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 ACEmeet 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 ofor 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 ~~Company’s~~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 Company’s or ~~their~~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~~Part I,

Item 1A. Risk ~~Factors”~~Factors and other statements in each Reporting Company’s 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 Company’s 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 of 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 Company’s 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.


	Registrants								Registrants
Item	Pepco Holdings		Pepco*		DPL*		ACE		Pepco Holdings		Pepco*		DPL*		ACE
Consolidated Statements of Income		4		49		67		88		4		55		75		98

Consolidated Statements of Comprehensive Income		5		N/A		N/A		N/A		5		N/A		N/A		N/A

Consolidated Balance Sheets		6		50		68		89		6		56		76		99

Consolidated Statements of Cash Flows		8		52		70		91		8		58		78		101

Consolidated Statement of Equity		9		53		71		92		9		59		79		102

Notes to Consolidated Financial Statements		10		54		72		93		10		60		80		103

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	Three Months Ended March 31,					Three Months Ended June 30,						Six Months Ended June 30,
	2012		2011			2012			2011			2012			2011
	*(millions of dollars)*					*(millions of dollars)*
Net Income	$	68	$	64		$	62		$	94		$	130		$	158

Other Comprehensive Income
Gains (losses) on commodity derivatives designated as cash flow hedges:
Losses arising during period		—		(1	)
Other Comprehensive Income (Loss) from Continuing Operations
Gain (losses) from continuing operations on commodity derivatives designated as cash flow hedges:
Gains arising during period							—			3			—			2
Amount of losses reclassified into income		13		27			12			19			25			46

Net gains on commodity derivatives		13		26			12			22			25			48
Amortization of gains for prior service costs		1		1
Pension and other postretirement benefit plans							(6	)		(5	)		(5	)		(4	)

Other comprehensive income, before income taxes		14		27			6			17			20			44
Income tax expense related to other comprehensive income		6		11			2			7			8			18

Other comprehensive income, net of income taxes		8		16			4			10			12			26

Comprehensive Income	$	76	$	80		$	66		$	104		$	142		$	184

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	March 31, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	*(millions of dollars, except shares)*						*(millions of dollars, except shares)*
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	986		$	732		$	875		$	732
Current portion of long-term debt and project funding		114			112			49			112
Accounts payable and accrued liabilities		522			549			526			549
Capital lease obligations due within one year		8			8			12			8
Taxes accrued		99			110			79			110
Interest accrued		79			47			50			47
Liabilities and accrued interest related to uncertain tax positions		3			3			9			3
Derivative liabilities		25			26			18			26
Other		259			274			258			274

Total Current Liabilities		2,095			1,861			1,876			1,861

DEFERRED CREDITS
Regulatory liabilities		526			526			525			526
Deferred income taxes, net		3,119			2,863			3,104			2,863
Investment tax credits		22			22			21			22
Pension benefit obligation		232			424			305			424
Other postretirement benefit obligations		467			469			446			469
Liabilities and accrued interest related to uncertain tax positions		10			32			6			32
Derivative liabilities		2			6			10			6
Other		179			191			182			191

Total Deferred Credits		4,557			4,533			4,599			4,533

LONG-TERM LIABILITIES
Long-term debt		3,794			3,794			4,203			3,794
Transition bonds issued by ACE Funding		285			295			276			295
Long-term project funding		13			13			13			13
Capital lease obligations		78			78			70			78

Total Long-Term Liabilities		4,170			4,180			4,562			4,180

COMMITMENTS AND CONTINGENCIES (NOTE 15)
EQUITY
Common stock, $.01 par value, 400,000,000 shares authorized, 228,244,115 and 227,500,190 shares outstanding, respectively		2			2
Common stock, $.01 par value, 400,000,000 shares authorized, 228,851,815 and 227,500,190 shares outstanding, respectively								2			2
Premium on stock and other capital contributions		3,340			3,325			3,354			3,325
Accumulated other comprehensive loss		(55	)		(63	)		(51	)		(63	)
Retained earnings		1,079			1,072			1,079			1,072

Total Equity		4,366			4,336			4,384			4,336

TOTAL LIABILITIES AND EQUITY	$	15,188		$	14,910		$	15,421		$	14,910

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	Three Months Ended March 31,						Six Months Ended June 30,
	2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
OPERATING ACTIVITIES
Net income	$	68		$	64		$	130		$	158
Income from discontinued operations		—			(2	)		—			(1	)
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		110			105			221			210
Non-cash rents from cross-border energy lease investments		(13	)		(14	)		(26	)		(28	)
Gain on early termination of finance leases held in trust								—			(39	)
Deferred income taxes		259			90			235			61
Net unrealized (gains) losses on derivatives								(12	)		7
Impairment losses								3			—
Other		(4	)		(4	)		(8	)		(10	)
Changes in:
Accounts receivable		78			87			60			63
Inventories		3			10			(17	)		(4	)
Prepaid expenses		—			10			(36	)		(34	)
Regulatory assets and liabilities, net		(37	)		11			(93	)		(40	)
Accounts payable and accrued liabilities		(60	)		(126	)		(45	)		(71	)
Pension contributions		(200	)		(110	)		(200	)		(110	)
Pension benefit obligation, excluding contributions		15			16			33			26
Cash collateral related to derivative activities		20			31			53			44
Taxes accrued		(247	)		(49	)
Interest accrued		33			31
Income tax-related prepayments, receivables and payables								(184	)		34
Other assets and liabilities		(2	)		16			10			26
Conectiv Energy net assets held for sale		—			31			—			42

Net Cash From Operating Activities		23			197			124			334

INVESTING ACTIVITIES
Investment in property, plant and equipment		(291	)		(171	)		(589	)		(387	)
Department of Energy capital reimbursement awards received		7			9			22			16
Proceeds from early termination of finance leases held in trust								—			161
Changes in restricted cash equivalents		1			(2	)		2			(3	)
Net other investing activities		2			—			5			(7	)

Net Cash Used By Investing Activities		(281	)		(164	)		(560	)		(220	)

FINANCING ACTIVITIES
Dividends paid on common stock		(61	)		(61	)		(123	)		(122	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		17			14			28			25
Redemption of preferred stock of subsidiaries		—			(6	)		—			(6	)
Issuances of long-term debt								450			235
Reacquisitions of long-term debt		(9	)		(9	)		(122	)		(52	)
Issuances of short-term debt, net		253			33
Issuances (Repayments) of short-term debt, net								143			(139	)
Cost of issuances		(3	)		—			(7	)		(2	)
Net other financing activities		16			(7	)		(3	)		(16	)

Net Cash From (Used By) Financing Activities		213			(36	)		366			(77	)

Net Decrease in Cash and Cash Equivalents		(45	)		(3	)
Net (Decrease) Increase in Cash and Cash Equivalents								(70	)		37
Cash and Cash Equivalents at Beginning of Period		109			21			109			21

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	64		$	18		$	39		$	58

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes, net	$	—		$	2
Cash received for income taxes, net							$	(3	)	$	(2	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	Common Stock				Premium on Stock				Accumulated Other Comprehensive (Loss) Income				Retained Earnings			Total
*(millions of dollars, except shares)*									Accumulated Other Comprehensive (Loss) Income			Common Stock							Premium on Stock			Accumulated Other Comprehensive Loss			Retained Earnings				Total
*(millions of dollars, except shares)*	Shares		Par Value		Premium on Stock			Premium on Stock				Accumulated Other Comprehensive (Loss) Income				Total		Retained Earnings	Premium on Stock			Accumulated Other Comprehensive Loss		Total					Total			Shares			Par Value
BALANCE, DECEMBER 31, 2011		227,500,190	$	2				Premium on Stock				Accumulated Other Comprehensive (Loss) Income			227,500,190			Retained Earnings	$	2		$	3,325	Total			$		(63	)	$	1,072		$	4,336
Net income		—		—		—				—				68			68		—			—			—				—			68			68
Other comprehensive income		—		—		—				8				—			8		—			—			—				8			—			8
Dividends on common stock ($0.27 per share)		—		—		—				—				(61	)		(61	)	—			—			—				—			(61	)		(61	)
Issuance of common stock:
Original issue shares, net		319,037		—		9				—				—			9		319,037			—			9				—			—			9
Shareholder DRP original shares		424,888		—		8				—				—			8		424,888			—			8				—			—			8
Net activity related to stock-based awards		—		—		(2	)			—				—			(2	)	—			—			(2	)			—			—			(2	)

BALANCE, MARCH 31, 2012		228,244,115	$	2	$	3,340			$	(55	)		$	1,079		$	4,366		228,244,115			2			3,340				(55	)		1,079			4,366
Net income																			—			—			—				—			62			62
Other comprehensive income																			—			—			—				4			—			4
Dividends on common stock ($0.27 per share)																			—			—			—				—			(62	)		(62	)
Issuance of common stock:
Original issue shares, net																			186,820			—			3				—			—			3
Shareholder DRP original shares																			420,880			—			8				—			—			8
Net activity related to stock-based awards																			—			—			3				—			—			3

BALANCE, JUNE 30, 2012																			228,851,815		$	2		$	3,354			$	(51	)	$	1,079		$	4,384

The accompanying Notes are an integral part of these Consolidated Financial Statements.

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 ~~to the lesser extent,~~ the distribution and supply of natural ~~gas (Power Delivery):~~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 utility’s service territory. Distribution facilities are low-voltage systems that carry electricity to end-use customers in the utility’s 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 ~~also owns and operates two~~deactivated its Buzzard Point oil-fired generation ~~facilities that are scheduled for deactivation in~~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 ~~March 31,~~June 30, 2012 and 2011 were ~~$160~~$112 million and ~~$305~~$233 million, respectively, while operating income for the same periods was ~~$15~~$16 million and ~~$12~~$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 ~~$92~~$61 million as of ~~March 31,~~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.

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 PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease ~~Investments.”~~Investments” to the consolidated financial statements of PHI.

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s 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 Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion. The disposition of all of Conectiv Energy’s 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, ~~is complete.~~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.

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 PHI’s 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 PHI’s 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 ~~March 31,~~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 ~~March 31,~~June 30, 2012 may not be indicative of PHI’s results that will be realized for the full year ending December 31, 2012.

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 ~~and long-lived assets for~~ impairment calculations, fair value calculations for derivative instruments, ~~the costs of providing~~ pension and other postretirement ~~benefits, evaluation~~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, ~~accrual of unbilled revenue, recognition of changes in network service transmission rates for prior service year costs, and~~ the recognition of income tax benefits for investments in finance leases held in trust associated with PHI’s portfolio of cross-border energy lease ~~investments.~~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.

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. PHI’s 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.

During the second quarter of 2011, PHI’s 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 PHI’s utility subsidiaries at June 30, 2011.

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.

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 ~~March 31,~~June 30, 2012 and 2011 were approximately ~~$51~~$49 million and ~~$57~~$55 million, respectively, of which approximately ~~$50~~$47 million and ~~$53~~$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 ACE’s customers through regulated rates.

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. DPL’s 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 as of March 31, 2012.~~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 ~~these agreements.~~the PPAs. PHI has concluded that consolidation is not required for any of these ~~agreements~~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 ~~of the~~ wind ~~facilities~~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. DPL’s purchases under the three wind PPAs totaled $9$6 million and $5$4 million for the three months ended ~~March 31,~~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.DPL’s purchases under the solar agreement were ~~zero~~less than $1 million for the three and six months ended ~~March 31,~~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 DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 megawatt fuel cell generation facility ~~is expected to be~~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. ~~PHI has concluded that~~ DPL ~~would account~~is accounting for this arrangement as an agency transaction.

Atlantic City Electric Transition Funding LLC (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 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 ACE’s 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.

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 ~~generators~~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 ~~electricity~~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 company’s annual proportion of the total New Jersey load attributable to all ~~EDCs.~~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 byfrom 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 ~~the other EDCs.~~

~~Currently, PHI believes that~~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 ACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. ~~Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the recognition of a regulatory liability (asset).~~ The next PJM capacity auction is scheduled for May ~~2012.~~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 Pepco’s 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 PHI’s 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 ~~three~~six months ended ~~March 31,~~June 30, 2012.

Taxes included in Pepco Holdings’ gross revenues were ~~$92~~$93 million and ~~$96~~$94 million for the three months ended ~~March 31,~~June 30, 2012 and 2011, respectively, and $184 million and $190 million for the six months ended June 30, 2012 and 2011, respectively.

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:

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 ~~three~~six months ended ~~March 31,~~June 30, 2011.

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.

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.

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~~Income tax expense of $1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2011.

The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with PHI’s March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on PHI’s consolidated financial statements and the new disclosure requirements are in Note (14), “Fair Value Disclosures,” of PHI’s consolidated financial statements.

The FASB issued new disclosure requirements for reporting comprehensive income that were effective beginning with PHI’s 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.”

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.

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 PHI’s March 31, 2013 consolidated financial statements. PHI is evaluating the impact of this new guidance on its consolidated financial statements.

Pepco Holdings’ management has identified its operating segments at ~~March 31,~~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 ~~March 31,~~June 30, 2012 and 2011 is as follows:


	Three Months Ended March 31, 2012											Three Months Ended June 30, 2012
	*(millions of dollars)*											*(millions of dollars)*
	Power Delivery		Pepco Energy Services		Other Non- Regulated		Corporate and Other (a)			PHI Consolidated		Power Delivery		Pepco Energy Services			Other Non- Regulated		Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,055	$	228	$	13	$	(4	)	$	1,292	$	984	$	185		$	14	$	(4	)	$	1,179
Operating Expenses (b)		954		211		1		(13	)		1,153		860		171	(c)		2		(6	)		1,027
Operating Income		101		17		12		9			139		124		14			12		2			152
Interest Income		—		—		1		(1	)		—		—		—			1		(1	)		—
Interest Expense		53		1		3		8			65		53		—			4		8			65
Other Income (Expenses)		8		—		1		(1	)		8
Preferred Stock Dividends		—		—		1		(1	)		—
Income Tax Expense (Benefit)		9		6		—		(1	)		14
Net Income from Continuing Operations		47		10		10		1			68
Other Income													8		—			—		2			10
Income Tax Expense													25		6			2		2			35
Net Income (Loss) from Continuing Operations													54		8			7		(7	)		62
Total Assets		11,473		544		1,487		1,684			15,188		11,734		536			1,499		1,652			15,421
Construction Expenditures	$	280	$	5	$	—	$	6		$	291	$	285	$	5		$	—	$	8		$	298


	Three Months Ended March 31, 2011												Three Months Ended June 30, 2011
	*(millions of dollars)*												*(millions of dollars)*
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated		Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	1,249	$	373	$	14		$	(2	)	$	1,634	$	1,093	$	311	$	14		$	(6	)	$	1,412
Operating Expenses (b)		1,131		357		2			(5	)		1,485		957		298		(38	)(c)		(7	)		1,210
Operating Income		118		16		12			3			149		136		13		52			1			202
Interest Income		—		—		1			(1	)		—		—		—		1			(1	)		—
Interest Expense		50		1		3			8			62		52		1		4			6			63
Other Income (Expenses)		8		1		(1	)		1			9
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (Benefit)		29		6		2			(3	)		34
Other Income														8		1		—			1			10
Income Tax Expense (Benefit) (d)														20		5		30			(1	)		54
Net Income (Loss) from Continuing Operations		47		10		6			(1	)		62		72		8		19	(c)		(4	)		95
Total Assets (excluding Assets Held For Sale)		10,667		613		1,645			1,295			14,220		10,803		615		1,461			1,354			14,233
Construction Expenditures	$	160	$	1	$	—		$	10		$	171	$	204	$	6	$	—		$	6		$	216

PHI’s goodwill balance of $1.4 billion was unchanged during the ~~three~~six months ended ~~March 31,~~June 30, 2012. Substantially all of PHI’s goodwill balance was generated by Pepco’s 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).

