in certain cross-border energy leases early. As a result of the early terminations, PHI reversed $22 million of previously recognized income tax benefits associated with those leases which will not be realized due to the early termination.
In the second quarter of 2011, PHI reached a settlement with the Internal Revenue Service (IRS) with respect to interest due on its federal tax liabilities related to the tax years 1996 through 2002. In connection with this agreement, PHI reallocated certain amounts that had been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, PHI recorded an additional tax benefit in the amount of $17 million (after-tax) in the second quarter of 2011.
Also in the second quarter of 2011, PHI received refunds of approximately $5 million and recorded tax benefits of approximately $4 million (after-tax) related to the filing of amended state tax returns. These amended returns reduced state taxable income due to an increase in tax basis reported on certain prior years asset dispositions.
Six Months Ended June 30, 2012 and 2011
PHIs consolidated effective tax rates for the six months ended June 30, 2012 and 2011 were 27.4% and 35.9%, respectively. The lower effective tax rate for the six months ended June 30, 2012 was primarily a result of the reversal of income tax benefits associated with cross-border energy lease investments in the second quarter of 2011, as discussed above. The rate was further decreased by an increase in deductible asset removal costs for Pepco in 2012 related to a higher level of asset retirements. The decrease in the effective tax rate for the six months ended June 30, 2012 was partially offset by lower benefits recorded in 2012 in connection with estimates and interest related to uncertain and effectively settled tax positions as discussed below.
In the first quarter of 2012, PHI recorded income tax benefits related to uncertain and effectively settled tax positions, primarily due to the effective settlement with the IRS with respect to the methodology used historically to calculate deductible mixed service costs and the expiration of the statute of limitations associated with an uncertain tax position in Pepco. In contrast, during the six months ended June 30, 2011, PHI recorded a $17 million benefit, primarily resulting from the settlement with the IRS on interest due on its 1996 through 2002 tax years discussed above, and the $4 million state tax benefit related to prior years asset dispositions.
(12) EQUITY AND EARNINGS PER SHARE
Basic and Diluted Earnings Per Share
PHIs basic and diluted earnings per share (EPS) calculations are shown below:
Equity Forward Transaction
On March 5, 2012, PHI entered into an equity forward transaction in connection with a public offering of 17,922,077 shares of PHI common stock. The use of an equity forward transaction substantially eliminates future equity market price risk by fixing a common equity offering sales price under the then existing market conditions, while mitigating immediate share dilution resulting from the offering by postponing the actual issuance of common stock until funds are needed in accordance with PHIs capital investment and regulatory plans.
Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHIs common stock from third parties and sold them to a group of underwriters for $19.25 per share, less an underwriting discount equal to $0.67375 per share. Under the terms of the equity forward transaction, to the extent that the transaction is physically settled, PHI would be required to issue and deliver shares of PHI common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $18.57625 per share at the time the equity forward transaction was entered into, and the amount of cash to be received by PHI upon physical settlement of the equity forward is subject to certain adjustments in accordance with the terms of the equity forward transaction. The equity forward transaction must be settled fully within 12 months of the transaction date. Except in specified circumstances or events that would require physical settlement, PHI is able to elect to settle the equity forward transaction by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to March 5, 2013.
The equity forward transaction had no initial fair value since it was entered into at the then market price of the common stock. PHI will not receive any proceeds from the sale of common stock until the equity forward transaction is settled, and at that time PHI will record the proceeds, if any, in equity. PHI concluded that the equity forward transaction was an equity instrument based on the accounting guidance in ASC 480 and ASC 815 and that it qualified for an exception from derivative accounting under ASC 815 because the forward sale transaction was indexed to its own stock. Currently, PHI anticipates settling the equity forward transaction through physical settlement during the fourth quarter of 2012.
At June 30, 2012, the equity forward transaction could have been settled with physical delivery of the shares to the forward counterparty in exchange for cash of $323 million. At June 30, 2012, the equity forward transaction could also have been cash settled, with delivery of cash of approximately $13 million to the forward counterparty, or net share settled with delivery of approximately 640,000 shares of common stock to the forward counterparty.
