responseletter-2010june17.htm

2.	We note the $212 million decrease in fuel and purchased energy due to lower volumes of electricity purchased to serve decreased retail customer load as the result of the continuing expiration of existing retail contracts. Please tell us and disclose if you anticipate this trend to continue. In this regard, we would anticipate any known trends to be disclosed as well as the potential impact of these trends on your financial statements.

	In the aftermath of the disruptions in the capital and credit markets in 2008 and with the significant increase in the collateral obligations of the retail energy supply business of Pepco Energy Services (PES) in the second half of 2008, we began to disclose in the 2008 Form 10-K, on page 47 and on page 156, the conduct of a strategic analysis of the retail energy supply business of PES that included, among other things, the evaluation of potential alternative supply arrangements to reduce the collateral requirements of the business or a possible restructuring, sale or wind down of the business. The disclosures on page 47 and page 156 of the 2008 Form 10-K also indicated that the increased cost of capital associated with the collateral obligations of PES had been factored into its retail pricing and, as a consequence, PES had experienced reduced retail customer retention levels and reduced levels of retail customer acquisitions.

	In each of the Forms 10-Q filed for the first, second and third quarters of 2009, we continued to disclose both the conduct of the strategic analysis of the retail energy supply business and the related reductions in both customer retention levels and new retail customer acquisitions (see page 8 of each of the Forms 10-Q filed for the first, second and third quarters of 2009). Beginning with the second quarter of 2009, PES began to see decreased revenues and costs of sales associated with the reduced level of customer acquisitions. Accordingly, on pages 112 and 114 of the second quarter 2009 Form 10-Q, within Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), both the operating revenue and costs of sales sections related to PES reference declines associated with fewer customer acquisitions and decreased retail customer load. Similar disclosures continued in the MD&A presented in the third quarter 2009 Form 10-Q (see pages 114 and 115) and in the 2009 Form 10-K (see pages 52 and 54), referencing the continuing expiration of existing retail contracts as a factor leading to declines in both revenues and costs of sales (i.e., reduced retail customer retention levels and reduced levels of retail customer acquisitions).

	In this regard, the PES trends of reduced revenues and reduced costs of sales associated with the retail energy supply business were introduced in the 2008 Form 10-K and we believe were appropriately identified and disclosed in MD&A in the following year Forms 10-Q and Form 10-K.

	On December 7, 2009, PHI filed a Form 8-K announcing that its strategic evaluation of the PES business was completed in the fourth quarter of 2009. The Form 8-K indicated that the operating revenue, operating expense and operating income of the retail energy supply business will diminish as the existing contracts expire. Multiple disclosures were then made in the 2009 Form 10-K referencing PHI’s fourth quarter decision to wind down the retail electricity and natural gas supply business of Pepco Energy Services (see pages 11, 41-42 and 138). The disclosures also indicate, among other things, that Pepco Energy Services will not be entering into any new retail energy supply contracts as a result of the wind down decision, and that collateral balances will be decreasing over time. These disclosures, combined with the previous disclosures of reduced retail customer retention levels and reduced levels of retail customer acquisitions, communicate to a reader that the revenues and costs of sales related to this business would continue to decline over the period of the wind down as existing contracts expire.

3.	Refer to your bill stabilization adjustment (“BSA”) disclosure on page 146. We note you are recognizing revenue and recording a regulatory asset when you experience a net positive revenue decoupling adjustment. Explain in detail why you believe such amounts are probable of recovery and confirm for us no other events are required in the future other than billing. We assume the MPSC and the DCPSC allow for the automatic adjustment of future rates. Please confirm if our assumption is correct, if not then please explain your basis for revenue recognition. In this regard, we read your disclosure on page 198 that discusses Pepco’s rate filing with the DCPSC requesting an increase in distribution rates and seeks approval for an annual rate increase of approximately $50 million under the BSA. We also read your disclosure on page 36 of your March 31, 2010 Form 10-Q which discusses the ultimate rate decision made by the DCPSC [in] March approving an electric distribution rate increase of only $19.8 million. In light of the March DCPSC rate decision, explain to us if revenue recognition under the BSA is appropriate under GAAP. Refer to FASB ASC 980-605-25-4. We may have further comment.

	In response to the first part of the comment, we confirm your assumption that the Maryland Public Service Commission (MPSC) and the District of Columbia Public Service Commission (DCPSC) allow for the automatic adjustment of future rates related to positive revenue decoupling adjustments under the BSA and no other events are required in the future other than billing. In addition, based on the mechanism to adjust future rates established under the respective rate orders approving the BSA, there is a high probability of recovery of the related regulatory assets and, as such, revenue recognition is appropriate.