PHI’s annual impairment test as of November 1, 2011 indicated that goodwill was not impaired. For the ~~three~~six months ended ~~March 31,~~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.

Over the last several years, PHI’s 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 customer’s volumetric consumption) to recover the utility’s 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 ~~as applicable,~~ 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 year’s 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. Pepco’s or DPL’s 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 DPL’s and Pepco’s 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 DPL’s and Pepco’s respective electric distribution base rate proceedings.

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 ~~that had been~~ proposed ~~and approved~~ by ~~the DPSC,~~DPL in ~~DPL’s~~its 2010 GCR filing (the settlement approved by the DPSC in ~~the~~its 2010 GCR case included only the first year of ~~such~~the proposed two-year amortization). The rates proposed in the 2011 GCR ~~which include the second year of the two-year amortization approved in the 2010 GCR case,~~ 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.

On February 21, 2012, DPL submitted its application for a waiver under its GCR tariff, which requires DPL to request an interim GCR rate increase when the under-recovery exceeds 6.0%. The DPSC granted the waiver on March 6, 2012.

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. ~~As permitted by~~Under Delaware law, DPL ~~intends~~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 ~~approval. A decision by~~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 DPL’s annual rate increase request ($31.8 million) has not changed. The final DPSC order is expected by the end of ~~2012.~~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.

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.

On December 9, 2011, DPL submitted an application with the MPSC to increase its electric distribution base rates. The filing ~~seeks~~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 ~~includes~~included a request for MPSC approval of a RIM and the use of fully forecasted test years in future DPL rate cases. ~~A decision by~~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 DPL’s depreciation rates, which are expected to lower annual depreciation and amortization expenses by an estimated $4.1 million. The order did not approve DPL’s 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 ~~expected in July 2012.~~currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

$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 Pepco’s depreciation rates, which are expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s 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 ~~expected in July 2012.~~currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

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 utility’s 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 ~~already~~ 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.

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 ~~(increased~~(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.

the IIP, allowed recovery by ACE of ~~ACE’s~~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 ACE’s 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 ACE’s IIP filing is expected by the end of ~~the third quarter of~~ 2012.

In August 2011, ACE filed a petition with the NJBPU seeking authorization for deferred accounting treatment of uninsured incremental storm damage restoration costs not otherwise recovered through base rates. In that petition, ACE sought deferred accounting treatment for recovery of storm costs of approximately $8 million incurred during Hurricane Irene, which impacted ACE’s service territory in the third quarter of 2011. In an order dated December 15, 2011, the NJBPU directed that this petition be transmitted to the Office of Administrative Law with a request that the matter be consolidated with the ACE 2011 Base Rate Case, discussed above.

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 ACE’s long-term power purchase contracts with the NUGs, (ii) costs related to surcharges that fund several statewide social programs and ACE’s uncollected accounts, and (iii) operating costs associated with ACE’s 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 ~~$54.5~~$55.3 million. ~~A decision by~~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 ~~this~~June 18, 2012. The rates have been deemed “provisional” because ACE’s filing ~~is expected by the end~~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 ~~second quarter of 2012.~~final underlying costs for reasonableness and prudency will be completed after such filing.

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.

calculated by independent rating agencies that evaluate and rate PHI, Pepco and DPL and each of their debt issuances, (ii) the effect on Pepco’s and DPL’s 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 MPSC’s order on the grounds that ~~that~~ such order violated the commerce clause and the supremacy clause of the U.S. Constitution. ~~PHI continues to evaluate whether to seek~~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 MPSC’s order.

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.~~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 company’s 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 ~~seeks~~sought to postpone the effective date of the SOCA (currently expected to be in 2015) ~~of the SOCA~~ until the litigation is complete. The other generation company ~~proposes~~proposed to adjust the payment terms of the SOCA to reflect the total expected revenues under the original bid, which the generation company ~~alleges~~alleged may be in jeopardy if it were unable to clear in the PJM auction commencing in 2015. ACE does not believe that a dispute exists under the SOCAs and is disputing the amendment of the SOCAs jointly with the other EDCs. ACE does not believe the impact of either of such SOCA amendments would be material, although the result of such amendments, if approved, may be to prolong the term of one or both SOCAs. In April 2012, the NJBPU issued an order consolidating the two matters. ~~A decision is expected~~On May 1, 2012 (memorialized in a May 7, 2012 order), the ~~second quarter~~NJBPU denied all of ~~2012.~~the generation companies’ requests without prejudice to their right to raise the issues at a later date.

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 ~~March 31,~~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, management’s 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 ~~March 31,~~June 30, 2012 and ~~as of~~ December 31, 2011 are summarized below:


	March 31, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	*(millions of dollars)*						*(millions of dollars)*
Scheduled lease payments to PHI, net of non-recourse debt	$	2,120		$	2,120		$	2,120		$	2,120
Less: Unearned and deferred income		(758	)		(771	)		(745	)		(771	)

Investment in finance leases held in trust		1,362			1,349			1,375			1,349
Less: Deferred income tax liabilities		(797	)		(793	)		(816	)		(793	)

Net investment in finance leases held in trust	$	565		$	556		$	559		$	556

Income recognized from cross-border energy lease investments was comprised of the following for the three and six months ended ~~March 31,~~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 ~~reviews~~compares each lessee’s performance ~~versus~~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 ~~March 31,~~June 30, 2012, all lessees were in compliance with the terms and conditions of their lease agreements.

The table below shows PHI’s net investment in these leases by the published credit ratings of the lessees as of ~~March 31,~~June 30, 2012 and December 31, 2011:


Lessee Rating (a)	March 31, 2012		December 31, 2011		June 30, 2012		December 31, 2011
	*(millions of dollars)*				*(millions of dollars)*
Rated Entities
AA/Aa and above	$	746	$	737	$	752	$	737
A		616		612		623		612

Total	$	1,362	$	1,349	$	1,375	$	1,349

The following Pepco Holdings information is for the three months ended ~~March 31,~~June 30, 2012 and 2011:


	Pension Benefits						Other Postretirement Benefits						Pension Benefits						Other Postretirement Benefits
	2012			2011			2012			2011			2012			2011			2012			2011
	*(millions of dollars)*												*(millions of dollars)*
Service cost	$	11		$	10		$	1		$	2		$	7		$	7		$	3		$	1
Interest cost		26			26			9			9			27			27			8			9
Expected return on plan assets		(34	)		(31	)		(5	)		(5	)		(32	)		(33	)		(4	)		(4	)
Amortization of prior service cost		—			—			(1	)		(1	)
Amortization of prior service cost (benefit)														1			(1	)		(1	)		(1	)
Amortization of net actuarial loss		14			13			5			4			18			11			2			2
Termination benefits														—			—			1			1

Net periodic benefit cost	$	17		$	18		$	9		$	9		$	21		$	11		$	9		$	8

The following Pepco Holdings information is for the six months ended June 30, 2012 and 2011:

Net periodic benefit cost related to continuing operations is included in ~~other~~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 ~~the~~PHI’s total ~~PHI~~ net periodic pension and other postretirement benefit costs related to continuing operations.

PHI’s funding policy with regard to PHI’s 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 ~~at least~~ 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.

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 company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month ~~LIBOR~~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.

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 ~~March 31,~~June 30, 2012.

The absence of a material adverse change in PHI’s 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 ~~March 31,~~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 ~~$679~~$969 million and ~~$1 billion,~~$994 million, respectively. PHI’s utility subsidiaries had combined cash and unused borrowing capacity under the credit facility of ~~$452~~$586 million and $711 million at ~~March 31,~~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 ~~March 31,~~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. ~~In January 2012, the~~Although PHI’s Board of Directors had approved in January 2012 an increase in PHI’s ~~maximum~~commercial paper program limit to ~~$1.25 billion, which has not been put into effect as of March 31, 2012.~~align it with PHI’s borrowing limits under the credit facility, PHI intends to maintain this limit at its current level.

PHI, Pepco and ~~DPL~~ACE had ~~$521~~$365 million, ~~$204~~$108 million and ~~$133~~$74 million, respectively, of commercial paper outstanding at ~~March 31,~~June 30, 2012. ~~ACE did not issue commercial paper during the first quarter of 2012 and~~DPL had no commercial paper outstanding at ~~March 31,~~June 30, 2012. The weighted average interest rate for commercial paper issued by PHI, Pepco, DPL and ~~DPL~~ACE during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~0.75%~~0.81%, ~~0.40%~~0.41%, 0.41% and ~~0.39%~~0.41%, respectively. The weighted average maturity of all commercial paper issued by PHI, Pepco, DPL and ~~DPL~~ACE during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~twelve,~~thirteen, four, five and ~~four~~two days, respectively.

~~In January 2012, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.~~

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.

InOn April 4, 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. ~~Proceeds~~Net proceeds from the issuance of the long-term debt were primarily used (i) to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures and working capital, (ii) to ~~redeem,~~fund the redemption, prior to maturity, of all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds due ~~February 15,~~in 2024 issued by the Industrial Development Authority of the City of Alexandria, Virginia (IDA), on Pepco’s 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 DPL’s 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 DPL’s 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 DPL’s 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 Pepco’s benefit were ~~redeemed as noted in the preceding paragraph.~~redeemed. In connection with such redemption, Pepco redeemed all of the $38.3 million outstanding of its 5.375% first mortgage bonds due ~~February 15,~~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 DPL’s 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.

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%. PHI’s 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 ~~April 24,~~June 30, 2012, outstanding borrowings under the loan agreement bore interest at an annual ~~interest~~ rate of ~~1.115%~~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 ~~intends to use~~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 ~~be in~~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.

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 DPL’s 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.

In the ordinary course of its retail energy supply business, which is in the process of being wound down, Pepco Energy Services ~~enters~~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 ~~March 31,~~June 30, 2012, Pepco Energy Services had posted net cash collateral of ~~$92~~$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 ~~March 31,~~June 30, 2012 and December 31, 2011, the amount of cash, plus borrowing capacity under PHI’s credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled ~~$227~~$383 million and $283 million, respectively.

A reconciliation of PHI’s consolidated effective income tax rate from continuing operations is as follows:


	Three Months Ended March 31,										Three Months Ended June 30,										Six Months Ended June 30,
	2012					2011					2012					2011					2012					2011
	*(millions of dollars)*										*(millions of dollars)*
Income tax at Federal statutory rate	$	29		35.0	%	$	33		35.0	%	$	34		35.0	%	$	52		35.0	%	$	63		35.0	%	$	86		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		4		4.9			5		5.0			5		5.3			6		4.0			10		5.4			11		4.5
Asset removal costs		(3	)	(3.7	)		(1	)	(0.7	)		(4	)	(4.0	)		(2	)	(1.3	)		(7	)	(3.8	)		(3	)	(1.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions												3		2.8			(17	)	(11.4	)		(10	)	(5.8	)		(15	)	(6.1	)
Cross-border energy lease investments		(1	)	(1.2	)		(1	)	(1.2	)		(1	)	(1.1	)		21		14.1			(2	)	(1.2	)		20		8.2
Change in estimates and interest related to uncertain and effectively settled tax positions		(13	)	(15.9	)		1		1.2
Investment tax credits		(1	)	(1.2	)		(1	)	(1.2	)
Permanent differences related to deferred compensation		(1	)	(1.2	)		(2	)	(2.2	)
State tax benefit related to prior years’ asset dispositions												—		—			(4	)	(2.7	)		—		—			(4	)	(1.6	)
Other, net		—		0.4			—		(0.5	)		(2	)	(1.9	)		(2	)	(1.5	)		(5	)	(2.2	)		(7	)	(2.9	)

Consolidated income tax expense related to continuing operations	$	14		17.1	%	$	34		35.4	%	$	35		36.1	%	$	54		36.2	%	$	49		27.4	%	$	88		35.9	%

PHI’s consolidated effective tax rates for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~17.1%~~36.1% and ~~35.4%~~36.2%, respectively. The ~~decrease~~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 ~~effective tax rate primarily resulted from changes~~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.

PHI’s 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 ~~Internal Revenue Service (IRS)~~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. ~~The effective rate was further decreased as~~In contrast, during the six months ended June 30, 2011, PHI recorded a ~~result of~~$17 million benefit, primarily resulting from the ~~increase in asset removal costs in Pepco in 2012 primarily~~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 ~~a higher level of~~prior years’ asset ~~retirements.~~dispositions.

PHI’s basic and diluted earnings per share (EPS) calculations are shown below:


	Three Months Ended March 31,				Three Months Ended June 30,
	2012		2011		2012		2011
	(millions of dollars, except per share data)				(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	68	$	62	$	62	$	95
Net income from discontinued operations		—		2
Net income (loss) from discontinued operations						—		(1	)

Net income	$	68	$	64	$	62	$	94

Shares (Denominator) (in millions):
Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		228		225		228		226
Adjustment to shares outstanding		—		—		—		—

Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		228		225
Weighted Average Shares Outstanding for Computation of Basic Earnings per Share of Common Stock						228		226
Net effect of potentially dilutive shares (a)		—		—		1		—

Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		228		225
Weighted Average Shares Outstanding for Computation of Diluted Earnings per Share of Common Stock						229		226

Basic and Diluted Earnings per Share
Earnings per share of common stock from continuing operations	$	0.30	$	0.27	$	0.27	$	0.42
Earnings per share of common stock from discontinued operations		—		0.01		—		—

Basic and diluted earnings per share	$	0.30	$	0.28	$	0.27	$	0.42

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 PHI’s capital investment and regulatory plans.

Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s 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, ~~and~~ in whole or in part, at any time on or prior to March 5, 2013.

The equity forward transaction ~~has~~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.~~settlement during the fourth quarter of 2012.

At ~~March 31,~~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 ~~$328~~$323 million. At ~~March 31,~~June 30, 2012, the equity forward transaction could also have been cash settled, with delivery of cash of approximately ~~$14~~$13 million to the forward counterparty, or net share settled with delivery of approximately ~~740,000~~640,000 shares of common stock to the forward counterparty.

Prior to its settlement, the equity forward transaction will be reflected in PHI’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PHI’s common stock used in calculating diluted earnings per share for a reporting period ~~is deemed to~~would be increased by the ~~excess, if any, of 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 PHI’s earnings per share only during periods when the applicable average market price per share of PHI’s 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 PHI’s earnings per share.