Prior to its settlement, the equity forward transaction will be reflected in PHIs diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PHIs common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the equity forward transaction less the number of shares that could be purchased by PHI in the market (based on the average market price during that reporting period) using the proceeds receivable upon settlement of the equity forward transaction (based on the adjusted forward sale price at the end of that reporting period). The excess number of shares is weighted for the portion of the reporting period in which the equity forward transaction is outstanding.
Accordingly, before physical or net share settlement of the equity forward transaction, and subject to the occurrence of certain events, PHI anticipates that the forward sale agreement will have a dilutive effect on PHIs earnings per share only during periods when the applicable average market price per share of PHIs common stock is above the per share adjusted forward sale price, as described above. However, if PHI decides to physically or net share settle the forward sale agreement, any delivery by PHI of shares upon settlement could result in dilution to PHIs earnings per share.
For the three and six months ended June 30, 2012, the equity forward transaction did not have a material dilutive effect on PHIs earnings per share.
(13) DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Derivatives are used by Pepco Energy Services and Power Delivery to hedge commodity price risk, as well as by PHI, from time to time, to hedge interest rate risk.
The retail energy supply business of Pepco Energy Services, which is in the process of being wound down, enters into energy commodity contracts in the form of electricity and natural gas futures, swaps, options and forward contracts to hedge commodity price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. The primary risk management objective is 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.
Pepco Energy Services commodity contracts that are not designated for hedge accounting, do not qualify for hedge accounting, or do not meet the requirements for normal purchase and normal sale accounting, are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting are recorded on an accrual basis.
In Power Delivery, DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and to limit its customers exposure to increases in the market price of natural gas under a hedging program approved by the DPSC. DPL uses these derivatives to manage the commodity price risk associated with its physical natural gas purchase contracts. The natural gas purchase contracts qualify as normal purchases, which are not required to be recorded in the financial statements until settled. 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 FASB guidance on regulated operations (ASC 980) until recovered from its customers through a fuel adjustment clause approved by the DPSC.
ACE was ordered to enter into the SOCAs by the NJBPU, and under the SOCAs, ACE would receive or make payments to electric generation facilities based on i) the difference between the fixed price in the SOCAs and the price for capacity that clears PJM, and ii) ACEs annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be approximately 15 percent. ACE began applying derivative accounting to two of its SOCAs as of June 30, 2012 because the generators cleared the 2015-2016 PJM capacity auction in May 2012. Changes in the fair value of the derivatives embedded in the SOCAs are deferred as regulatory assets or liabilities because the NJBPU has allowed full recovery from ACEs distribution customers for all payments made by ACE and ACEs distribution customers would be entitled to all payments received by ACE.
PHI also uses derivative instruments from time to time to mitigate the effects of fluctuating interest rates on debt issued in connection with the operation of its 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 August 2002. Upon issuance of the fixed rate-debt in August 2002, the treasury rate locks were terminated at a loss. The loss has been deferred in Accumulated Other Comprehensive Loss (AOCL) and is being recognized in income over the life of the debt issued as interest payments are made.
The tables below identify the balance sheet location and fair values of derivative instruments as of June 30, 2012 and December 31, 2011:
Under FASB guidance on the offsetting of balance sheet accounts (ASC 210-20), 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, 2012 and December 31, 2011, all PHI cash collateral pledged related to derivative instruments accounted for at fair value was entitled to offset under master netting agreements.
Derivatives Designated as Hedging Instruments
Cash Flow Hedges
Pepco Energy Services
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 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 that are related to hedge ineffectiveness or the forecasted hedged transaction being probable not to occur, are recognized in income. Pepco Energy Services has elected to no longer apply cash flow hedge accounting to certain of its electricity derivatives and all of its natural gas derivatives. Amounts included in AOCL for these cash flow hedges as of June 30, 2012 represent net losses on derivatives prior to the election to discontinue cash flow hedge accounting less amounts reclassified into income as the hedged transactions occur or because the hedged transactions were deemed probable not to occur. Gains or losses on these derivatives after the election to discontinue cash flow hedge accounting are recognized directly in income.