	In accordance with FASB ASC 980-605-25-4 related to revenue recognition under alternative revenue programs, a regulatory asset is recorded when either Pepco or DPL experience a net positive revenue decoupling adjustment under the BSA approved by the MPSC and the DCPSC. Pepco and DPL consider the BSA to be a Type A alternative revenue program, as defined under FASB ASC 980-605-25-2, since the BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period.

	In the case of a net positive revenue decoupling adjustment, representing the amount by which (a) the revenue that Pepco and DPL are each entitled to earn under the BSA based on the approved distribution charge per customer exceeds (b) the revenue from Maryland and District of Columbia retail distribution sales based on kilowatt hours delivered, additional revenue is recorded and a regulatory asset is recognized as a result of meeting all of the following three conditions of FASB ASC 980-605-25-4.

	a.	“The program is established by an order from the utility's regulatory commission that allows for automatic adjustment of future rates. Verification of the adjustment to future rates by the regulator would not preclude the adjustment from being considered automatic.”

		The BSA was established by rate orders of the MPSC and DCPSC in 2007 and 2009, respectively – MPSC Order # 81517 (Pepco), MPSC Order # 81518 (DPL), and DCPSC Order # 15556 (Pepco). The orders provide for automatic adjustments of future rates on a monthly basis for the revenue decoupling adjustment. Pepco and DPL are required to make, and are making, monthly compliance filings with the respective public service commissions to provide information related to the calculation of the BSA rate adjustment that will be implemented in a future period, but this requirement does not preclude the adjustment from being considered automatic by the public service commissions. Accordingly, no other events are required in the future other than billing to recover a positive revenue decoupling adjustment.

	b.	“The amount of additional revenues for the period is objectively determinable and is probable of recovery.”

		The amount of additional revenue to be recorded in a period is objectively determinable based on the definition of the revenue decoupling adjustment noted above and on page 146 of the 2009 Form 10-K. In addition, the additional revenue is considered probable of recovery. Each month, the revenue decoupling adjustment amount is converted into a rate per kilowatt hour for each affected customer tariff by the Regulatory Affairs group of Pepco and DPL based on forecasted sales so that the adjustment amount can be billed to customers in the second succeeding billing period. This conversion to a rate per kilowatt hour is required due to customer bills being calculated based on a kilowatt hour rate multiplied by usage measured in kilowatt hours. The BSA rate per kilowatt hour, representing the revenue decoupling adjustment, has a high probability of recovery in a future period, as the BSA rate is included in bills to customers in the second succeeding month from when incurred (in accordance with the rate orders noted above). In addition, any shortfall, or overage, of actual sales from forecasted sales in the next period is included in the calculation for the following month, thus allowing a mechanism for future recovery and true up.

	c.	“The additional revenues will be collected within 24 months following the end of the annual period in which they are recognized.”

		The revenue decoupling adjustment is collected through the rate adjustments outlined in condition (b) above, thus allowing for collection within a 24 month period following the end of the annual period in which they are recognized. Since the adjustment amounts are billed within 60 days, collection is assured in a short time period substantially less than 24 months.

	In response to the comment regarding Pepco’s recent electric distribution rate increase approved by the DCPSC on March 2, 2010, and its impact on revenue recognition under the BSA, please note the following:

	The DCPSC approved the BSA for Pepco in September 2009 via Order # 15556, with an implementation date of November 1, 2009. As part of this order, average distribution charges per customer were established for use in calculating distribution revenue to be recognized in a reporting period, which results in a revenue decoupling adjustment, as noted previously in this response. The average distribution charges per customer established in Order # 15556 remained in effect until the approval of an electric distribution rate increase totaling $19.8 million, which took effect on March 23, 2010 as referenced on page 36 of the first quarter 2010 Form 10-Q. As part of that rate increase, new average distribution charges per customer were established. The change in average distribution charges per customer, resulting in higher reported distribution revenue for future periods, did not impact the mechanism established in Order # 15556 for automatic rate changes related to the revenue decoupling adjustment.

Although a rate increase request totaling $50 million was filed with the DCPSC in May 2009, as referenced on page 198 of the 2009 Form 10-K, the calculation of the revenue decoupling adjustment before any such increase was approved did not consider any increase related to this request, and thus had no impact on reported revenue or the calculation of the revenue decoupling adjustment. Calculations of allowable distribution revenue under the BSA continued to be made based on average distribution charges per customer approved in Order # 15556. Beginning on March 23, 2010, with the approval of new rates, the revenue decoupling adjustment was changed to reflect on a go forward basis the additional revenue the company is authorized to collect. All previously recorded revenue decoupling adjustments have been collected from customers.