For the three and six months ended ~~March 31,~~June 30, 2012, the equity forward transaction did not have a material dilutive effect on PHI’s earnings per share.

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. ~~DPL’s capacity contracts are not classified as derivatives.~~ All premiums paid and other transaction costs incurred as part of DPL’s 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) ACE’s 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 ACE’s distribution customers for all payments made by ACE and ACE’s 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 ~~their~~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 ~~March 31,~~June 30, 2012 and December 31, 2011:


	As of March 31, 2012															As of June 30, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments (b)			Gross Derivative Instruments			Effects of Cash Collateral and Netting			Net Derivative Instruments			Derivatives Designated as Hedging Instruments (a)			Other Derivative Instruments (b)			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	*(millions of dollars)*															*(millions of dollars)*
Derivative assets (current assets)	$	9		$	8		$	17		$	(11	)	$	6		$	—		$	5		$	5		$	4	$	9
Derivative assets (non-current assets)		—			1			1			—			1			—			8			8			—		8

Total Derivative assets		9			9			18			(11	)		7			—			13			13			4		17

Derivative liabilities (current liabilities)		(38	)		(50	)		(88	)		63			(25	)		(21	)		(34	)		(55	)		37		(18	)
Derivative liabilities (non-current liabilities)		(8	)		(6	)		(14	)		12			(2	)		(3	)		(13	)		(16	)		6		(10	)

Total Derivative liabilities		(46	)		(56	)		(102	)		75			(27	)		(24	)		(47	)		(71	)		43		(28	)

Net Derivative (liability) asset	$	(37	)	$	(47	)	$	(84	)	$	64		$	(20	)	$	(24	)	$	(34	)	$	(58	)	$	47	$	(11	)

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 ~~March 31,~~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.

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 ~~March 31,~~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 ~~March 31,~~June 30, 2012 and 2011 is provided in the tables below:


	Three Months Ended March 31,					Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011			2012		2011		2012		2011
	*(millions of dollars)*					*(millions of dollars)*
Amount of net pre-tax loss arising during the period included in accumulated other comprehensive loss	$	—	$	(1	)
Amount of net pre-tax gain arising during the period included in accumulated other comprehensive loss						$	—	$	3	$	—	$	2

Amount of net pre-tax loss reclassified into income:
Effective portion:
Fuel and purchased energy		13		27
Fuel and purchased energy expense							12		19		25		46
Ineffective portion:~~(a)~~
Revenue		—		—			—		—		—		—

Total net pre-tax loss reclassified into income		13		27			12		19		25		46

Net pre-tax gain on commodity derivatives included in accumulated other comprehensive loss	$	13	$	26		$	12	$	22	$	25	$	48

As of ~~March 31,~~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.


	Quantities				Quantities
Commodity	March 31, 2012		December 31, 2011		June 30, 2012		December 31, 2011
Forecasted Purchases Hedges
Natural gas (One Million British Thermal Units (MMBtu))		—		—
Electricity (Megawatt hours (MWh))		246,680		614,560		3,360		614,560
Electricity capacity (MW-Days)		—		—

Forecasted Sales Hedges
Electricity (MWh)		246,680		614,560		3,360		614,560

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s 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 ~~amount of the~~ net unrealized derivative losses arising during the period ~~included in~~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 ~~March 31,~~June 30, 2012 and 2011 associated with cash flow hedges:

The tables below provide details regarding effective cash flow hedges included in PHI’s consolidated balance sheets as of ~~March 31,~~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 ~~March 31,~~June 30, 2012, ~~$33~~$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:


	As of March 31, 2012						As of June 30, 2012
Contracts	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term		Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	*(millions of dollars)*						*(millions of dollars)*
Energy commodity (a)	$	21	$	17		26 months	$	15	$	13		23 months
Interest rate		10		1		245 months		10		1		242 months

Total	$	31	$	18			$	25	$	14

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 ~~income.~~

For the three and six months ended ~~March 31,~~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 ~~March 31,~~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:

March 31, 2012

December 31, 2011

June 30, 2012

December 31, 2011

Commodity

Quantity

Net Position

Quantity

Net Position

Quantity

Net Position

Quantity

Net Position

Financial transmission rights (MWh)

79,607

Long

267,480

Long

366,472

Long

267,480

Long

Electric capacity (MW–Days)

5,185

Long

12,920

Long

—

12,920

Long

Electric (MWh)

657,240

Long

788,280

Long

528,856

Long

788,280

Long

Natural gas (MMBtu)

15,037,300

Long

24,550,257

Long

9,474,741

Long

24,550,257

Long

DPL ~~holds~~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 ~~the change~~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~~clause for DPL’s derivatives or the ~~three months ended March 31, 2012 and 2011,~~NJBPU order for ACE’s derivatives associated with the SOCAs. The following table indicates the net unrealized derivative losses arising during the period ~~included in~~that were deferred as Regulatory assets and the net realized losses recognized in the consolidated statements of income ~~are provided in~~(through Fuel and purchased energy expense) that were also deferred as Regulatory assets for the ~~table below:~~three and six months ended June 30, 2012 and 2011 associated with these derivatives:

As of ~~March 31,~~June 30, 2012 and December 31, 2011, ~~DPL had~~ the ~~following~~quantity and position of DPL’s net outstanding natural gas commodity forward contracts and ACE’s capacity derivatives associated with the SOCAs that did not qualify for hedge ~~accounting:~~accounting were:

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 party’s 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 PHI’s or DPL’s 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 PHI’s derivative liabilities with credit risk-related contingent features as of ~~March 31,~~June 30, 2012 and December 31, 2011, were ~~$40~~$20 million and $54 million, respectively, before giving effect to offsetting transactions or collateral under master netting agreements. As of ~~March 31,~~June 30, 2012, PHI had posted no cash collateral against its gross derivative liability, resulting in a net liability of ~~$40~~$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 PHI’s and DPL’s debt ratings had been downgraded below investment grade as of ~~March 31,~~June 30, 2012 and December 31, 2011, PHI’s 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 ~~$111~~$72 million and $124 million, respectively, and PHI would have been required to post additional collateral with the counterparties of approximately ~~$111~~$72 million and $123 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

PHI’s primary ~~sources~~source for posting cash collateral or letters of credit ~~are~~is its credit facility. At ~~March 31,~~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 ~~$679~~$969 million and ~~$1 billion,~~$994 million, respectively, of which ~~$227~~$383 million and $283 million, respectively, was available to Pepco Energy Services.

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, PHI’s financial assets and liabilities ~~(excluding Conectiv Energy assets and liabilities held for sale)~~ that were accounted for at fair value on a recurring basis as of ~~March 31,~~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. PHI’s 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.


	Fair Value Measurements at March 31, 2012								Fair Value Measurements at June 30, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	*(millions of dollars)*								*(millions of dollars)*
ASSETS
Derivative instruments (b)
Electricity (c)	$	3	$	—	$	3	$	—	$	3	$	—	$	3	$	—
Capacity (e)										8		—		—		8
Cash equivalents
Treasury fund		70		70		—		—		46		46		—		—
Executive deferred compensation plan assets
Money market funds		16		16		—		—		14		14		—		—
Life insurance contracts		61		—		43		18		62		—		43		19

	$	150	$	86	$	46	$	18	$	133	$	60	$	46	$	27

LIABILITIES
Derivative instruments (b)
Electricity (c)	$	31	$	—	$	31	$	—	$	22	$	—	$	22	$	—
Natural gas (d)		56		42		—		14		38		27		—		11
Capacity (e)										9		—		—		9
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—		27		—		27		—

	$	115	$	42	$	59	$	14	$	96	$	27	$	49	$	20

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.

PHI’s level 2 derivative instruments primarily consist of electricity derivatives at ~~March 31,~~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 ~~that~~and certain employment agreement obligations. The life insurance policies are categorized as level 2 assets because they are ~~priced~~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 ~~March 31,~~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 ~~include~~that are significant ~~inputs that are~~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, ~~and~~ natural gas physical basis contracts held by Pepco Energy ~~Services.~~ Services, and capacity under the SOCAs entered into by ACE:

ACE used a discounted cash flow methodology to estimate the fair value of the capacity derivatives embedded in the SOCAs. ACE utilized an external consulting firm to estimate annual zonal PJM capacity prices through the 2030-2031 auction. The capacity price forecast was based on various assumptions that impact the cost of constructing new generation facilities, including zonal load forecasts, zonal fuel and energy prices, generation capacity and transmission planning, and environmental legislation and regulation. ACE reviewed the assumptions and resulting capacity price forecast for reasonableness. ACE used the capacity price forecast to estimate future cash flows. A significant change in the forecasted prices would have a significant impact on the estimated fair value of the SOCAs. ACE employed a discount rate reflective of the estimated weighted average cost of capital for merchant generation companies since payments under the SOCAs are contingent on providing generation capacity.

The table below summarizes the primary unobservable inputs used to determine the fair value of PHI’s level 3 instruments and the range of values that could be used for those inputs as of ~~March 31,~~June 30, 2012:

PHI used values within these ranges as part of its fair value ~~estimates, and a~~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 ~~March 31,~~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 PHI’s fair value measurements using significant unobservable inputs (level 3) for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are shown below:


	Three Months Ended March 31, 2012					Six Months Ended June 30, 2012
	Natural Gas			Life Insurance Contracts		Natural Gas			Life Insurance Contracts		Capacity
	*(millions of dollars)*					*(millions of dollars)*
Beginning balance as of January 1	$	(17	)	$	17	$	(17	)	$	17	$	—
Total gains (losses) (realized and unrealized)
Total gains (losses) (realized and unrealized):
Included in income		—			1		—			2		—
Included in accumulated other comprehensive loss		—			—		—			—		—
Included in regulatory assets		(3	)		—		(3	)		—		(1	)
Purchases		—			—		—			—		—
Issuances		—			—		—			—		—
Settlements		6			—		9			—		—
Transfers in (out) of level 3		—			—		—			—		—

Ending balance as of March 31	$	(14	)	$	18
Ending balance as of June 30						$	(11	)	$	19	$	(1	)


	Three Months Ended March 31, 2011						Six Months Ended June 30, 2011
	Natural Gas			Life Insurance Contracts			Natural Gas			Life Insurance Contracts
	*(millions of dollars)*						*(millions of dollars)*
Beginning balance as of January 1	$	(23	)	$	19		$	(23	)	$	19
Total gains (losses) (realized and unrealized)
Total gains (losses) (realized and unrealized):
Included in income		—			3			—			5
Included in accumulated other comprehensive loss		—			—			—			—
Included in regulatory assets		(1	)		—			(2	)		—
Purchases		—			—			—			—
Issuances		—			(1	)		—			(1	)
Settlements		5			(4	)		8			(4	)
Transfers in (out) of level 3		—			—			(4	)		—

Ending balance as of March 31	$	(19	)	$	17
Ending balance as of June 30							$	(21	)	$	19

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:

The estimated fair values of PHI’s debt instruments that are measured at amortized cost in PHI’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of ~~March 31,~~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. PHI’s 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~~Long-term project funding represents debt instruments issued by Pepco Energy Services related to its energy savings contracts. ~~Long-Term~~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 PHI’s debt instruments at December 31, 2011 are shown below:


	December 31, 2011				December 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	*(millions of dollars)*				*(millions of dollars)*
Long-term debt	$	3,867	$	4,577	$	3,867	$	4,577
Transition Bonds issued by ACE Funding		332		380		332		380
Long-term project funding		15		15		15		15

The carrying amounts of all other financial instruments in the accompanying consolidated financial statements approximate fair value.

In 1993, Pepco was served with Amended Complaints filed in the state Circuit Courts of Prince George’s County, Baltimore City and Baltimore County, Maryland in separate ongoing, consolidated proceedings known as “In re: Personal Injury Asbestos Case.” Pepco and other corporate entities were brought into these cases on a theory of premises liability. Under this theory, the plaintiffs argued that Pepco was negligent in not providing a safe work environment for employees or its contractors, who allegedly were exposed to asbestos while working on Pepco’s property. Initially, a total of approximately 448 individual plaintiffs added Pepco to their complaints. While the pleadings were not entirely clear, it appeared that each plaintiff sought $2 million in compensatory damages and $4 million in punitive damages from each defendant. In the intervening years, most of the cases were voluntarily dismissed by the plaintiffs prior to their respective trial dates. At the beginning of the first quarter of 2012, there were approximately 90 cases pending against Pepco in the Maryland State Courts (excluding those tendered to Mirant Corporation (Mirant) for defense and indemnification in connection with the sale by Pepco of its generation assets to Mirant in 2000), with an aggregate amount of monetary damages sought of approximately $360 million. On March 1, 2012, the parties to these consolidated proceedings (each represented by the same law firm) filed a stipulation of dismissal, by which the plaintiffs voluntarily dismissed Pepco as a defendant, eliminating any reasonably possible liability Pepco may have had with respect to these proceedings.

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 Jersey’s 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 decedent’s 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 decedent’s 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 PHI’s 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 ~~March 31,~~June 30, 2012 are summarized as follows:


			Legacy Generation										Legacy Generation
	Transmission and Distribution		Regulated		Non-Regulated		Other		Total		Transmission and Distribution		Regulated			Non-Regulated		Other		Total
	*(millions of dollars)*										*(millions of dollars)*
Beginning balance as of January 1	$	15	$	8	$	10	$	2	$	35	$	15	$	8		$	10	$	2	$	35
Accruals		—		—		—		—		—		—		—			—		—		—
Payments		—		1		—		—		1		—		(1	)		—		—		(1	)

Ending balance as of March 31		15		7		10		2		34
Ending balance as of June 30												15		7			10		2		34
Less amounts in Other current liabilities		2		2		—		2		6		2		2			—		2		6

Amounts in Other deferred credits	$	13	$	5	$	10	$	—	$	28	$	13	$	5		$	10	$	—	$	28

On July 1, 2010, PHI sold the Conectiv Energy wholesale power generation business to Calpine. Under New Jersey’s 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 ~~January 1, 2001~~February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. ~~The~~PHI responded to the data ~~request covers the period from February 2004 to July 1, 2010.~~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 ~~position or~~condition, results of ~~operations.~~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.

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. EPA’s claims are based on ACE’s 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, EPA’s 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 ACE’s 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.

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 Peck’s 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 (NPL).~~List. The ~~NPL,~~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.

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 ~~next step in the~~ litigation ~~will be the~~is moving forward with certain “test case” defendants (not including ACE, DPL and Pepco) filing of summary judgment motions regarding ~~liability for certain “test case” defendants, not including ACE, DPL and Pepco.~~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.

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 DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. ~~In February 2011, the District of Columbia filed a complaint against~~The consent decree does not obligate Pepco ~~and~~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 ~~United States District Court for~~river that are determined to be attributable to past activities at the ~~District of Columbia for the purpose of obtaining judicial approval of the consent decree.~~Benning Road site. On December 1, 2011, the U.S. District Court ~~issued an order granting~~approved the ~~motion to enter a revised~~ consent decree. The ~~District Court’s~~ order entering the consent decree requires DDOE to solicit and consider public comment on the key RI/FS documents prior to final approval, requires DDOE to make final versions of all approved RI/FS documents available to the public, and 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 byduring the ~~end of the third quarter~~fall of 2012, at which time the RI/FS field work ~~activities~~ 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.