The cash flow hedge activity during the three and six months ended June 30, 2012 and 2011 is provided in the tables below:
As of June 30, 2012 and December 31, 2011, Pepco Energy Services had the following types and quantities of outstanding energy commodity contracts employed as cash flow hedges of forecasted purchases and forecasted sales.
All premiums paid and other transaction costs incurred as part of DPLs natural gas hedging activity, in addition to all of DPLs gains and losses related to hedging activities, are deferred under FASB guidance on regulated operations until recovered from customers based on the fuel adjustment clause approved by the DPSC. The following table indicates the net unrealized derivative losses arising during the period that were deferred as Regulatory assets and the net realized losses recognized in the consolidated statements of income (through Fuel and purchased energy expense) that were also deferred as Regulatory assets for the three and six months ended June 30, 2012 and 2011 associated with cash flow hedges:
Cash Flow Hedges Included in Accumulated Other Comprehensive Loss
The tables below provide details regarding effective cash flow hedges included in PHIs consolidated balance sheets as of June 30, 2012 and 2011. Cash flow hedges are marked to market on the consolidated balance sheets with corresponding adjustments to AOCL for effective cash flow hedges. As of June 30, 2012, $25 million of the losses in AOCL were associated with derivatives that Pepco Energy Services previously designated as cash flow hedges. Although Pepco Energy Services no longer designates these derivatives as cash flow hedges, gains or losses previously deferred in AOCL prior to the decision to discontinue cash flow hedge accounting will remain in AOCL until the hedged forecasted transaction occurs unless it is deemed probable that the hedged forecasted transaction will not occur. The data in the following tables indicate the cumulative net 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:
Other Derivative Activity
Pepco Energy Services
Pepco Energy Services holds certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the balance sheet with the gain or loss for changes in fair value recorded through Fuel and purchased energy expense.
For the three and six months ended June 30, 2012 and 2011, the amount of the derivative gain (loss) for Pepco Energy Services recognized in income is provided in the table below:
As of June 30, 2012 and December 31, 2011, Pepco Energy Services had the following net outstanding commodity forward contract quantities and net position on derivatives that did not qualify for hedge accounting:
DPL and ACE have certain derivatives that are not in hedge accounting relationships and are not designated as normal purchases or normal sales. These derivatives are recorded at fair value on the consolidated balance sheets with the gain or loss for changes in fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the consolidated balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause for DPLs derivatives or the NJBPU order for ACEs derivatives associated with the SOCAs. The following table indicates the net unrealized derivative losses arising during the period that were deferred as Regulatory assets and the net realized losses recognized in the consolidated statements of income (through Fuel and purchased energy expense) that were also deferred as Regulatory assets for the three and six months ended June 30, 2012 and 2011 associated with these derivatives:
As of June 30, 2012 and December 31, 2011, the quantity and position of DPLs net outstanding natural gas commodity forward contracts and ACEs capacity derivatives associated with the SOCAs that did not qualify for hedge accounting were:
Contingent Credit Risk Features
The primary contracts used by Pepco Energy Services and Power Delivery 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.
Under the ISDA or similar agreements, 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 those designated as normal purchases and normal sales that are accounted for off-balance sheet. 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 Pepco Energy Services are usually guaranteed by PHI. The obligations of DPL are stand-alone obligations without the guaranty of PHI. If PHIs or DPLs debt 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 are required to be fully collateralized without regard to the debt rating of the holder.
The gross fair values of PHIs derivative liabilities with credit risk-related contingent features as of June 30, 2012 and December 31, 2011, were $20 million and $54 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of June 30, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of $20 million. As of December 31, 2011, PHI had posted cash collateral of $1 million against its gross derivative liability, resulting in a net liability of $53 million. If PHIs and DPLs debt ratings had been downgraded below investment grade as of June 30, 2012 and December 31, 2011, PHIs net settlement amounts, including both the fair value of its derivative liabilities and its normal purchase and normal sale contracts in loss positions, would have been approximately $72 million and $124 million, respectively, and PHI would have been required to post additional collateral with the counterparties of approximately $72 million and $123 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.
PHIs primary source for posting cash collateral or letters of credit is its credit facility. At June 30, 2012 and December 31, 2011, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the future liquidity needs of PHI and its subsidiaries totaled $969 million and $994 million, respectively, of which $383 million and $283 million, respectively, was available to Pepco Energy Services.