	·	Phase I – Communication of the New Standard: PHI’s Technical Research group held two information sessions that covered the new guidance with key participants in PHI’s contract monitoring process, such as control performers and business unit contacts, as well as representatives from different business areas of PHI. The sessions provided examples of possible VIEs as well as notification that the Technical Research group would be requesting that these individuals identify any potential VIEs in their areas that should be reviewed by the Technical Research group. Technical Research followed up with these individuals to identify potential VIEs.

	·	Phase II – Identification of Potential VIEs: Technical Research compiled a list of potential VIEs with the assistance of the control performers, business unit contacts, and business area representatives along with members of the Corporate Accounting team, other business representatives, the Controllers at PHI’s Conectiv Energy and Pepco Energy Services subsidiaries, and other personnel from PHI’s Controller’s Department. We shared this list with these individuals to validate the completeness of the list. We believe the process was comprehensive and thorough and resulted in a full listing of contracts with VIEs.

	·	Phase III – VIE and Primary Beneficiary Analysis: By year end 2009, Technical Research had compiled a list of potential VIEs and began reviewing each interest or contract to assess whether there was a relationship with a VIE and whether a PHI entity was the primary beneficiary under the new guidance. Technical Research documented its conclusions for each of the interests or contracts that were identified with the assistance of other personnel involved with these interests or contracts. Included in this analysis were certain contracts that PHI subsidiaries entered into prior to December 31, 2003 for which it had previously concluded that sufficient information was not available to determine whether the counterparty was a VIE or whether the PHI subsidiary was the primary beneficiary of the VIE. The scope exception from the accounting guidance for consolidation of VIEs for

	Based on this analysis, PHI and its subsidiary registrants each concluded and disclosed in its 2009 Form 10-K that it did not expect the new guidance would result in a material change in accounting or disclosures within their financial statements once adopted on January 1, 2010. This disclosure of the expected impact for PHI and its subsidiary registrants can be found on the following pages of the 2009 Forms 10-K: page 153 (PHI); page 224 (Pepco); page 261 (DPL); page 297 (ACE).

	The new accounting rules for consolidation of VIEs did result in an arrangement with ACE Transition Funding, LLC (ACE Funding) being added to PHI’s and ACE’s disclosures about VIEs in the first quarter 2010 Forms 10-Q (see page 11 for PHI and page 87 for ACE). ACE Funding was established in 2001 by ACE solely for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. ACE Funding met the definition of a VIE under the new guidance because the equity owner, ACE, lacks some critical decision-making authority over servicing activities that are important to the economic performance of ACE Funding and inconsistent with the typical rights of an equity holder. Certain decision-making authority over servicing was instead singularly held by the debt investors. The debt investors hold participating rights and kick-out rights regarding ACE’s performance as servicer that are not shared with the equity owner, ACE. The impact of participating rights and kick-out rights was new guidance added to the accounting for VIEs under the new rules, and these rights are defined as follows:

	ACE is the primary beneficiary of ACE Funding because (i) it is contractually obligated to perform the servicing activities that drive the economic performance of ACE Funding, and (ii) ACE has the obligation to absorb potential interim losses and the right to receive potential interim benefits that could potentially be significant to ACE Funding. The potential interim losses or benefits, while not likely to occur, would result from a timing difference between the amount of Transition Bond charges collected from ACE customers and the amount of ACE Funding operating expense payments, which include principal and interest payments related to the Transition Bonds of ACE Funding. If ACE were to absorb interim losses, then ACE Funding can request from the New Jersey Board of Public Utilities an increase in Transition Bond charges billed to ACE customers and, if approved, the increase would allow ACE to recover the interim losses over time. ACE had consolidated ACE Funding prior to the effective date of the new guidance for VIEs as ACE owned 100 percent of ACE Funding, so the adoption of the new guidance for consolidation of VIEs did not have an impact on the financial statements of PHI and ACE other than the additional disclosure required for VIEs.

	Most of the power purchase contracts entered into by PHI subsidiaries are with supplying entities that meet the scope exception for business enterprises in the accounting guidance for consolidation of VIEs. The accounting guidance defines a business as follows in FASB ASC 805-10-20:

	“A business is a self-sustaining integrated set of activities and assets conducted and managed for the purpose of providing a return to investors. A business consists of (a) inputs, (b) processes applied to those inputs, and (c) resulting outputs that are used to generate revenues. For a set of activities and assets to be a business, it must contain all of the inputs and processes necessary for it to conduct normal operations, which include the ability to sustain a revenue stream by providing its outputs to customers.”