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.

In January 2011, a coupling failure on a transformer cooler pipe resulted in a release of non-toxic mineral oil at Pepco’s 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 ~~that require~~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 ~~has submitted an incident report and is providing the requested records. In December 2011, Pepco~~ completed field sampling during the fourth quarter of 2011 and ~~anticipates submitting a report~~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.

OnIn June 2012, Pepco commenced discussions with DDOE regarding a possible consent decree that would resolve DDOE’s threatened claims for civil penalties for alleged violation of the District’s 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 ~~16,~~ 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 onin April ~~20,~~ 2011. OnIn March ~~25,~~ 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, which EPA advised may lead to an EPA demand for noncompliance penalties.~~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 accumulated storm water from the secondary containment system. Pepco currently is ~~currently~~ seeking DDOE’s and EPA’s approval to commence operation of the new system and, after receiving such approval, will submit a further revised SPCC plan to EPA. In the meantime, Pepco ~~will continue~~is continuing to use the above ground holding tank to manage storm water from the secondary containment system.

~~In addition to the cost to remediate impacts to the river and shoreline,~~ On April 19, 2012, EPA advised Pepco ~~also may be liable for non-compliance penalties and/or natural resource damages in addition to those~~that it ~~has already paid. It~~ is not ~~possible to accurately estimate an amount or range of reasonably possible loss to which it may be exposed associated with this liability~~seeking civil penalties at this ~~time; however, based on current information, PHI and Pepco do not believe this matter will have a material adverse effect on their respective financial conditions, results of operations or cash flows.~~time for alleged non-compliance with SPCC regulations.

The amounts accrued for these matters are included in the table above under the column entitled Transmission and Distribution.

In October 2011, Pepco Energy Services received a notice of violation from the VADEQ, which advised Pepco Energy Services of information on which VADEQ may rely to institute an administrative or judicial enforcement action in connection with alleged violation of Virginia air pollution control law and regulations at the facility of Pepco Energy Services’ subsidiary Fauquier County Landfill Gas, L.L.C. in Warrenton, Virginia. The notice of violation is based on an on-site VADEQ inspection during which VADEQ observed certain alleged deficiencies relating to the facility’s permit to construct and operate. On February 21, 2012, Pepco Energy Services signed a proposed consent order sent by VADEQ, pursuant to which Pepco Energy Services agreed to perform certain remedial actions and agreed to pay a civil charge of approximately $10,000.

PCI has entered seven cross-border energy lease investments involving public utility assets (primarily consisting of hydroelectric generation and coal-fired electric generation facilities and natural gas distribution networks) located outside of the United States. Each of these investments is comprised of multiple leases and each investment is structured as a sale and leaseback transaction commonly referred to by the IRS as a sale-in, lease-out, or SILO transaction. PHI current annual tax benefits from these lease investments are approximately $48 million. As of ~~March 31,~~June 30, 2012, the book value of PHI’s investment in its cross-border energy lease investments was approximately $1.4 billion. After taking into consideration the $74 million paid with the 2001-2002 audit (as discussed below), the net federal and state tax benefits received for the remaining leases from January 1, 2001, the earliest year that remains open to audit, to ~~March 31,~~June 30, 2012, has been approximately ~~$522~~$534 million.

Since 2005, PHI’s cross-border energy lease investments have been under examination by the IRS as part of the PHI federal income tax audits. In connection with the audit of PHI’s 2001-2002 and 2003-2005 income tax returns, respectively, the IRS disallowed the depreciation and interest deductions in excess of rental income claimed by PHI with respect to each of its cross-border energy lease investments. In addition, the IRS has sought to recharacterize each of the leases as a loan transaction as to which PHI would be subject to original issue discount income. PHI disagreed with the IRS’ proposed adjustments and filed protests of these findings with the Office of Appeals of the IRS. In November 2010, PHI entered into a settlement agreement with the IRS for the 2001 and 2002 tax years and subsequently filed refund claims in July 2011 for the disallowed tax deductions relating to the leases for these years. In January 2011, as part of this settlement, PHI paid $74 million of additional tax for 2001 and 2002, penalties of $1 million, and $28 million in interest associated with the disallowed deductions. Since the July 2011 claim for refund was not approved by the IRS within the statutory six-month period, in January 2012 PHI filed complaints in the U.S. Court of Federal Claims seeking recovery of the tax payment, interest and penalties. Absent a settlement, this litigation against the IRS may take several years to resolve. The 2003-2005 income tax return review continues to be in process with the IRS Office of Appeals and at present, ~~will~~is not be a part of the U.S. Court of Federal Claims litigation discussed above.

In the event that the IRS were to be successful in disallowing 100% of the tax benefits associated with these lease investments and recharacterizing these lease investments as loans, PHI estimates that, as of ~~March 31,~~June 30, 2012, it would be obligated to pay approximately ~~$658~~$674 million in additional federal and state taxes and ~~$127~~$132 million of interest on the remaining leases. The ~~$785~~$806 million in additional federal and state taxes and interest is net of the $74 million tax payment made in January 2011. In addition, the IRS could require PHI to pay a penalty of up to 20% on the amount of additional taxes due.

PHI anticipates that any additional taxes that it would be required to pay as a result of the disallowance of prior deductions or a re-characterization of the leases as loans would be recoverable in the form of lower taxes over the remaining terms of the affected leases. Moreover, the entire amount of any additional federal and state tax would not be due immediately, but rather, the federal and state taxes would be payable when the open audit years are closed and PHI amends subsequent tax returns not then under audit. To mitigate the taxes due in the event of a total disallowance of tax benefits, PHI could elect to liquidate all or a portion of its remaining cross-border energy lease investments, which PHI estimates could be accomplished over a period of six months to one year. Based on current market values, PHI estimates that liquidation of the remaining portfolio would generate sufficient cash proceeds to cover the estimated ~~$785~~$806 million in federal and state taxes and interest due as of ~~March 31,~~June 30, 2012, in the event of a total disallowance of tax benefits and a recharacterization of the leases as loans. If payments of additional taxes and interest preceded the receipt of liquidation proceeds, the payments would be funded by currently available sources of liquidity.

To the extent that PHI does not prevail in this matter and suffers a disallowance of the tax benefits and incurs imputed original issue discount income, PHI would be required under FASB guidance on leases (ASC 840) to recalculate the timing of the tax benefits generated by the cross-border energy lease investments and adjust the equity value of the investments, which would result in a material non-cash charge to earnings.

On January 20, 2012, the District of Columbia Office of Tax and Revenue issued proposed regulations to implement the mandatory unitary combined reporting method for tax years beginning in 2011. PHI will continue to analyze these regulations and will record the impact, if any, of such regulations on PHI’s results of operations in the period in which the proposed regulations are adopted as final regulations.

PHI and certain of its subsidiaries have various financial and performance guarantees and indemnification obligations that they have entered into in the normal course of business to facilitate commercial transactions with third parties as discussed below.

As of ~~March 31,~~June 30, 2012, PHI and its subsidiaries were parties to a variety of agreements pursuant to which they were guarantors for standby letters of credit, energy procurement obligations, and other commitments and obligations. The commitments and obligations, in millions of dollars, were as follows:


	Guarantor										Guarantor
	PHI		Pepco		DPL		ACE		Total		PHI		Pepco		DPL		ACE		Total
Energy procurement obligations of Pepco Energy Services (a)	$	160	$	—	$	—	$	—	$	160	$	121	$	—	$	—	$	—	$	121
Guarantees associated with disposal of Conectiv Energy assets (b)		18		—		—		—		18		13		—		—		—		13
Guaranteed lease residual values (c)		2		4		5		3		14		2		4		6		3		15

Total	$	180	$	4	$	5	$	3	$	192	$	136	$	4	$	6	$	3	$	149

PHI and certain of its subsidiaries have entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These indemnification agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. Typically, claims may be made by third parties under these indemnification agreements over various periods of time depending on the nature of the claim. The maximum potential exposure under these indemnification agreements can range from a specified dollar amount to an unlimited amount depending on the nature of the claim and the particular transaction. The total maximum potential amount of future payments under these indemnification agreements is not estimable due to several factors, including uncertainty as to whether or when claims may be made under these indemnities.

Pepco Energy Services has a diverse portfolio of energy services performance contracts that are associated with the installation of energy savings equipment or combined heat and power facilities for federal, state and local government customers. As part of the energy savings contracts, Pepco Energy Services typically guarantees that the equipment or systems installed by Pepco Energy Services will generate a specified amount of energy savings on an annual basis over a multi-year period. As of ~~March 31,~~June 30, 2012, Pepco Energy Services’ energy savings guarantees on both completed projects and projects under construction totaled ~~$441~~$439 million over the

life of the performance contracts with the longest remaining term being 15 years. On an annual basis, Pepco Energy Services undertakes a measurement and verification process to determine the amount of energy savings for the year and whether there is any shortfall in the annual energy savings compared to the guaranteed amount. As of ~~March 31,~~June 30, 2012, Pepco Energy Services had performance guarantee contracts associated with the production at its combined heat and power facilities on both completed projects and projects under construction totaling $15 million over the life of the contracts, with the longest remaining term being 20 years. Pepco Energy Services recognizes a liability for the value of the estimated energy savings or production shortfalls when it is probable that the guaranteed amounts will not be achieved and the amount is reasonably estimable. As of ~~March 31,~~June 30, 2012, Pepco Energy Services did not have an accrued liability for energy savings or combined heat and power performance contracts. There was no significant change in the type of contracts issued for the three and six months ended ~~March 31,~~June 30, 2012. Based on its historical experience, Pepco Energy Services believes the probability of incurring a material loss under its energy savings or combined heat and power performance contracts is remote.

From time to time, PHI is ~~also~~ required to guarantee the obligations of Pepco Energy Services under certain of its ~~construction~~energy efficiency and combined heat and power contracts. At ~~March 31,~~June 30, 2012, PHI’s guarantees of Pepco Energy Services’ ~~construction projects~~obligations under these contracts totaled ~~$143~~$147 million.

On ~~April~~July 26, 2012, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable ~~June 29,~~September 28, 2012, to stockholders of record on ~~June 11,~~September 10, 2012.

The components of Pepco Holdings’ AOCL relating to continuing operations are as follows. For additional information, see the consolidated statements of comprehensive income.


	Commodity Derivatives			Treasury Lock			Prior Service Costs			Total			Commodity Derivatives			Treasury Lock			Pension and Other Postretirement Benefit Plans			Total
	*(millions of dollars)*												*(millions of dollars)*
Balance, December 31, 2011	$	(29	)	$	(10	)	$	(24	)	$	(63	)	$	(29	)	$	(10	)	$	(24	)	$	(63	)
Current year change		8			—			—			8
Change in period														8			—			—			8

Balance, March 31, 2012	$	(21	)	$	(10	)	$	(24	)	$	(55	)		(21	)		(10	)		(24	)		(55	)
Change in period														6			—			(2	)		4

Balance, June 30, 2012													$	(15	)	$	(10	)	$	(26	)	$	(51	)

The income tax expense for each component of Pepco Holdings’ other comprehensive income is as follows:

In April 2010, the Board of Directors approved a plan for the disposition of PHI’s competitive wholesale power generation, marketing and supply business, which had been conducted through Conectiv Energy. On July 1, 2010, PHI completed the sale of Conectiv Energy’s wholesale power generation business to Calpine. The disposition of all of Conectiv Energy’s 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 is complete.

~~Income~~Loss from discontinued operations, net of income taxes, for the three months ended ~~March 31,~~June 30, 2012 and 2011, was zero and $2$1 million, respectively. Income from discontinued operations, net of income taxes, for the six months ended June 30, 2012 and 2011, was zero and $1 million, respectively.


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
Operating Revenue	$	465		$	534		$	456		$	506		$	921		$	1,040

Operating Expenses
Purchased energy		185			255			160			218			345			473
Other operation and maintenance		103			102			101			100			204			202
Depreciation and amortization		47			42			48			42			95			84
Other taxes		90			92			92			94			182			186

Total Operating Expenses		425			491			401			454			826			945

Operating Income		40			43			55			52			95			95

Other Income (Expenses)
Interest expense		(25	)		(24	)		(24	)		(22	)		(49	)		(46	)
Other income		4			6			4			4			8			10

Total Other Expenses		(21	)		(18	)		(20	)		(18	)		(41	)		(36	)

Income Before Income Tax Expense		19			25			35			34			54			59
Income Tax (Benefit) Expense		(5	)		7
Income Tax Expense								8			2			3			9

Net Income	$	24		$	18		$	27		$	32		$	51		$	50


	March 31, 2012		December 31, 2011		June 30, 2012		December 31, 2011
	*(millions of dollars, except shares)*				*(millions of dollars, except shares)*
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	204	$	74	$	108	$	74
Accounts payable and accrued liabilities		200		209		217		209
Accounts payable due to associated companies		64		57		59		57
Capital lease obligations due within one year		8		8		12		8
Taxes accrued		51		63		54		63
Interest accrued		36		17		17		17
Other		111		110		108		110

Total Current Liabilities		674		538		575		538

DEFERRED CREDITS
Regulatory liabilities		173		169		169		169
Deferred income taxes, net		1,173		1,039		1,180		1,039
Investment tax credits		5		5		4		5
Other postretirement benefit obligations		67		66		67		66
Liabilities and accrued interest related to uncertain tax positions		5		38		3		38
Other		68		68		65		68

Total Deferred Credits		1,491		1,385		1,488		1,385

LONG-TERM LIABILITIES
Long-term debt		1,540		1,540		1,701		1,540
Capital lease obligations		78		78		70		78

Total Long-Term Liabilities		1,618		1,618		1,771		1,618

COMMITMENTS AND CONTINGENCIES (NOTE 11)
EQUITY
Common stock, $.01 par value, 200,000,000 shares authorized, 100 shares outstanding		—		—		—		—
Premium on stock and other capital contributions		705		705		755		705
Retained earnings		821		797		848		797

Total Equity		1,526		1,502		1,603		1,502

TOTAL LIABILITIES AND EQUITY	$	5,309	$	5,043	$	5,437	$	5,043


	Three Months Ended March 31,						Six Months Ended June 30,
	2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
OPERATING ACTIVITIES
Net income	$	24		$	18		$	51		$	50
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		47			42			95			84
Deferred income taxes		127			26			127			17
Changes in:
Accounts receivable		35			28			4			(9	)
Inventories		(4	)		(4	)		(11	)		—
Prepaid expenses								14			14
Regulatory assets and liabilities, net		(14	)		(4	)		(34	)		(1	)
Accounts payable and accrued liabilities		(7	)		(33	)		(2	)		(8	)
Prepaid pension expense								11			9
Pension contributions		(85	)		(40	)		(85	)		(40	)
Taxes accrued		(139	)		50
Interest accrued		19			19
Income tax-related prepayments, receivables and payables								(129	)		62
Other assets and liabilities		4			16			(5	)		(6	)