(14) FAIR VALUE DISCLOSURES
Financial Instruments Measured at Fair Value on a Recurring Basis
PHI applies FASB guidance on fair value measurement and disclosures (ASC 820) that established a framework for measuring fair value and expanded disclosures about fair value measurements. As defined in the guidance, 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. The guidance 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) and the lowest priority to unobservable inputs (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, 2012 and December 31, 2011. As required by the guidance, 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.
PHI classifies its fair value balances in the fair value hierarchy based on the observability of the inputs used in the fair value calculation 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, such as the New York Mercantile Exchange (NYMEX).
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 data. Level 2 also includes those financial instruments that are valued using 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 and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
PHIs level 2 derivative instruments primarily consist of electricity derivatives at June 30, 2012. Level 2 power swaps are provided by a pricing service that uses liquid trading hub prices or liquid hub prices plus a congestion adder to estimate the fair value at zonal locations within trading hubs.
Executive deferred compensation plan assets consist of life insurance policies and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are valued based on the assets underlying the policies, which consist of short-term cash equivalents and fixed income securities that are priced using observable market data and can be liquidated for the value of the underlying assets as of June 30, 2012. The level 2 liability associated with the life insurance policies represents a deferred compensation obligation, the value of which is tracked via underlying insurance sub-accounts. The sub-accounts are designed to mirror existing mutual funds and money market funds that are observable and actively traded.
The value of certain employment agreement obligations is derived using a discounted cash flow valuation technique. The discounted cash flow calculations are based on a known and certain stream of payments to be made over time that are discounted to determine their net present value. The primary variable input, the discount rate, is based on market-corroborated and observable published rates. These obligations have been classified as level 2 within the fair value hierarchy because the payment streams represent contractually known and certain amounts and the discount rate is based on published, observable data.
Level 3 Pricing inputs that are significant and generally less observable than those from objective sources. Level 3 includes those financial instruments that are valued using models or other valuation methodologies.
Derivative instruments categorized as level 3 include natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC, natural gas physical basis contracts held by Pepco Energy Services, and capacity under the SOCAs entered into by ACE:
The table below summarizes the primary unobservable inputs used to determine the fair value of PHIs level 3 instruments and the range of values that could be used for those inputs as of June 30, 2012:
PHI used values within these ranges as part of its fair value estimates. A significant change in any of the unobservable inputs within these ranges would have an insignificant impact on the reported fair value as of June 30, 2012.
Executive deferred compensation plan assets and liabilities include certain life insurance policies that are valued using the cash surrender value of the policies, net of loans against those policies. The cash surrender values do not represent a quoted price in an active market; therefore, those inputs are unobservable and the policies are categorized as level 3. Cash surrender values are provided by third parties and reviewed by PHI for reasonableness.
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, 2012 and 2011 are shown below:
The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other income or Other operation and maintenance expense for the periods below were as follows:
Other Financial Instruments
The estimated fair values of PHIs debt instruments that are measured at amortized cost in PHIs consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of June 30, 2012 are shown in the table below. As required by the fair value measurement guidance, debt instruments are classified in their entirety within the fair value hierarchy 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, which may affect the valuation of fair value debt instruments and their placement within the fair value hierarchy levels.
The fair value of Long-term debt categorized as level 1 is based on actual quoted trade prices for the debt in active markets on the measurement date.
The fair value of Long-term debt and Transition Bonds issued by ACE Funding categorized as level 2 is based on a blend of quoted prices for the debt and quoted prices for similar debt in active markets, but not on the measurement date. The blend places more weight on current pricing information when determining the final fair value measurement. The fair value information is provided by brokers and PHI reviews the methodologies and results.
The fair value of Long-term debt categorized as level 3 is based on a discounted cash flow methodology using observable inputs, such as the U.S. Treasury yield, and unobservable inputs, such as credit spreads, because quoted prices for the debt or similar debt in active markets were insufficient. The Long-term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. Long-term project funding is categorized as level 3 because PHI concluded that the amortized cost carrying amounts for these instruments approximates fair value, which does not represent a quoted price in an active market.