PHI’s primary power purchase contracts are supply contracts entered into by: a) PHI utilities to provide standard offer service (SOS) and Basic Generation Service (BGS) for their customers; or, b) Conectiv Energy or Pepco Energy Services to provide energy to either their wholesale or retail customers. These supply contracts are typically with established, self-sustaining energy companies for a length of time that is usually less than five years. The supplying entities are typically self-sustaining, in that they have the inputs, processes, and outputs to deliver energy to PHI subsidiaries. The supplying entities are not solely reliant on PHI subsidiaries to remain in business and their relationships with PHI subsidiaries do not have any one of the following characteristics in the accounting guidance for consolidation of VIEs that would preclude the scope exception for business enterprises:

Pages 139-140 of the 2009 Form 10-K identify the power purchase contracts entered into by PHI subsidiaries that were subject to the accounting guidance for consolidation of VIEs at December 31, 2009. These power purchase contracts are distinguishable from the typical power purchase contracts entered into by PHI subsidiaries. These power purchase contracts were entered into with newly established entities that typically had not yet constructed the generation facilities. In addition, the period of time covered by these power purchase contracts is generally longer. The shortest period of time covered by a power purchase contract in the population discussed below was fifteen years from the inception of the contract. The discussion below summarizes the implementation of the new accounting rules for VIEs related to these power purchase contracts and that there was no impact on PHI’s financial statements or disclosures upon adoption:

	·	Page 139 contains disclosures about ACE’s power purchase agreements (PPAs) with three non-utility generators (NUGs) that it entered into in the early 1990’s. These PPAs continue to be scoped out of the accounting guidance for VIEs because ACE has been unable to obtain information necessary to determine whether the NUGs are VIEs or whether ACE is the primary beneficiary and the scope exception has not changed. PHI’s quarterly requests for financial information from the NUGs have been rejected by the NUGs for proprietary and confidentiality reasons. The new accounting guidance for consolidation of VIEs, effective January 1, 2010 for PHI, retained the scope exception that was effective for these types of relationships as of December 31, 2009. PHI and ACE have historically disclosed information about the PPAs with these NUGs that is required for contractual relationships that are subject to this scope exception, so there was no impact of the new guidance for consolidation of VIEs on the financial statements or disclosures of PHI and ACE.

	·	Pages 139-140 contain disclosures about DPL’s PPAs with four wind facilities that were VIEs under the accounting guidance that was effective as of December 31, 2009. The wind facilities still meet the definition of VIEs and DPL would not be the primary beneficiary of them under the new accounting guidance that was effective January 1, 2010. PHI concluded that the wind facilities were VIEs under both sets of guidance because the owners of the wind facilities could not finance their activities without the subordinated financial support of DPL through the PPAs. Under the four PPAs, DPL purchases a significant portion of energy produced by the wind facilities and the associated renewable energy credits (RECs), and DPL is in a subordinate lien position to the lender to each wind facility. DPL continues to not be the primary beneficiary of the VIEs under the new accounting guidance because it does not have the power to direct matters that most

5.	Please tell us and disclose the carrying amount of goodwill for each reportable segment. We note your disclosure that substantially all of the goodwill is allocated to the Power Delivery Reporting Unit. Refer to FASB ASC 350-20-50-1.

	PHI’s carrying amounts of goodwill included in its reportable segments that have goodwill are as follows: Power Delivery reportable segment--$8.0 million, and Pepco Energy Services reportable segment--$0.4 million. Goodwill included in Corporate and Other is $1,398.1 million. On page 153 of its 2009 Form 10-K, PHI did not disclose the goodwill balance for the Power Delivery and Pepco Energy Services reportable segments because the amounts were considered immaterial.

	On page 153 of its 2009 Form 10-K, PHI also disclosed that the total assets of Corporate and Other includes Pepco Holdings’ goodwill balance which is primarily attributable to Power Delivery. Additionally, on page 155 of its 2009 Form 10-K, PHI discloses that substantially all of PHI’s $1.4 billion goodwill balance was generated by Pepco’s acquisition of Conectiv in 2002 and is allocated to the Power Delivery reporting unit for purposes of assessing impairment. PHI’s carrying amounts of goodwill for its reporting units that have goodwill allocated to them for purposes of assessing impairment are as follows: Power Delivery reporting unit--$1,406.1 million, and the Energy Services reporting unit of Pepco Energy Services--$0.4 million.

	PHI did not push down goodwill to the reportable segments in its segment disclosure since goodwill is not includable in rates charged to the customers of its regulated utility subsidiaries. Accordingly, the $1.398.1 million of goodwill was not part of the Power Delivery segment assets reported to PHI’s Chief Operating Decision Maker. FASB ASC 280-10-50-27 provides that only those assets that are included in the measure of the segment’s assets that is used by the Chief Operating Decision Maker shall be reported for a segment. PHI believes, as indicated in FASB ASC 350-20-35-44, that goodwill assigned to reporting units for purposes of impairment testing is not required to be reflected in an entity’s reported segments.