Net Cash From Operating Activities		7			118			36			172

INVESTING ACTIVITIES
Investment in property, plant and equipment		(158	)		(97	)		(306	)		(205	)
Department of Energy capital reimbursement awards received		6			8			21			14
Net other investing activities		2			(1	)		3			(6	)

Net Cash Used By Investing Activities		(150	)		(90	)		(282	)		(197	)

FINANCING ACTIVITIES
Capital contribution from Parent								50			—
Issuances of long-term debt								200			—
Reacquisitions of long-term debt								(38	)		—
Issuances of short-term debt, net		130			—			34			—
Cost of issuances								(4	)		—
Net other financing activities		8			—			(1	)		(5	)

Net Cash From Financing Activities		138			—
Net Cash From (Used By) Financing Activities								241			(5	)

Net (Decrease) Increase in Cash and Cash Equivalents		(5	)		28
Net Decrease in Cash and Cash Equivalents								(5	)		(30	)
Cash and Cash Equivalents at Beginning of Period		12			88			12			88

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	7		$	116		$	7		$	58

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid (received) for income taxes (includes payments to (from) PHI for federal income taxes)	$	1		$	(70	)	$	1		$	(71	)


	Common Stock				Premium on Stock				Retained Earnings				Total			Common Stock					Premium on Stock			Retained Earnings			Total
*(millions of dollars, except shares)*	Shares		Par Value						Retained Earnings			Shares					Par Value				Premium on Stock			Retained Earnings			Total
BALANCE, DECEMBER 31, 2011		100	$	—	Premium on Stock		$	705			$	797	Total		$	1,502		100		$	—		$	705		$	797		$	1,502
Net Income		—		—		—				24				24
Net income																	—		—			—			24			24

BALANCE, MARCH 31, 2012		100	$	—	$	705			$	821			$	1,526			100		—			705			821			1,526
Net income																	—		—			—			27			27
Capital contribution from Parent																	—		—			50			—			50

BALANCE, JUNE 30, 2012																	100	$	—		$	755		$	848		$	1,603

Potomac Electric Power Company (Pepco) is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both the District of Columbia and Maryland. Pepco is a wholly owned subsidiary of Pepco Holdings, Inc. (Pepco Holdings or PHI).

Pepco’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in Pepco’s 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 Pepco’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly Pepco’s financial condition as of ~~March 31,~~June 30, 2012, in accordance with GAAP. The year-end December 31, 2011 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended ~~March 31,~~June 30, 2012 may not be indicative of results that will be realized for the full year ending December 31, 2012.

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 financial statements and accompanying notes. Although Pepco 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 impairment evaluations, pension and other postretirement benefits 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, and income tax provisions and reserves. Additionally, Pepco is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. Pepco 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.

Total incremental storm restoration costs incurred by Pepco through June 30, 2012 were $1.6 million, with $1.0 million incurred for repair work and $0.6 million incurred as capital expenditures. Costs incurred for repair work of $0.8 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland, and $0.2 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 Pepco associated with the derecho are currently estimated to range between $39 million and $47 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. Pepco will be pursuing recovery of the incremental storm restoration costs during the next cycle of distribution base rate cases.

During the second quarter of 2011, Pepco reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for Pepco at June 30, 2011.

Taxes included in Pepco’s gross revenues were ~~$84~~$86 million and $85 million for the three months ended ~~March 31,~~June 30, 2012 and 2011, respectively, and $169 million and $171 million for the six months ended June 30, 2012 and 2011, respectively.

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following ~~adjustment has~~adjustments have been recorded and isare not considered ~~material:~~material either individually or in the aggregate:

Fair Value Measurements and Disclosures (Accounting Standards Codification (ASC) 820)

The Financial Accounting Standards Board (FASB) issued new guidance on fair value measurement and disclosures that was effective beginning with Pepco’s March 31, 2012 financial statements. The new measurement guidance did not have a material impact on Pepco’s financial statements and the new disclosure requirements are in Note (10), “Fair Value Disclosures,” of Pepco’s financial statements.

Pepco operates its business as one regulated utility segment, which includes all of its services as described above.

Over the last several years, Pepco has proposed in each of its jurisdictions the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. To date, a bill stabilization adjustment (BSA) has been approved and implemented for ~~Pepco~~ electric service in Maryland and for electric service in the District of Columbia. The Maryland Public Service Commission (MPSC) has issued an order requiring modification of the BSA in Maryland so that revenues lost as a result of major storm outages are not collected 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 (as discussed below). 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.

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 has proposed in each of its jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, Pepco 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 year’s 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. Pepco’s 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 Pepco’s electric distribution base rate proceedings.

Pepco also has requested, in each of its 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 Pepco’s electric distribution base rate proceedings.

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 return on equity (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.

On December 16, 2011, Pepco submitted an application with the MPSC to increase its electric distribution base rates. The filing ~~seeks~~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 ~~includes~~included a request for MPSC approval of a RIM and the use of fully forecasted test years in future Pepco rate cases. AOn 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 Pepco’s depreciation rates, which are expected to lower annual depreciation and amortization expenses by an estimated $27.3 million. The order did not approve Pepco’s 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 ~~expected in July 2012.~~currently evaluating the MPSC order to determine what further actions, if any, it may seek to pursue.

In February 2011, the MPSC initiated proceedings involving Pepco ~~as well as~~and its affiliate Delmarva Power & Light Company (DPL) ~~and~~, 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 utility’s 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 ~~already~~ 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.

On September 29, 2009, the MPSC initiated an investigation into whether the ~~regulated~~ electric distribution companies (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.

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. Pepco is evaluating the impact of the order, 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 ~~its~~Pepco’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate Pepco and its debt issuances, (ii) the effect on ~~its~~Pepco’s ability to recover its 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 ~~its~~the financial condition, results of operations and cash ~~flows.~~flows of Pepco. On April 27, 2012, a group of generators operating in the PJM Interconnection, LLC region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSC’s 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, ~~continues to evaluate whether to seek~~DPL, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order.

Pepco accounts for its participation in its parent’s single-employer plans, ~~the~~ Pepco ~~Holdings, Inc. Retirement Plan~~Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended ~~March 31,~~June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were ~~$26~~$30 million and ~~$27~~$19 million, respectively. Pepco’s allocated share was ~~$11~~$9 million and ~~$10~~$7 million, respectively, for the three months ended ~~March 31,~~June 30, 2012 and 2011. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were $56 million and $46 million, respectively. Pepco’s allocated share was $20 million and $17 million, respectively, for the six months ended June 30, 2012 and 2011.

In the first quarter of 2012, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million. In the first quarter of 2011, Pepco made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $40 million.

PHI, Pepco, DPL and Atlantic City Electric Company (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 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 company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month ~~LIBOR~~London Interbank Offered Rate 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 ~~March 31,~~June 30, 2012.

At ~~March 31,~~June 30, 2012 and December 31, 2011, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was ~~$452~~$586 million and $711 million, respectively. Pepco’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by DPL and ACE and the portion of the total capacity being used by PHI.

Pepco maintains an on-going commercial paper program to address its short-term liquidity needs. As of ~~March 31,~~June 30, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

Pepco had ~~$204~~$108 million of commercial paper outstanding at ~~March 31,~~June 30, 2012. The weighted average interest rate for commercial paper issued by Pepco during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~0.40%~~0.41% and the weighted average maturity of all commercial paper issued by Pepco during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~five~~four days.

On April 4, 2012, Pepco issued $200 million of 3.05% first mortgage bonds due April 1, 2022. ~~Proceeds~~Net proceeds from the issuance of the long-term debt were primarily used (i) to repay Pepco’s outstanding commercial paper that was issued to temporarily fund capital expenditures and working capital, (ii) to ~~redeem,~~fund the redemption, prior to maturity, of all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds due ~~February 15,~~in 2024 issued by the Industrial Development Authority of the City of Alexandria, Virginia (IDA), on Pepco’s behalf and (iii) for general corporate purposes.

On April 30, 2012, all of the $38.3 million outstanding of the 5.375% pollution control revenue refunding bonds issued by IDA for Pepco’s benefit were redeemed as noted in the preceding paragraph. In connection with such redemption, Pepco redeemed all of the $38.3 million outstanding of its 5.375% first mortgage bonds due ~~February 15,~~in 2024 that secured the obligations under such pollution control bonds.


	Three Months Ended March 31,										Three Months Ended June 30,										Six Months Ended June 30,
	2012					2011					2012					2011					2012					2011
	*(millions of dollars)*															*(millions of dollars)*
Income tax at Federal statutory rate	$	7		35.0	%	$	9		35.0	%	$	12		35.0	%	$	12		35.0	%	$	19		35.0	%	$	21		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		1		6.3			1		4.4			2		5.6			2		4.7			3		5.7			3		4.6
Asset removal costs												(4	)	(11.5	)		(2	)	(4.4	)		(7	)	(12.8	)		(3	)	(4.2	)
Change in estimates and interest related to uncertain and effectively settled tax positions		(10	)	(50.5	)		—		—			(1	)	(3.5	)		(4	)	(12.1	)		(11	)	(20.2	)		(4	)	(6.6	)
Permanent differences related to deferred compensation		—		(1.0	)		(1	)	(4.4	)
Asset removal costs		(3	)	(15.8	)		(1	)	(4.0	)
Amortization of software costs		—		2.1			—		(0.4	)
Deferred tax basis adjustments		—		(2.1	)		—		—
Permanent differences related to deferred compensation funding												—		(0.9	)		—		(1.2	)		(1	)	(0.9	)		(2	)	(2.5	)
State tax benefit related to prior years’ asset dispositions												—		—			(4	)	(12.4	)		—		—			(4	)	(7.1	)
Other, net		—		(0.3	)		(1	)	(2.6	)		(1	)	(1.8	)		(2	)	(3.8	)		—		(1.2	)		(2	)	(3.9	)

Income tax expense	$	(5	)	(26.3	)%	$	7		28.0	%	$	8		22.9	%	$	2		5.8	%	$	3		5.6	%	$	9		15.3	%

Pepco’s effective tax rates for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~(26.3)%~~22.9% and ~~28.0%~~5.8%, respectively. The increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions and refunds received on amended state tax returns in 2011 related to prior years’ asset dispositions.

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 have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, Pepco recorded an additional tax benefit in the amount of $5 million (after-tax) in the second quarter of 2011.

Also in the second quarter of 2011, Pepco 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 on certain prior years’ asset dispositions.

Pepco’s effective tax rates for the six months ended June 30, 2012 and 2011 were 5.6% and 15.3%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, partially offset by the state tax benefit recorded in 2011 related to prior years’ asset dispositions. The effective rate was further decreased as a result of the increase in asset removal costs in 2012 primarily related to a higher level of asset retirements.

In the first quarter of 2012, Pepco recorded income tax benefits related to uncertain and effectively settled tax positions primarily due to the effective settlement with the ~~Internal Revenue Service~~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. ~~The effective rate was further decreased as~~

In the second quarter of 2011, Pepco recorded a ~~result~~$5 million interest benefit from the reallocation of ~~the increase in asset removal costs in 2012 primarily~~its deposits and a $4 million tax benefit related to the filing of amended state tax returns, as discussed above.

Further, in March of 2011, Pepco accrued $3 million related to proceeds from life insurance policies on a ~~higher level of asset retirements.~~former executive. This income is not taxable and is included in the permanent differences related to deferred compensation funding.

Pepco 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). Pepco 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, Pepco 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, Pepco’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of ~~March 31,~~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. Pepco’s 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.


	Fair Value Measurements at March 31, 2012								Fair Value Measurements at June 30, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	*(millions of dollars)*								*(millions of dollars)*
ASSETS
Executive deferred compensation plan assets
Money market funds	$	13	$	13	$	—	$	—	$	12	$	12	$	—	$	—
Life insurance contracts		57		—		39		18		58		—		39		19

	$	70	$	13	$	39	$	18	$	70	$	12	$	39	$	19

LIABILITIES
Executive deferred compensation plan liabilities
Life insurance contracts	$	10	$	—	$	10	$	—	$	9	$	—	$	9	$	—

	$	10	$	—	$	10	$	—	$	9	$	—	$	9	$	—

Pepco 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:

Reconciliations of the beginning and ending balances of Pepco’s fair value measurements using significant unobservable inputs (level 3) for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are shown below:


	Life Insurance Contracts					Life Insurance Contracts
	Three Months Ended March 31,					Six Months Ended June 30,
	2012		2011			2012		2011
	*(millions of dollars)*					*(millions of dollars)*
Beginning balance as of January 1	$	17	$	18		$	17	$	18
Total gains (losses) (realized and unrealized)
Total gains (losses) (realized and unrealized):
Included in income		1		3			2		5
Included in accumulated other comprehensive loss		—		—			—		—
Purchases		—		—			—		—
Issuances		—		(1	)		—		(1	)
Settlements		—		(4	)		—		(4	)
Transfers in (out) of level 3		—		—			—		—

Ending balance as of March 31	$	18	$	16
Ending balance as of June 30						$	19	$	18

The breakdown of realized and unrealized gains on level 3 instruments included in income as a component of Other operation and maintenance expense for the periods below were as follows:


	Three Months Ended March 31,				Six Months Ended June 30,
	2012		2011		2012		2011
	*(millions of dollars)*				*(millions of dollars)*
Total gains included in income for the period	$	1	$	3	$	2	$	5

Change in unrealized gains relating to assets still held at reporting date	$	1	$	1	$	2	$	2

The estimated fair values of Pepco’s debt instruments that are measured at amortized cost in Pepco’s financial statements and the associated level of the estimates within the fair value hierarchy as of ~~March 31,~~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. Pepco’s 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 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 Pepco reviews the methodologies and results.

The estimated fair ~~values~~value of Pepco’s debt instruments at December 31, 2011 ~~are~~is shown below:

The carrying amount of all other financial instruments in the accompanying financial statements approximate fair value.

Pepco 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 Pepco’s customers, environmental clean-up costs incurred by Pepco generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of Pepco described below at ~~March 31,~~June 30, 2012 are summarized as follows:

The U.S. Environmental Protection Agency (EPA) informed Pepco in a May 2009 letter that Pepco may be a potentially responsible party (PRP) under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (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 Peck’s 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 (NPL).~~List. The ~~NPL,~~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.

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 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 ~~next step in the~~ litigation ~~will be the~~is moving forward with certain “test case” defendants (not including Pepco) filing of summary judgment motions regarding ~~liability for certain “test case” defendants, not including Pepco.~~liability. The case has been stayed as to the

remaining defendants pending rulings upon the test cases. Although Pepco cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, Pepco does not believe that it 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.