The estimated fair values of PHIs debt instruments at December 31, 2011 are shown below:
The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.
(15) COMMITMENTS AND CONTINGENCIES
In September 2011, an asbestos complaint was filed in the New Jersey Superior Court, Law Division, against ACE (among other defendants) asserting claims under New Jerseys Wrongful Death and Survival statutes. The complaint, filed by the estate of a decedent who was the wife of a former employee of ACE, alleges that the decedents mesothelioma was caused by exposure to asbestos brought home by her husband on his work clothes. Unlike the other jurisdictions to which PHI subsidiaries are subject, New Jersey courts have recognized a cause of action against a premise owner in a so-called take home case if it can be shown that the harm was foreseeable. In this case, the complaint seeks recovery of an unspecified amount of damages for, among other things, the decedents past medical expenses, loss of earnings, and pain and suffering between the time of injury and death, and asserts a punitive damage claim. At this time, ACE has concluded that a loss is reasonably possible with respect to this matter, but ACE was unable to estimate an amount or range of reasonably possible loss because (i) the damages sought are indeterminate, (ii) the proceedings are in the early stages, and (iii) the matter involves facts that ACE believes are distinguishable from the facts of the take home cause of action recognized by the New Jersey courts.
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. Although penalties assessed for violations of environmental laws and regulations are not recoverable from customers of PHIs utility subsidiaries, environmental clean-up costs incurred by Pepco, DPL and ACE generally are included by each company in its respective cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of PHI and its subsidiaries described below at June 30, 2012 are summarized as follows:
Conectiv Energy Wholesale Power Generation Sites
On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jerseys Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to preliminary estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million. The amount accrued by PHI for the ISRA-required remediation activities at the nine generating facility sites is included in the table above under the column entitled Legacy Generation Non-Regulated.
On September 14, 2011, PHI received a request for data from the U.S. Environmental Protection Agency (EPA) regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Acts new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, PHI does not expect this inquiry to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.
The sale of the Conectiv Energy wholesale power generation business to Calpine did not include a coal ash landfill site located at the Edge Moor generating facility, which PHI intends to close. The preliminary estimate of the costs to PHI to close the coal ash landfill ranges from approximately $2 million to $3 million, plus annual post-closure operations, maintenance and monitoring costs, estimated to range between $120,000 and $193,000 per year for 30 years. The amounts accrued by PHI for this matter are included in the table above under the column entitled Legacy Generation - Non-Regulated.
Franklin Slag Pile Site
In November 2008, ACE received a general notice letter from EPA concerning the Franklin Slag Pile site in Philadelphia, Pennsylvania, asserting that ACE is a potentially responsible party (PRP) that may have liability for clean-up costs with respect to the site and for the costs of implementing an EPA-mandated remedy. EPAs claims are based on ACEs sale of boiler slag from the B.L. England generating facility, then owned by ACE, to MDC Industries, Inc. (MDC) during the period June 1978 to May 1983. EPA 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 EPA letter also states that, as of the date of the letter, EPAs expenditures for response measures at the site have exceeded $6 million. EPA estimates the additional cost for future response measures will be approximately $6 million. ACE believes that 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 claims to the contrary made by 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 supports 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. Costs to resolve this matter are not expected to be material and are expensed as incurred.
Peck Iron and Metal Site
EPA informed Pepco in a May 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, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that Pecks metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation that Pepco arranged for disposal or treatment of hazardous substances sent to the site on information provided by former Peck Iron and Metal personnel, who informed EPA that Pepco was a customer at the site. Pepco has advised 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 may be entitled to the recyclable material exemption from CERCLA liability. In a Federal Register notice published on November 4, 2009, EPA placed the Peck Iron and Metal site on the National Priorities List. The National Priorities List, among other things, serves as a guide to EPA in determining which sites warrant further investigation to assess the nature and extent of the human health and environmental risks associated with a site. In September 2011, EPA initiated a remedial investigation/feasibility study (RI/FS) using federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with the RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.