	Because the $1,398.1 million of goodwill was not pushed down to the operating segments, it was not displayed in the information provided to the Chief Operating Decision Maker. Therefore, in its Segment Information footnote, PHI believes, pursuant to FASB ASC 350-20-50-1, that it has properly not included the $1,398.1 million goodwill within the segment assets and has properly included this goodwill in the Corporate and Other column (which consists of amounts not allocated to the reportable segments). In future filings, PHI will disclose in the Segment Information footnote the amount of goodwill included in the Corporate and Other column. PHI also believes that it properly did not disclose pursuant to FASB ASC 350-20-50-1 the $8.0 million and $0.4 million, respectively, of goodwill related to the Power Delivery and Pepco Energy Services reportable segments because the amounts were considered immaterial.

6.	We note the pending sale of the Conectiv merchant generation business as disclosed in your Item 1.01 Form 8-K filed on April 21, 2010. Please explain to us how goodwill will be allocated in determining the loss on the disposal of Conectiv. Further, please tell us and disclose how goodwill will be allocated between the retained and disposed reporting units. If there is remaining goodwill in the portion of the reporting unit that is to be retained, then it should be tested for impairment. Refer to FASB ASC 350-20-35-57.

7.	Please tell us and disclose a description of the regulatory treatment of your pension and other postretirement benefit costs and the period over which any deferred amounts are expected to be recovered in rates. Refer to FASB ASC 980-715-50-1.

	The regulatory treatment for pension and other postretirement benefit costs related to PHI’s regulated subsidiaries is for PHI to record a regulatory asset for its regulated subsidiaries’ share of the unfunded portion of PHI’s defined benefit pension and other postretirement plans, which was initially recorded as a liability on PHI’s balance sheet with the adoption, as of December 31, 2006, of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (FASB ASC 715-20).

	PHI has established pension and OPEB plans that cover employees at both its regulated and unregulated subsidiaries and, accordingly, accounts for them as single-employer plans in its consolidated financial statements. PHI’s regulated utility subsidiaries, in their separate financial statements, account for their participation in these plans as participations in multi-employer plans and do not record pension and OPEB liabilities. For PHI’s regulated subsidiaries, the unfunded obligation recorded by PHI represents a projected liability to employees for services rendered and is an “incurred cost” as that term is used in FASB ASC 980-340-25-1. Accordingly, a regulatory asset is recorded by PHI for the regulated subsidiaries’ share of the unfunded obligation. On page 163 of its 2009 Form 10-K, PHI discloses the components of the unfunded obligation for both pension benefits and other postretirement benefits, including the apportionment of the unfunded obligation among regulated and unregulated subsidiaries.

	The regulatory asset is amortized in proportion to the recognition of actuarial losses, prior service cost credits and transition obligations attributable to its defined benefit pension plan and other postretirement benefit plans, and the amortization method is consistent with PHI’s recognition of net periodic benefit costs in accordance with FASB ASC 715-30 and FASB ASC 715-60.

	For ratemaking purposes after the adoption of FASB ASC 715-20, PHI’s regulated utility subsidiaries have continued to include in their cost of service pension and other postretirement benefit expenses allocated to them based on computations made in accordance with FASB ASC 715-30 and FASB ASC 715-60, respectively, and have an established history of recovering these amounts in rate proceedings. PHI believes these deferred costs will be included in allowable costs in future rate proceedings and will be fully recovered over the average remaining service period of active employees expected to receive benefits.

8.	Refer to page 198 where you state the Maryland Public Service Commission rejected a proposed surcharge mechanism for pension and OPEB expenses. Please tell us how you have historically recovered pension and OPEB costs. Further, explain if the rejected surcharge mechanism impacts your ability to recover pension and OPEB expenses. In this regard, tell us what evidence you are relying on to assert your pension and OPEB costs are recoverable in future rates.

	Historically, for ratemaking purposes, PHI’s regulated utility subsidiaries have recovered pension and OPEB expenses by including in cost of service pension and OPEB expenses allocated to them based on computations made in accordance with FASB ASC 715-30 and FASB ASC 715-60, respectively. These costs have always been accepted for recovery in rates by the public service commissions in our various jurisdictions.