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 ~~a subsidiary of Pepco’s affiliate,~~ Pepco Energy Services, ~~Inc. (collectively with its subsidiaries, 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 DDOE’s selection of a remedial action for the Benning Road site and for the Anacostia River sediment associated with the site. ~~In February 2011, the District of Columbia filed a complaint against~~The consent decree does not obligate Pepco ~~and~~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 ~~United States District Court for~~river that are determined to be attributable to past activities at the ~~District of Columbia for the purpose of obtaining judicial approval of the consent decree.~~Benning Road site. On December 1, 2011, the U.S. District Court ~~issued an order granting~~approved the ~~motion to enter a revised~~ consent decree. The ~~District Court’s~~ order entering the consent decree requires DDOE to solicit and consider public comment on the key RI/FS documents prior to final approval, requires DDOE to make final versions of all approved RI/FS documents available to the public, and 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.

The remediation costs accrued ~~by Pepco~~ for this matter are included in the table above under the columns entitled Transmission and Distribution and Legacy Generation – Regulated.

The amounts accrued for these matters are included in the table above under the column entitled Transmission and Distribution.

On January 20, 2012, the District of Columbia Office of Tax and Revenue issued proposed regulations to implement the mandatory unitary combined reporting method for tax years beginning in 2011. Pepco will continue to analyze these regulations and will record the impact, if any, of such regulations on Pepco’s results of operations in the period in which the proposed regulations are adopted as final regulations.

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including Pepco. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to Pepco for the three months ended ~~March 31,~~June 30, 2012 and 2011 were approximately ~~$51~~$52 million and $43 million, respectively. PHI Service Company costs directly charged or allocated to Pepco for the six months ended June 30, 2012 and 2011 were approximately $103 million and $86 million, respectively.

Pepco Energy Services performs utility maintenance services, including services that are treated as capital costs, for Pepco. Amounts charged to Pepco by Pepco Energy Services for the three months ended ~~March 31,~~June 30, 2012 and 2011 were approximately $5$6 million and $4 million, respectively. Amounts charged to Pepco by these companies for the six months ended June 30, 2012 and 2011 were approximately $10 million and $8 million, respectively.

As of ~~March 31,~~June 30, 2012 and December 31, 2011, Pepco had the following balances on its balance sheets due to related parties:


	March 31, 2012			December 31, 2011			June 30, 2012			December 31, 2011
(Liability) Asset	*(millions of dollars)*						*(millions of dollars)*
(Payable to) Receivable from Related Party (current) (a)
PHI Parent Company	$	—		$	15		$	—		$	15
PHI Service Company		(24	)		(32	)		(22	)		(32	)
Pepco Energy Services (b)		(40	)		(40	)		(37	)		(40	)

Total	$	(64	)	$	(57	)	$	(59	)	$	(57	)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
Operating Revenue
Electric	$	259		$	298		$	235		$	245		$	494		$	543
Natural gas		74			102			24			39			98			141

Total Operating Revenue		333			400			259			284			592			684

Operating Expenses
Purchased energy		143			182			122			145			265			327
Gas purchased		49			71			13			25			62			96
Other operation and maintenance		65			65			62			47			127			112
Depreciation and amortization		24			22			25			22			49			44
Other taxes		9			11			7			9			16			20

Total Operating Expenses		290			351			229			248			519			599

Operating Income		43			49			30			36			73			85


Other Income (Expenses)
Interest expense		(11	)		(11	)		(11	)		(11	)		(22	)		(22	)
Other income		3			2			3			2			6			4

Total Other Expenses		(8	)		(9	)		(8	)		(9	)		(16	)		(18	)


Income Before Income Tax Expense		35			40			22			27			57			67

Income Tax Expense		14			17			9			5			23			22


Net Income	$	21		$	23		$	13		$	22		$	34		$	45


	March 31, 2012		December 31, 2011		June 30, 2012		December 31, 2011
	*(millions of dollars, except shares)*				*(millions of dollars, except shares)*
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Short-term debt	$	238	$	152	$	105	$	152
Current portion of long-term debt		66		66		—		66
Accounts payable and accrued liabilities		84		92		93		92
Accounts payable due to associated companies		18		21		21		21
Taxes accrued		7		11		5		11
Interest accrued		12		6		9		6
Derivative liabilities		12		12		10		12
Other		59		59		61		59

Total Current Liabilities		496		419		304		419

DEFERRED CREDITS
Regulatory liabilities		292		297		292		297
Deferred income taxes, net		655		615		647		615
Investment tax credits		6		6		6		6
Other postretirement benefit obligations		23		22		23		22
Liabilities and accrued interest related to uncertain tax positions		—		9		—		9
Derivative liabilities		—		3		—		3
Other		38		37		41		37

Total Deferred Credits		1,014		989		1,009		989

LONG-TERM LIABILITIES
Long-term debt		699		699		948		699

COMMITMENTS AND CONTINGENCIES (NOTE 13)
EQUITY
Common stock, $2.25 par value, 1,000 shares authorized, 1,000 shares outstanding		—		—		—		—
Premium on stock and other capital contributions		347		347		347		347
Retained earnings		526		505		539		505

Total Equity		873		852		886		852

TOTAL LIABILITIES AND EQUITY	$	3,082	$	2,959	$	3,147	$	2,959


	Three Months Ended March 31,						Six Months Ended June 30,
	2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
OPERATING ACTIVITIES
Net income	$	21		$	23		$	34		$	45
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		24			22			49			44
Deferred income taxes		41			18			33			40
Changes in:
Accounts receivable		16			6			25			28
Inventories		4			9			(6	)		1
Regulatory assets and liabilities, net		(7	)		18			(23	)		(5	)
Accounts payable and accrued liabilities		(8	)		(34	)		6			(24	)
Pension contributions		(85	)		(40	)		(85	)		(40	)
Taxes accrued		(31	)		(4	)
Interest accrued		6			6
Income tax-related prepayments, receivables and payables								(12	)		(25	)
Other assets and liabilities		4			10			12			17

Net Cash (Used By) From Operating Activities		(15	)		34
Net Cash From Operating Activities								33			81

INVESTING ACTIVITIES
Investment in property, plant and equipment		(69	)		(41	)		(145	)		(99	)
Net other investing activities		(1	)		1			(2	)		(1	)

Net Cash Used By Investing Activities		(70	)		(40	)		(147	)		(100	)

FINANCING ACTIVITIES
Issuances of short-term debt, net		87			—
Net other financing activities		(3	)		—
Issuances of long-term debt								250			35
Reacquisitions of long-term debt								(66	)		(35	)
Repayments of short-term debt, net								(47	)		—
Cost of issuances								(3	)		—

Net Cash From Financing Activities		84			—			134			—

Net Decrease in Cash and Cash Equivalents		(1	)		(6	)
Net Increase (Decrease) in Cash and Cash Equivalents								20			(19	)
Cash and Cash Equivalents at Beginning of Period		5			69			5			69

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4		$	63		$	25		$	50

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for income taxes (includes payments to PHI for federal income taxes)	$	—		$	4
Cash (received) paid for income taxes (includes payments (from) to PHI for federal income taxes)							$	(3	)	$	8


	Common Stock										Common Stock				Premium on Stock				Retained Earnings				Total
*(millions of dollars, except shares)*	Shares		Par Value		Premium on Stock		Retained Earnings		Total		Shares		Par Value						Retained Earnings				Total
BALANCE, DECEMBER 31, 2011		1,000	$	—	$	347	$	505	$	852		1,000	$	—	Premium on Stock		$	347			$	505			$	852
Net Income		—		—		—		21		21
Net income												—		—		—				21				21

BALANCE, MARCH 31, 2012		1,000	$	—	$	347	$	526	$	873		1,000		—		347				526				873
Net income												—		—		—				13				13

BALANCE, JUNE 30, 2012												1,000	$	—	$	347			$	539			$	886

Delmarva Power & Light Company (DPL) is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland and provides natural gas distribution service in northern Delaware. ~~Additionally,~~ DPL also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territories who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Standard Offer Service in both Delaware and Maryland. DPL is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

DPL’s unaudited financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (GAAP). Pursuant to the rules and regulations of the Securities and Exchange Commission, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted. Therefore, these financial statements should be read along with the annual financial statements included in DPL’s 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 DPL’s management, the financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly DPL’s financial condition as of ~~March 31,~~June 30, 2012, in accordance with GAAP. The year-end December 31, 2011 balance sheet included herein was derived from audited financial statements, but does not include all disclosures required by GAAP. Interim results for the three and six months ended ~~March 31,~~June 30, 2012 may not be indicative of DPL’s results that will be realized for the full year ending December 31, 2012.

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 financial statements and accompanying notes. Although DPL 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 evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits 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, and income tax provisions and reserves. Additionally, DPL is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. DPL 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.

Total incremental storm restoration costs incurred by DPL through June 30, 2012 were $0.5 million, with $0.3 million incurred for repair work and $0.2 million incurred as capital expenditures. Costs incurred for repair work of $0.2 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in Maryland, and $0.1 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 DPL associated with the derecho are currently estimated to range between $2 million and $3 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. DPL will be pursuing recovery of the incremental storm restoration costs during the next cycle of distribution base rate cases.

During the second quarter of 2011, DPL reduced its self-insurance reserves for general and auto liability claims by approximately $2 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for DPL at June 30, 2011.

DPL 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.

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. DPL’s costs associated with obtaining RECs to fulfill its RPS obligations are recoverable from its customers by law. As of June 30, 2012, DPL has entered into three land-based wind power purchase agreements (PPAs) in the aggregate amount of 128 megawatts and one solar PPA with a 10 megawatt ~~facility as of March 31, 2012.~~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 ~~these agreements.~~the PPAs. DPL has concluded that consolidation is not required for any of these ~~agreements~~PPAs under the FASB guidance on the consolidation of variable interest entities.

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 ~~provide~~provides for a reduction in DPL’s REC requirements based upon the actual energy output of the facilities. In June 2012, a 3 megawatt fuel cell generation facility ~~is expected to be~~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. ~~PHI has concluded that~~ DPL ~~would account~~is accounting for this arrangement as an agency transaction.

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired at the acquisition date. All of DPL’s goodwill was generated by DPL’s acquisition of Conowingo Power Company in 1995. DPL 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 DPL below the carrying amount of its net assets. ~~DPL performs its annual impairment test as of November 1.~~ 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; an adverse regulatory action; or an impairment of DPL’s long-lived assets. DPL concluded that an interim impairment test was not required during the ~~three~~six months ended ~~March 31,~~June 30, 2012.

Taxes included in DPL’s gross revenues were $4 million for each of the three months ended June 30, 2012 and $52011, and $8 million and $9 million for the six months ended June 30, 2012 and 2011, respectively.

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustments have been recorded and are not considered material:

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.

The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with DPL’s March 31, 2012 financial statements. The new measurement guidance did not have a material impact on DPL’s financial statements and the new disclosure requirements are in Note (12), “Fair Value Disclosures,” of DPL’s financial statements.

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, DPL has adopted the new guidance and concluded it did not have a material impact on its financial statements.

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 DPL’s March 31, 2013 financial statements. DPL is evaluating the impact of this new guidance on its financial statements.

DPL operates its business as one regulated utility segment, which includes all of its services as described above.

DPL’s goodwill balance of $8 million was unchanged during the ~~three~~six months ended ~~March 31,~~June 30, 2012. All of DPL’s goodwill was generated by its acquisition of Conowingo Power Company in 1995.

DPL’s annual impairment test as of November 1, 2011 indicated that goodwill was not impaired. For the ~~three~~six months ended ~~March 31,~~June 30, 2012, DPL concluded that there were no events requiring it to perform an interim goodwill impairment test. DPL will perform its next annual impairment test as of November 1, 2012.

Over the last several years, DPL has proposed in each of its 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 customer’s volumetric consumption) to recover the utility’s fixed costs, plus a reasonable rate of return. Although different from the BSA, ~~DPL~~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), DPL has proposed, in each of its jurisdictions, a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases. Through the RIM, 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 year’s 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. DPL’s 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 DPL’s electric distribution base rate proceedings.

DPL also has requested, ~~approval~~ in each of its 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 DPL’s electric distribution base rate proceedings.

~~been~~ proposed ~~and approved~~ by ~~the DPSC,~~DPL in ~~DPL’s~~its 2010 GCR filing (the settlement approved by the DPSC in ~~the~~its 2010 GCR case included only the first year of ~~such~~the proposed two-year amortization). The rates proposed in the 2011 GCR ~~which include the second year of the two-year amortization approved in the 2010 GCR case,~~ 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.~~

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. ~~As permitted by~~Under Delaware law, DPL ~~intends~~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 ~~approval. A decision by~~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 DPL’s annual rate increase request ($31.8 million) has not changed. The final DPSC order is expected by the end of ~~2012.~~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.

In February 2011, the MPSC initiated proceedings involving DPL ~~as well as~~and its affiliate Potomac Electric Power Company (Pepco) ~~and~~, 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 DPL, ~~and Pepco,~~ 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 utility’s 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. 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.

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. DPL is evaluating the impact of the order, 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 ~~its~~DPL’s balance sheets, as well as its credit metrics, as calculated by independent rating agencies that evaluate and rate DPL and its debt issuances, (ii) the effect on DPL’s ability to recover its 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 ~~its~~the financial condition, results of operations and cash ~~flows.~~flows of DPL. On April 27, 2012, a group of generators operating in the PJM Interconnection, LLC region filed a complaint in the United States District Court for the Northern District of Maryland challenging the MPSC’s order on the grounds that ~~that~~ such order violated the commerce clause and the supremacy clause of the U.S. Constitution. On May 4, 2012, DPL, ~~continues to evaluate whether to seek~~Pepco, BG&E and other parties filed notices of appeal in circuit courts in Maryland requesting judicial review of the MPSC’s order.

DPL accounts for its participation in its parent’s single-employer plans, ~~the~~ Pepco ~~Holdings, Inc. Retirement Plan~~Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended ~~March 31,~~June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were ~~$26~~$30 million and ~~$27~~$19 million, respectively. DPL’s allocated share was $6 million and $7$5 million, respectively, for the three months ended ~~March 31,~~June 30, 2012 and 2011. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were $56 million and $46 million, respectively. DPL’s allocated share was $12 million for each of the six months ended June 30, 2012 and 2011.

In the first quarter of 2012, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan of $85 million. In the first quarter of 2011, DPL made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $40 million.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month ~~LIBOR~~London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

At ~~March 31,~~June 30, 2012 and December 31, 2011, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was ~~$452~~$586 million and $711 million, respectively. DPL’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and ACE and the portion of the total capacity being used by PHI.

DPL maintains an on-going commercial paper program to address its short-term liquidity needs. As of ~~March 31,~~June 30, 2012, the maximum capacity available under the program was $500 million, subject to available borrowing capacity under the credit facility.

DPL had ~~$133 million of~~no commercial paper outstanding at ~~March 31,~~June 30, 2012. The weighted average interest rate for commercial paper issued by DPL during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~0.39%~~0.41% and the weighted average maturity of all commercial paper issued by DPL during the ~~three~~six months ended ~~March 31,~~June 30, 2012 was ~~four~~five days.

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 DPL’s benefit, as described above. 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.