Ward Transformer Site
In April 2009, a group of PRPs with respect to 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 cost recovery and/or contribution claims against a number of entities, including ACE, DPL and Pepco with respect to past and future response costs incurred by the PRP group in performing a removal action at the site. In a March 2010 order, the court denied the defendants motion to dismiss. The litigation is moving forward with certain test case defendants (not including ACE, DPL and Pepco) filing summary judgment motions regarding liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although PHI cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, PHI does not believe that any of its three utility subsidiaries had extensive business transactions, if any, with the Ward Transformer site and therefore, costs incurred to resolve this matter are not expected to be material.
Benning Road Site
In September 2010, PHI received a letter from EPA stating that EPA and the District of Columbia Department of the Environment (DDOE) have identified the Benning Road location, consisting of a transmission and distribution facility operated by Pepco and a generation facility operated by Pepco Energy Services, as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. The letter stated that the principal contaminants of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. In January 2011, Pepco and Pepco Energy Services entered into a proposed consent decree with DDOE that requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10-15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for DDOEs selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DDOE will look to the companies to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. On December 1, 2011, the U.S. District Court approved the consent decree. The order entering the consent decree requires the parties to submit a written status report to the District Court on May 24, 2013 regarding the implementation of the requirements of the consent decree and any related plans for remediation. In addition, if the RI/FS has not been completed by May 24, 2013, the status report must provide an explanation and a showing of good cause for why the work has not been completed.
Pepco and Pepco Energy Services anticipate that a RI/FS work plan will be approved by the DDOE during the fall of 2012, at which time the RI/FS field work will commence.
The remediation costs accrued for this matter are included in the table above under the columns entitled Transmission and Distribution, Legacy Generation Regulated, and Legacy Generation Non-Regulated.
Indian River Oil Release
In 2001, DPL entered into a consent agreement with the Delaware Department of Natural Resources and Environmental Control for remediation, site restoration, natural resource damage compensatory projects and other costs associated with environmental contamination resulting from an oil release at the Indian River generating facility, which was sold in June 2001. The amount of remediation costs accrued for this matter is included in the table above under the column entitled Legacy Generation - Regulated.
Potomac River Mineral Oil Release
In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepcos Potomac River substation in Alexandria, Virginia. An overflow of an underground secondary containment reservoir resulted in approximately 4,500 gallons of mineral oil flowing into the Potomac River.
The release falls within the regulatory jurisdiction of multiple federal and state agencies. Beginning in March 2011, DDOE issued a series of compliance directives requiring Pepco to prepare an incident report, provide certain records, and prepare and implement plans for sampling surface water and river sediments and assessing ecological risks and natural resources damages. Pepco completed field sampling during the fourth quarter of 2011 and submitted sampling results to DDOE during the second quarter of 2012. Initial discussions with DDOE indicate that additional monitoring of shoreline sediments may be required.
In June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOEs threatened claims for civil penalties for alleged violation of the Districts Water Pollution Control Law, as well as for damages to natural resources. Based on these initial discussions, PHI and Pepco do not believe that the resolution of these claims will have a material adverse effect on their respective financial condition, results of operations or cash flows.
In March 2011, the Virginia Department of Environmental Quality (VADEQ) requested documentation regarding the release and the preparation of an emergency response report, which Pepco submitted to the agency in April 2011. In March 2011, Pepco received a notice of violation from VADEQ and in December 2011, VADEQ executed a consent agreement that had been executed by Pepco in August 2011, pursuant to which Pepco paid a civil penalty of approximately $40,000. The U.S. Coast Guard assessed a $5,000 penalty against Pepco for the release of oil into the waters of the United States, which Pepco has paid.
During March 2011, EPA conducted an inspection of the Potomac River substation to review compliance with federal regulations regarding Spill Prevention, Control, and Countermeasure (SPCC) plans for facilities using oil-containing equipment in proximity to surface waters. As a result, EPA identified several potential violations of the SPCC regulations relating to SPCC plan content, recordkeeping, and secondary containment. As a result of the oil release, Pepco submitted a revised SPCC plan to EPA in August 2011 and implemented certain interim operational changes to the secondary containment systems at the facility which involve pumping accumulated storm water to an aboveground holding tank for off-site disposal. In December 2011, Pepco completed the installation of a treatment system designed to allow automatic discharge of accumulate