	As a result of the decline in the value of the plan assets held by PHI’s defined benefit pension plan in 2008 related to disruptions in the capital and credit markets, DPL experienced a significant increase in the actuarially determined pension net periodic benefit cost in 2009. As discussed on page 264 of its 2009 Form 10-K, DPL’s combined pension and other postretirement net periodic benefit cost was approximately $25 million for 2009 as compared to $3 million in 2008. The increase in pension and OPEB expenses between 2008 and 2009 would typically be requested for recovery from the Maryland Public Service Commission (MPSC) in future rate filings covering the service period for 2009. Instead of waiting until the next base rate case filing for recovery of the additional pension and OPEB expenses, in May 2009, DPL sought from the MPSC approval of a rate surcharge mechanism to track and either bill or credit differences between actual pension and OPEB expenses and those expenses included in the current rates. The requested surcharge mechanism would have allowed for an automatic adjustment of customer rates as pension and OPEB expenses changed, and, therefore, would have eliminated any regulatory lag. Regulatory lag is that time between a utility's request for new rates and the granting of the rates by utility commissions.

	The fact that the surcharge mechanism was rejected does not impact our ability to recover pension and OPEB expenses because expenses computed as noted above have always been included in cost of service and accepted by the public service commissions in our various jurisdictions. The rejected surcharge mechanism did not result in disallowance of any pension and OPEB expenses included in the cost of service filed in the May 2009 rate case by Delmarva Power & Light in the Maryland jurisdiction. The proposed surcharge mechanism, had it been accepted, would have allowed automatic adjustments to rates based upon a rolling three-year average of pension and OPEB expenses. The MPSC rejected the proposed alternative approach to collection of pension and OPEB expenses and accepted DPL’s historical mechanism and, therefore, the MPSC’s rejection does not impact DPL’s ability to recover the deferred pension and OPEB expenses in future rates.

	PHI’s regulated utility subsidiaries have an established history of including pension and OPEB expenses, computed as noted above, in their cost of service, and the public service commissions in each of our various jurisdictions have an established history of allowing for recovery of these expenses in rates. We have relied upon these historical outcomes when concluding that these deferred costs will be fully recovered in future rates.

9.	Please explain to us how you determined your long-term expected return assumption on plan assets of 8.25% and concluded that the rate used is reasonable. Please be detailed in your analysis and include a summary for us by asset class of your actual long-term returns for the life of such assets. Please tell us whether you used a geometric or arithmetic mean to compute your expected long-term return. Contrast your returns with benchmarks for similar asset classes. See FASB ASC 715-30-35-47. We may have further comment.

	The long-term expected return assumption on plan assets represents PHI’s estimate of the rate of return to be earned on plan assets over the projected period the benefits are expected to be paid (60 years). It reflects the expected rate of return on the assets in the plan including expected contributions to the plan assets during the current year less benefits and expenses expected to be paid during the current year. PHI uses the “building block method” to estimate the total rate of return. Under this approach, the percentage of plan assets in each asset class according to PHI’s target asset allocation is multiplied by the expected asset return for the related asset class. The weighted expected rates of return for each asset class are then added together to determine the total expected rate of return.

	PHI’s independent pension investment advisor annually conducts a survey of leading Wall Street investment firms for expected returns over the next decade for each primary asset class (large-cap U.S. equities, small-cap U.S. equities, international equities, commodities, bonds, and various alternative investments), based on historical returns for these asset classes and their

	PHI Asset Allocation Policy	Actual Long-Term Annual Returns (a)	Expected Long-Term Annual Returns (b)	Weighted Long-Term Annual Returns (c)
Equities:
U.S. Large Cap	32.0%	10.7%	10.0%	3.2%
U.S. Small Cap	10.0%	9.8%	12.0%	1.2%
International	15.0%	9.1%	10.6%	1.6%
Commodities	3.0%	4.9%	8.0%	0.2%

Core Bonds	30.0%	8.9%	6.0%	1.8%

Alternatives:
Private Equity/Venture Capital	5.0%	13.9%	14.5%	0.7%
Real Estate	5.0%	10.1%	12.0%	0.6%

Weighted Total Return				9.4%

(a)Historical benchmark returns from 1980-2008 for each primary asset class provided by independent pension investment advisor.

(b)Expected long-term returns (20-30 years) developed by independent pension investment advisor from ten-year Wall Street Consensus expectations.

(c)Expected long-term annual returns weighted based on PHI asset allocation percentage of each asset class.

	As indicated in the above table, the weighted long-term annual return using the building block method was 9.4% for 2009. This return, which is based on benchmark indices, does not reflect investment management fees and plan expenses that would result in a lower net overall return. PHI also compares the overall weighted long-term annual return to the actual long-term return on PHI’s plan assets. PHI’s actual long-term return on all plan assets (1980-2009) has averaged 9.1% using an arithmetic mean. PHI historically has not tracked actual returns on plan assets by asset class.

	The long-term expected return assumption of 8.25% was determined by adjusting the weighted long-term annual return of 9.4% for investment management fees and plan expenses and other judgmental factors. The return of 8.25% was considered reasonable as it is in the middle of a range of expected returns on plan assets of peer companies (as provided by our Actuary).