	Three Months Ended March 31,								Three Months Ended June 30,									Six Months Ended June 30,
	2012				2011				2012				2011					2012				2011
	*(millions of dollars)*								*(millions of dollars)*
Income tax at Federal statutory rate	$	12	35.0	%	$	14	35.0	%	$	8	35.0	%	$	10		35.0	%	$	20	35.0	%	$	24		35.0	%
Increases (decreases) resulting from:
State income taxes, net of Federal effect		2	5.7	%		2	6.0			1	5.1			1		5.2			3	5.4			4		6.0
Change in estimates and interest related to uncertain and effectively settled tax positions										—	—			(5	)	(18.5	)		—	(0.2	)		(5	)	(7.5	)
Deferred tax adjustment										—	—			(1	)	(3.7	)		—	—			(1	)	(1.5	)
Depreciation										—	0.5			1		3.7			—	—			1		1.5
Other, net		—	(0.7	)		1	1.5			—	0.3			(1	)	(3.2	)		—	0.2			(1	)	(0.7	)

Income tax expense	$	14	40.0	%	$	17	42.5	%	$	9	40.9	%	$	5		18.5	%	$	23	40.4	%	$	22		32.8	%

DPL’s effective tax rates for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~40.0%~~40.9% and ~~42.5%~~18.5%, respectively. The ~~decrease~~increase in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions as discussed below.

During 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 have been on deposit with the IRS since 2006 among liabilities in the ~~first~~settlement years and subsequent years. Primarily related to the settlement and reallocations, DPL recorded an additional $4 million (after-tax) interest benefit in the second quarter of 2011. Also during the second quarter of 2011, DPL completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million decrease to income tax expense as shown in the “Deferred tax adjustment” line above.

DPL’s effective tax rates for the six months ended June 30, 2012 and 2011 were 40.4% and 32.8%, respectively. The increase in the effective tax rate resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to the additional $4 million interest benefit in 2011 from the reallocation of deposits discussed above.

DPL uses derivative instruments in the form of swaps and over-the-counter options primarily to reduce natural gas commodity price volatility and 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. ~~DPL’s capacity contracts are not classified as derivatives.~~ All premiums paid and other transaction costs incurred as part of DPL’s 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.

The tables below identify the balance sheet location and fair values of derivative instruments as of ~~March 31,~~June 30, 2012 and December 31, 2011:


	As of March 31, 2012													As of June 30, 2012
Balance Sheet Caption	Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments			Derivatives Designated as Hedging Instruments		Other Derivative Instruments			Gross Derivative Instruments			Effects of Cash Collateral and Netting		Net Derivative Instruments
	*(millions of dollars)*													*(millions of dollars)*
Derivative liabilities (current liabilities)	$	—	$	(14	)	$	(14	)	$	2	$	(12	)	$	—	$	(10	)	$	(10	)	$	—	$	(10	)
Derivative liabilities (non-current liabilities)		—		—			—			—		—			—		—			—			—		—

Total Derivative liabilities		—		(14	)		(14	)		2		(12	)		—		(10	)		(10	)		—		(10	)

Net Derivative (liability) asset	$	—	$	(14	)	$	(14	)	$	2	$	(12	)	$	—	$	(10	)	$	(10	)	$	—	$	(10	)

Under FASB guidance on the offsetting of balance sheet accounts (ASC ~~210)~~210-20), DPL offsets the fair value amounts recognized for derivative instruments and 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 ~~March 31, 2012 and~~ December 31, 2011, all DPL cash collateral pledged related to derivative instruments accounted for at fair value was entitled to be offset under master netting agreements.

All premiums paid and other transaction costs incurred as part of DPL’s natural gas hedging activity, in addition to all of DPL’s 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 ~~included in~~that were deferred as Regulatory assets and the net realized losses recognized in the statements of income (through Purchased energy or Gas purchased expense) that were also deferred as Regulatory assets for the three and six months ended ~~March 31,~~June 30, 2012 and 2011 associated with cash flow hedges:

DPL 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 sheets with the gain or loss for changes in the fair value recorded in income. In accordance with FASB guidance on regulated operations, offsetting regulatory liabilities or regulatory assets are recorded on the balance sheets and the recognition of the derivative gain or loss is deferred because of the DPSC-approved fuel adjustment clause. ~~For the three months ended March 31, 2012 and 2011,~~The following table indicates the net unrealized derivative losses arising during the period ~~included in~~that were deferred as Regulatory ~~Assets~~assets and the net realized losses recognized in the statements of income ~~are provided in~~(through Purchased energy and Gas purchased expense) that were also deferred as Regulatory assets for the ~~table below:~~three and six months ended June 30, 2012 and 2011 associated with these derivatives:

As of ~~March 31,~~June 30, 2012 and December 31, 2011, DPL had the following net outstanding natural gas commodity forward contracts that did not qualify for hedge accounting:

March 31, 2012

December 31, 2011

June 30, 2012

December 31, 2011

Commodity

Quantity

Net Position

Quantity

Net Position

Quantity

Net Position

Quantity

Net Position

Natural gas (MMBtu)

4,109,100

Long

6,161,200

Long

2,966,600

Long

6,161,200

Long

The primary contracts used by DPL 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 collateral requirements of~~ 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 party’s obligations. The fair values of all transactions between the parties are netted under the master netting provisions. Transactions may include derivatives accounted for on-balance sheet as well as normal purchases and normal sales that are accounted for off-balance sheet. 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 DPL are stand-alone obligations without the guaranty of PHI. If DPL’s 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 DPL’s derivative liabilities with credit-risk-related contingent features as of ~~March 31,~~June 30, 2012 and December 31, 2011, were ~~$12~~$10 million and $15 million, respectively. As of those dates, DPL had posted no cash collateral in the normal course of business against its gross derivative liabilities, resulting in net liabilities of ~~$12~~$10 million and $15 million, respectively. If DPL’s debt ratings had been downgraded below investment grade as of ~~March 31,~~June 30, 2012 and December 31, 2011, DPL’s net settlement amounts would have been approximately ~~$12~~$9 million and $15 million, respectively, and DPL would have been required to post additional collateral with the counterparties of approximately ~~$12~~$9 million and $15 million, respectively. The net settlement and additional collateral amounts reflect the effect of offsetting transactions under master netting agreements.

DPL’s primary source for posting cash collateral or letters of credit is PHI’s credit facility. At ~~March 31,~~June 30, 2012 and December 31, 2011, the aggregate amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries was ~~$452~~$586 million and $711 million, respectively.

DPL 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). DPL 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, DPL 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, DPL’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of ~~March 31,~~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. DPL’s 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.


	Fair Value Measurements at March 31, 2012								Fair Value Measurements at June 30, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	*(millions of dollars)*								*(millions of dollars)*
ASSETS
Cash equivalents
Treasury fund									$	22	$	22	$	—	$	—
Executive deferred compensation plan assets
Money market funds	$	2	$	2	$	—	$	—		2		2		—		—
Life insurance contracts		1		—		—		1		1		—		—		1

	$	3	$	2	$	—	$	1	$	25	$	24	$	—	$	1

LIABILITIES
Derivative instruments (b)
Natural gas (c)	$	14	$	2	$	—	$	12	$	10	$	—	$	—	$	10

	$	14	$	2	$	—	$	12	$	10	$	—	$	—	$	10

DPL 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:

Derivative instruments categorized as level 3 ~~include~~represent natural gas options used by DPL as part of a natural gas hedging program approved by the DPSC. DPL applies a Black-Scholes model to value its options ~~which contains~~with inputs, such as the forward price curves, contract prices, contract volumes, the risk-free rate and the implied volatility factors, ~~which~~that are based on a range of historical NYMEX option prices. ~~The implied volatility is a factor based on a range between 0.60 and 2.03.~~ DPL maintains valuation policies and procedures and reviews the validity and relevance of the inputs used to estimate the fair value of its options.

The table below summarizes the primary unobservable input used to determine the fair value of DPL’s level 3 instruments and the range of values that could be used for the input as of ~~March 31,~~June 30, 2012:

Type of Instrument

Fair Value at
March 31, 2012

Valuation Technique

Unobservable Input

Range

Fair Value at
June 30, 2012

Valuation Technique

Unobservable Input

Range

(millions of dollars)

Natural Gas Options

Option model

Volatility Factor

0.60 – 2.03

Natural gas options

(10

)

Option model

Volatility factor

0.69 – 2.78

DPL used values within this range as part of its fair value ~~estimates, and a~~estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of ~~March 31,~~June 30, 2012.

Reconciliations of the beginning and ending balances of DPL’s fair value measurements using significant unobservable inputs (level 3) for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are shown below:


	Three Months Ended March 31, 2012					Six Months Ended June 30, 2012
	Natural Gas			Life Insurance Contracts		Natural Gas			Life Insurance Contracts
	*(millions of dollars)*					*(millions of dollars)*
Beginning balance as of January 1	$	(15	)	$	1	$	(15	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—		—			—
Included in accumulated other comprehensive loss		—			—		—			—
Included in regulatory assets		(3	)		—		(3	)		—
Purchases		—			—		—			—
Issuances		—			—		—			—
Settlements		6			—		8			—
Transfers in (out) of level 3		—			—		—			—

Ending balance as of March 31	$	(12	)	$	1
Ending balance as of June 30						$	(10	)	$	1


	Three Months Ended March 31, 2011					Six Months Ended June 30, 2011
	Natural Gas			Life Insurance Contracts		Natural Gas			Life Insurance Contracts
	*(millions of dollars)*					*(millions of dollars)*
Beginning balance as of January 1	$	(23	)	$	1	$	(23	)	$	1
Total gains (losses) (realized and unrealized):
Included in income		—			—		—			—
Included in accumulated other comprehensive loss		—			—		—			—
Included in regulatory assets		(1	)		—		(2	)		—
Purchases		—			—		—			—
Issuances		—			—		—			—
Settlements		5			—		8			—
Transfers in (out) of level 3		—			—		—			—

Ending balance as of March 31	$	(19	)	$	1
Ending balance as of June 30						$	(17	)	$	1

The estimated fair values of DPL’s debt instruments that are measured at amortized cost in DPL’s financial statements and the associated level of the estimates within the fair value hierarchy as of ~~March 31,~~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. DPL’s 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 estimated fair ~~values~~value of DPL’s debt instruments at December 31, 2011 ~~are~~is shown below:

The carrying amounts of all other financial instruments in the accompanying financial statements approximate fair value.

DPL 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 DPL’s customers, environmental clean-up costs incurred by DPL generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of DPL described below at ~~March 31,~~June 30, 2012 are summarized as follows:


			Legacy Generation
	Transmission and Distribution		Regulated		Non-Regulated		Other		Total		Transmission and Distribution		Legacy Generation - Regulated			Other		Total
	*(millions of dollars)*										*(millions of dollars)*
Beginning balance as of January 1	$	1	$	4	$	—	$	2	$	7	$	1	$	4		$	2	$	7
Accruals		—		—		—		—		—		—		—			—		—
Payments		—		1		—		—		1		—		(1	)		—		(1	)

Ending balance as of March 31		1		3		—		2		6
Ending balance as of June 30												1		3			2		6
Less amounts in Other current liabilities		1		1		—		2		4		1		1			2		4

Amounts in Other deferred credits	$	—	$	2	$	—	$	—	$	2	$	—	$	2		$	—	$	2

In April 2009, a group of potentially responsible parties (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 DPL, 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 ~~next step in the~~ litigation ~~will be the~~is moving forward with certain “test case” defendants (not including DPL) filing of summary judgment motions regarding ~~liability for certain “test case” defendants, not including DPL.~~liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although DPL cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, DPL does not believe that it 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.

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including DPL. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to DPL for the three months ended ~~March 31,~~June 30, 2012 and 2011 were approximately $37 million and $31 million, respectively. PHI Service Company costs directly charged or allocated to DPL for the six months ended June 30, 2012 and 2011 were approximately $74 million and $62 million, respectively.

In addition to the PHI Service Company charges described above, DPL’s financial statements include the following related party transactions in its statements of income:


Income (Expenses)	Three Months Ended March 31,
Income					Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011		2012		2011
	*(millions of dollars)*				*(millions of dollars)*
Purchased power under Default Electricity Supply contracts with Conectiv Energy Supply, Inc. (a)	$	—	$	1	$	—	$	—	$	—	$	1
Intercompany lease transactions (b)		1		1		1		1		2		2

As of ~~March 31,~~June 30, 2012 and December 31, 2011, DPL had the following balances on its balance sheets due ~~(to) from~~to related parties:


Liability	March 31, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	*(millions of dollars)*						*(millions of dollars)*
Payable to Related Party (current) (a)
PHI Service Company	$	(17	)	$	(20	)	$	(21	)	$	(20	)
Conectiv Energy Supply, Inc.		—			(1	)		—			(1	)
Pepco Energy Services Inc. and its subsidiaries (Pepco Energy Services) (b)		(1	)		—

Total	$	(18	)	$	(21	)	$	(21	)	$	(21	)


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
Operating Revenue	$	256		$	315		$	270		$	304		$	526		$	619

Operating Expenses
Purchased energy		166			198			163			196			329			394
Other operation and maintenance		56			55			56			51			112			106
Depreciation and amortization		28			33			27			33			55			66
Other taxes		4			6			4			5			8			11
Deferred electric service costs		(15	)		(3	)		(20	)		(29	)		(35	)		(32	)

Total Operating Expenses		239			289			230			256			469			545

Operating Income		17			26			40			48			57			74

Other Income (Expenses)
Interest expense		(17	)		(15	)		(18	)		(18	)		(35	)		(33	)
Other income		1			—			1			2			2			2

Total Other Expenses		(16	)		(15	)		(17	)		(16	)		(33	)		(31	)

Income Before Income Tax Expense		1			11			23			32			24			43
Income Tax (Benefit) Expense		(1	)		5
Income Tax Expense								9			14			8			19

Net Income	$	2		$	6		$	14		$	18		$	16		$	24

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	March 31, 2012		December 31, 2011		June 30, 2012		December 31, 2011
	*(millions of dollars, except shares)*				*(millions of dollars, except shares)*
LIABILITIES AND EQUITY

CURRENT LIABILITIES
Short-term debt	$	23	$	23	$	97	$	23
Current portion of long-term debt		38		37		38		37
Accounts payable and accrued liabilities		122		117		129		117
Accounts payable due to associated companies		14		14		13		14
Taxes accrued		17		10		16		10
Interest accrued		21		15		15		15
Other		41		45		41		45

Total Current Liabilities		276		261		349		261

DEFERRED CREDITS
Regulatory liabilities		62		60		64		60
Deferred income taxes, net		768		698		760		698
Investment tax credits		7		7		7		7
Other postretirement benefit obligations		31		31		33		31
Derivative liabilities						9		—
Other		16		20		17		20

Total Deferred Credits		884		816		890		816

LONG-TERM LIABILITIES
Long-term debt		833		832		832		832
Transition Bonds issued by ACE Funding		285		295		276		295

Total Long-Term Liabilities		1,118		1,127		1,108		1,127

COMMITMENTS AND CONTINGENCIES (NOTE 11)
COMMITMENTS AND CONTINGENCIES (NOTE 12)