11.	We read your proposed accounting treatment related to the Conectiv sale and your discussion of the anticipated after-tax loss of $60-$90 million. Please explain to us how this amount was calculated. Please be specific in your explanation.

	As indicated in our first quarter 2010 Form 10-Q (see p.8), the approved plan of disposition of Conectiv Energy consists of the sale of Conectiv Energy’s wholesale power generation business to Calpine and the liquidation of all of Conectiv Energy’s non-generation assets, including load service supply contracts, energy hedging portfolio, certain tolling agreements and other non-core assets. In estimating the after-tax loss anticipated from the plan of disposition, we developed a range to allow for the inherent estimation involved in the calculation. The range of anticipated after-tax loss of $60-$90 million is comprised broadly of a range of the expected after-tax loss on the Calpine transaction (including transaction costs, certain contractual obligations and the write-off of certain tax attributes) and a range of the expected after-tax gain on the liquidation of the non-generation assets through the completion of the liquidation period, less estimated employee retention and severance payments associated with the orderly disposition of the non-generation assets. The gain on the disposition of the non-generation assets assumes that sales proceeds from asset sales (primarily sales of load service supply contracts) will exceed the accumulated losses on commodity derivatives designated as cash flow hedges that are included in PHI’s accumulated other comprehensive loss at March 31, 2010. The range of anticipated after-tax loss of $60-$90 million does not include the operating results of the business for the period from January 1, 2010 through the completion of the liquidation period (expected to be completed within 12 months from the adoption of the plan).

	We believe that the disclosures of the range of after-tax loss on page 45 of the first quarter 2010 Form 10-Q provides a reader with adequate forward-looking information on the impact that the disposition will have on PHI’s results of operations. We expect to update the range of the estimated after-tax loss disclosure in the second quarter 2010 Form 10-Q.

	We also note that, given the advanced stage of the structuring of the potential transaction to sell the wholesale power generation business as of March 31, 2010, we determined that it was appropriate under FASB ASC 360-10-35-21 to perform a recoverability test related to these long-lived assets since we had an expectation that it was more likely than not that the asset group would be sold significantly before the end of its previously estimated useful life. We completed the recoverability test by estimating undiscounted cash flows using a probability-weighted approach in accordance with the accounting guidance, which considered the likelihood of two possible outcomes, either selling the assets on June 30, 2010 or using the assets until the end of their useful lives. The results of the test indicated that the asset group was not impaired as of March 31, 2010, and we disclosed this conclusion on page 11 of the first quarter 2010 Form 10-Q under the discussion of “Long-Lived Asset Impairment Evaluation.”

12.	Please tell us and disclose if you have any cash flow hedge designation issues with regard to the sale of Conectiv. For example, a derivative instrument may no longer qualify as a cash flow hedge if the forecasted transaction is probable of not occurring, which could result in immediate reclassification of amounts in accumulated other comprehensive income into earnings. Refer to FASB ASC 815-30-50-1. Based on the disclosure on page 8 it appears the reclassification adjustments could be material. If material, then explain in detail why you did not disclose the amount of reclassification adjustments in your Form 10-Q for the period ended March 31, 2010.

	Conectiv Energy holds commodity derivatives designated as cash flow hedges as of March 31, 2010. Under the accounting rules for cash flow hedges, the effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (loss) and is reclassified into income in the same period or periods during which the hedged transactions affect income.

	When the Board of Directors of PHI approved a plan for the disposition of Conectiv Energy on April 20, 2010, our conclusion was that certain of the forecasted transactions that these derivative instruments were hedging (load service supply contracts) were probable not to occur. We viewed this event as a nonrecognized subsequent event for the quarter ended March 31, 2010 under FASB ASC 855-10-20, since the condition did not exist at the date of the balance sheet, but arose subsequent to that date.

	Prior to filing our first quarter 2010 Form 10-Q, Conectiv Energy management had begun to identify the forecasted transactions that were no longer deemed probable of occurring, but the plan of liquidation had not been fully developed at the specific contract level, the financial analysis of the effects of the liquidation had not been completed and current mark-to-market data were not yet available for the related derivatives designated as cash flow hedges for these transactions. Without a fully developed and documented plan of liquidation, we concluded that a disclosure of the sizing of the reclassification adjustment would be the most appropriate disclosure for our first quarter 2010 Form 10-Q. Accordingly, on pages 8 and 45 of the first quarter 2010 Form 10-Q, we disclosed that the loss to be recognized in the second quarter of 2010 related to the sale of the generation assets and the liquidation of the remaining Conectiv Energy assets could exceed the estimated range of after-tax loss of $60 million to $90 million due to unrealized losses required to be recorded in earnings related to derivative instruments no longer qualifying for cash flow hedge accounting. Further, we felt it was meaningful to disclose that PHI currently estimated that these unrealized losses would be offset by gains from the liquidation of the load service supply contracts over the liquidation period.

13.	Explain to us how you will present the cash flows from discontinued operations on your consolidated statements of cash flows. Further, explain to us and expand your liquidity discussion in Management’s Discussion and Analysis to provide an overview of the specific impact the Conectiv sale will have on your liquidity.

	While we are still evaluating the effects the discontinued operations presentation will have on PHI’s consolidated financial statements and disclosures in the second quarter 2010 Form 10-Q, we anticipate that we will present the net cash flows related to discontinued operations in the statement of cash flows as a single line item in each of the categories of the statement of cash flows: operating, investing and financing.

	Our first quarter 2010 Form 10-Q discloses, on page 112 under “Working Capital,” that we plan to use the proceeds from the unsecured credit facility (entered into on April 20, 2010) to reduce the working capital deficit. This bridge loan was entered into concurrent with our announced disposition of Conectiv Energy and, as disclosed, this loan will be repaid upon receipt of the proceeds associated with the sale of the Conectiv Energy wholesale power generation assets.

	Our disclosures in the second quarter 2010 Form 10-Q will include a detailed discussion of the planned use of the sale proceeds and the impact on the liquidity of our business.

Attention:	Andrew Mew
	Robert Babula
	Donna Di Silvio

Re:	PEPCO Holdings, Inc.
	Potomac Electric Power Company
	Delmarva Power & Light Company
	Atlantic City Electric Company
	Forms 10-K for the year ended December 31, 2009
	Filed February 25, 2010
	File Nos. 1-31403, 1-01072, 1-01405 and 1-03559

	Sincerely,


	/s/ A. J. Kamerick
	Anthony J. Kamerick
	Senior Vice President and Chief Financial Officer

	701 Ninth Street, NW Washington, DC 20068
Anthony J. Kamerick Senior Vice President Chief Financial Officer	202-872-2056 202-872-3015 Fax ajkamerick@pepcoholdings.com

1.	Our review encompassed the parent company, and the other subsidiary registrants listed on the facing page of your Form 10-K. In the interests of reducing the number of comments, we have not addressed each registrant with a separate comment. To the extent a comment is applicable to more than one registrant, please address the issue separately.

	We acknowledge the request that the staff’s comments should be addressed separately for each registrant to which it is applicable and have complied with this request.

	We plan, in future filings, to expand these disclosures to clearly state that the declines are directly associated with the reduced levels of customer retention and new customer acquisitions in 2009 and the disclosed wind down of the business, and that the declines are expected to continue to the end of the wind down period.

	Regarding disclosures of trends, we thought it was important to give a reader an indication of the relative size of the Pepco Energy Services business that was being wound down. Accordingly, on page 138 of the 2009 Form 10-K, we included a disclosure of the historical operating revenues and operating income related to the retail energy supply business for the last three years.

4.	Explain to us your implementation of the new accounting rules with respect to variable interest entities, and the related impact of this new guidance on your financial statements. Please be detailed in your response. In this regard, explain how you initially determined an entity or structure was a variable interest entity, and your determination of who was the primary beneficiary. Please ensure your response is comprehensive and includes an analysis of your power purchase contracts.

	In order to implement new consolidation guidance for variable interest entities (VIEs) in FASB ASC 810, PHI conducted a company-wide project in three distinct phases. Key activities in each of these phases were as follows:

	·	Participating rights: “the ability to block the actions through which an enterprise exercises the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance.”

	·	Kick-out rights: “the ability to remove the enterprise with the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance.”

	a.	PHI subsidiaries do not participate in the design of the supplier’s capital structure;

	b.	Substantially all of the activities of the suppliers are not on the behalf of PHI subsidiaries;

	c.	PHI subsidiaries do not provide more than half of the subordinated capital of the suppliers; and,

	d.	PHI subsidiaries, individually or as a group, are not a single-lessee of the suppliers.

10.	Please disclose the amount of retained earnings restricted or free of restrictions. See Rule 4-08(e) of Regulation S-X.

	The disclosure of restrictions on dividends on page 184 of our 2009 Form 10-K discloses the restrictions that could exist. Since the full amount of our retained earnings has no restrictions, we did not consider it necessary to specifically disclose the amount of retained earnings free of restrictions. In future filings, we will positively disclose that PHI had approximately $1,268 million and $1,271 million of retained earnings free of restrictions at December 31, 2009 and

	·	the Company is responsible for the adequacy and accuracy of the disclosure in the filings referred to herein;

	·	staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and