EQUITY
Common stock, $3.00 par value, 25,000,000 shares authorized, 8,546,017 shares outstanding		26		26		26		26
Premium on stock and other capital contributions		576		576		576		576
Retained earnings		202		200		201		200

Total Equity		804		802		803		802

TOTAL LIABILITIES AND EQUITY	$	3,082	$	3,006	$	3,150	$	3,006

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	Three Months Ended March 31,						Six Months Ended June 30,
	2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
OPERATING ACTIVITIES
Net income	$	2		$	6		$	16		$	24
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization		28			33			55			66
Deferred income taxes		72			9			64			30
Changes in:
Accounts receivable		17			16
Inventories		(1	)		—
Prepaid expenses								(43	)		(56	)
Regulatory assets and liabilities, net		(16	)		(3	)		(36	)		(34	)
Accounts payable and accrued liabilities		(8	)		(23	)		5			(5	)
Pension contributions		(30	)		(30	)		(30	)		(30	)
Taxes accrued		(63	)		12
Interest accrued		—			3
Income tax-related prepayments, receivables and payables								(47	)		13
Other assets and liabilities		10			10			(3	)		11

Net Cash From Operating Activities		11			33
Net Cash (Used By) From Operating Activities								(19	)		19

INVESTING ACTIVITIES
Investment in property, plant and equipment		(53	)		(22	)		(114	)		(60	)
Department of Energy capital reimbursement awards received		1			1			1			2
Net other investing activities		—			(3	)		2			(3	)

Net Cash Used By Investing Activities		(52	)		(24	)		(111	)		(61	)

FINANCING ACTIVITIES
Dividends paid to Parent								(15	)		—
Redemption of preferred stock		—			(6	)		—			(6	)
Issuances of long-term debt								—			200
Reacquisitions of long-term debt		(9	)		(9	)		(18	)		(17	)
Issuances of short-term debt, net		—			7
Issuances (repayments) of short-term debt, net								74			(133	)
Net other financing activities		8			(1	)		1			(2	)

Net Cash Used By Financing Activities		(1	)		(9	)
Net Cash From Financing Activities								42			42

Net Decrease in Cash and Cash Equivalents		(42	)		—			(88	)		—
Cash and Cash Equivalents at Beginning of Period		91			4			91			4

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	49		$	4		$	3		$	4

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash received for income taxes (includes payments from PHI for federal income taxes)	$	—		$	(6	)	$	—		$	(18	)

The accompanying Notes are an integral part of these Consolidated Financial Statements.


	Common Stock										Common Stock				Premium on Stock			Retained Earnings			Total
*(millions of dollars, except shares)*	Shares		Par Value		Premium on Stock		Retained Earnings		Total		Shares		Par Value					Retained Earnings			Total
BALANCE, DECEMBER 31, 2011		8,546,017	$	26	$	576	$	200	$	802		8,546,017	$	26	Premium on Stock	$	576		$	200		$	802
Net Income		—		—		—		2		2
Net income												—		—		—			2			2

BALANCE, MARCH 31, 2012		8,546,017	$	26	$	576	$	202	$	804		8,546,017		26		576			202			804
Net income												—		—		—			14			14
Dividends on common stock												—		—		—			(15	)		(15	)

BALANCE, JUNE 30, 2012												8,546,017	$	26	$	576		$	201		$	803

The accompanying Notes are an integral part of these Consolidated Financial Statements.

Atlantic City Electric Company (ACE) is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply, which is the supply of electricity at regulated rates to retail customers in its service territory who do not elect to purchase electricity from a competitive energy supplier. Default Electricity Supply is known as Basic Generation Service in New Jersey. ACE is a wholly owned subsidiary of Conectiv, LLC, which is wholly owned by Pepco Holdings, Inc. (Pepco Holdings or PHI).

ACE’s 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 ACE’s 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 ACE’s management, the consolidated financial statements contain all adjustments (which all are of a normal recurring nature) necessary to state fairly ACE’s financial condition as of ~~March 31,~~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 ~~March 31,~~June 30, 2012 may not be indicative of ACE’s results that will be realized for the full year ending December 31, 2012.

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 ACE 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 impairment evaluations, fair value calculations for derivative instruments, pension and other postretirement benefits 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, and income tax provisions and reserves. Additionally, ACE is subject to legal, regulatory and other proceedings and claims that arise in the ordinary course of its business. ACE 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.

On June 29, 2012, ACE was affected by a rapidly moving thunderstorm with hurricane-force winds, known as a “derecho,” which resulted in widespread customer outages in its service territory. The derecho caused extensive damage to ACE’s electric transmission and distribution systems. 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 ACE through June 30, 2012 were $0.9 million, with $0.5 million incurred for repair work and $0.4 million incurred as capital expenditures. All of the costs incurred for repair work of $0.5 million were deferred as regulatory assets to reflect the probable recovery of these storm restoration costs. 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 ACE associated with the derecho are currently estimated to range between $29 million and $35 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. The costs expensed will be deferred as regulatory assets to reflect the probable recovery of these storm restoration costs in New Jersey. ACE will be pursuing recovery of the incremental storm restoration costs in its next distribution base rate case.

During the second quarter of 2011, ACE reduced its self-insurance reserves for general and auto liability claims by approximately $1 million, based on obtaining an actuarial estimate of the unpaid losses attributed to general and auto liability claims for ACE at June 30, 2011.

ACE 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.

ACE 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. ACE 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, ACE applied the scope exemption from the consolidation guidance for enterprises that have not been able to obtain such information.

Atlantic City Electric Transition Funding LLC (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 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 ACE’s 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 consolidates ACE Funding in its financial statements as ACE is the primary beneficiary of ACE Funding under the variable interest entity consolidation guidance.

~~Currently, ACE believes that~~recorded an offsetting regulatory liability (asset) as described in more detail in Note (10), “Derivative Instruments and Hedging Activities”, and Note (11), “Fair Value Disclosures.” FASB guidance on derivative accounting and the accounting for regulated operations would apply to aACE’s obligations under the third SOCA once the related capacity has cleared a PJM auction. ~~Once cleared, the gain (loss) associated with the fair value of a derivative would be offset by the recognition of a regulatory liability (asset).~~ The next PJM capacity auction is scheduled for May ~~2012.~~2013. ACE has concluded that consolidation is not required for the SOCAs under the FASB guidance on the consolidation of variable interest entities.

Taxes included in ACE’s gross revenues were $4$3 million and $6$5 million for the three months ended ~~March 31,~~June 30, 2012 and 2011, respectively, and $7 million and $10 million for the six months ended June 30, 2012 and 2011, respectively.

Certain prior period amounts have been reclassified in order to conform to the current period presentation. The following adjustment has been recorded and is not considered material.

During the second quarter of 2011, ACE completed a reconciliation of its deferred taxes associated with certain regulatory assets and recorded adjustments that resulted in an increase to Income tax expense of $1 million for the three and six months ended June 30, 2011.

The FASB issued new guidance on fair value measurement and disclosures that was effective beginning with ACE’s March 31, 2012 consolidated financial statements. The new measurement guidance did not have a material impact on ACE’s consolidated financial statements and the new disclosure requirements are in Note ~~(10)~~(11), “Fair Value Disclosures,” of ACE’s consolidated financial statements.

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 ACE’s March 31, 2013 consolidated financial statements. ACE is evaluating the impact of this new guidance on its consolidated financial statements.

ACE operates its business as one regulated utility segment, which includes all of its services as described above.

Over the last several years, ACE has proposed the adoption of a mechanism to decouple retail distribution revenue from the amount of power delivered to retail customers. A bill stabilization adjustment ~~mechanism~~ (BSA) proposed by ACE ~~as part of a Phase 2 to the base rate proceeding filed~~ in ~~August~~ 2009 was not ~~included in the final settlement~~ approved ~~by the NJBPU on May 16, 2011. Accordingly,~~and there is no BSA proposal currently pending in New Jersey. Under the BSA, customer distribution rates ~~are~~would be 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.~~NJBPU.

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 ~~(increased~~(which was increased to approximately $80.2 million on February 24, 2012, to reflect the 2011 test year), based on a requested return on equity 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.

In July 2009, the NJBPU approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program (the IIP). In exchange for the increase in infrastructure investment, the NJBPU, through the IIP, allowed recovery by ACE of ~~ACE’s~~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 ACE’s 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 ACE’s IIP filing is expected by the end of ~~the third quarter of~~ 2012.

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.~~Agreements” and Note (10), “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.

ACE accounts for its participation in its parent’s single-employer plans, ~~the~~ Pepco ~~Holdings, Inc. Retirement Plan~~Holdings’ non-contributory retirement plan (the PHI Retirement Plan) and the Pepco Holdings, Inc. Welfare Plan for Retirees, as participation in multiemployer plans. PHI’s pension and other postretirement net periodic benefit cost for the three months ended ~~March 31,~~June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were ~~$26~~$30 million and ~~$27~~$19 million, respectively. ACE’s allocated share was $6 million and $6$4 million, respectively, for the three months ended ~~March 31,~~June 30, 2012 and 2011. PHI’s pension and other postretirement net periodic benefit cost for the six months ended June 30, 2012 and 2011, before intercompany allocations from the PHI Service Company, were $56 million and $46 million, respectively. ACE’s allocated share was $12 million and $10 million, respectively, for the six months ended June 30, 2012 and 2011.

In the first quarter of 2012, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan of $30 million. In the first quarter of 2011, ACE made a discretionary tax-deductible contribution to the PHI Retirement Plan in the amount of $30 million.

PHI, Potomac Electric Power Company (Pepco), Delmarva Power & Light Company (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 company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month ~~LIBOR~~London Interbank Offered Rate plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

At ~~March 31,~~June 30, 2012 and December 31, 2011, the amount of cash plus borrowing capacity under the credit facility available to meet the liquidity needs of PHI’s utility subsidiaries in the aggregate was ~~$452~~$586 million and $711 million, respectively. ACE’s borrowing capacity under the credit facility at any given time depends on the amount of the subsidiary borrowing capacity being utilized by Pepco and DPL and the portion of the total capacity being used by PHI.

ACE maintains an on-going commercial paper program to address its short-term liquidity needs. As of ~~March 31,~~June 30, 2012, the maximum capacity available under the program was $250 million, subject to available borrowing capacity under the credit facility.

ACE ~~did not issue commercial paper during the first quarter~~had $74 million of ~~2012 and had no~~ commercial paper outstanding at ~~March 31,~~June 30, 2012. The weighted average interest rate for commercial paper issued by ACE during the six months ended June 30, 2012 was 0.41% and the weighted average maturity of all commercial paper issued by ACE during the six months ended June 30, 2012 was two days.

In ~~January~~April 2012, ACE Funding made principal payments of $7$6 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.

In ~~April~~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.

A reconciliation of ACE’s consolidated effective income tax rate is as follows:

ACE’s consolidated effective tax rates for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~(100)%~~39.1% and ~~45.5%~~43.8%, respectively. During 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 have been on deposit with the IRS since 2006 among liabilities in the settlement years and subsequent years. Primarily related to the settlement and reallocations, ACE recorded an additional $1 million (after-tax) of interest due to the IRS in the second quarter of 2011. Also during the second quarter of 2011, ACE completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million increase to income tax expense as shown in the “Deferred Tax Adjustment” line above.

ACE’s consolidated effective tax rates for the six months ended June 30, 2012 and 2011 were 33.3% and 44.2%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions ~~in the first quarter of~~during 2012, primarily due to the effective settlement with the Internal Revenue Service with respect to the methodology used historically to calculate deductible mixed service costs.

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) ACE’s annual proportion of the total New Jersey load relative to the other EDCs in New Jersey, which is currently estimated to be 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 ACE’s distribution customers for all payments made by ACE and ACE’s distribution customers would be entitled to all payments received by ACE.

As of June 30, 2012, ACE had other non-current derivative assets of $8 million and non-current derivative liabilities of $9 million associated with the two SOCAs and an offsetting regulatory liability and asset, respectively, of the same amounts. As of June 30, 2012, ACE had 180 megawatts of capacity in a long position, with no collateral or netting applicable to the capacity. Unrealized gains and losses associated with these capacity derivatives, which netted to an unrealized loss of $1 million for the three and six months ended June 30, 2012, have been deferred as regulatory liabilities and assets, respectively, as of June 30, 2012.

ACE 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). ACE 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, ACE 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, ACE’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of ~~March 31,~~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. ACE’s 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.


	Fair Value Measurements at March 31, 2012								Fair Value Measurements at June 30, 2012
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	*(millions of dollars)*								*(millions of dollars)*
ASSETS
Derivative instruments (b)
Capacity (c)									$	8	$	—	$	—	$	8
Cash equivalents
Treasury fund	$	70	$	70	$	—	$	—		24		24		—		—

	$	70	$	70	$	—	$	—	$	32	$	24	$	—	$	8

LIABILITIES
Derivative instruments (b)
Capacity (c)									$	9	$	—	$	—	$	9
Executive deferred compensation plan liabilities
Life insurance contracts	$	1	$	—	$	1	$	—		1		—		1		—

	$	1	$	—	$	1	$	—	$	10	$	—	$	1	$	9

ACE 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:

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.

Derivative instruments categorized as level 3 represent capacity under the SOCAs entered into by ACE.

The table below summarizes the primary unobservable input used to determine the fair value of ACE’s level 3 instruments and the range of values that could be used for the input as of June 30, 2012:

ACE used a value within this range as part of its fair value estimates. A significant change in the unobservable input within this range would have an insignificant impact on the reported fair value as of June 30, 2012.

A reconciliation of the beginning and ending balances of ACE’s fair value measurements using significant unobservable inputs (level 3) for the six months ended June 30, 2012 is shown below:

The estimated fair values of ACE’s debt instruments that are measured at amortized cost in ACE’s consolidated financial statements and the associated level of the estimates within the fair value hierarchy as of ~~March 31,~~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. ACE’s 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 categorized as level 3 ~~was~~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 estimated fair values of ACE’s 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.

recovery of an unspecified amount of damages, ~~for,~~ among other things, for the decedent’s 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.

ACE 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 ACE’s customers, environmental clean-up costs incurred by ACE generally are included in its cost of service for ratemaking purposes. The total accrued liabilities for the environmental contingencies of ACE described below at ~~March 31,~~June 30, 2012 are summarized as follows:


			Legacy Generation
	Transmission and Distribution		Regulated		Non-Regulated		Other		Total		Legacy Generation - Regulated		Total
	*(millions of dollars)*										*(millions of dollars)*
Beginning balance as of January 1	$	—	$	1	$	—	$	—	$	1	$	1	$	1
Accruals		—		—		—		—		—		—		—
Payments		—		—		—		—		—		—		—

Ending balance as of March 31		—		1		—		—		1
Less amounts in Other current liabilities		—		—		—		—		—
Ending balance as of June 30												1		1
Less amounts in Other current												—		—

Amounts in Other deferred credits	$	—	$	1	$	—	$	—	$	1	$	1	$	1

In November 2008, ACE received a general notice letter from the U.S. Environmental Protection Agency (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. EPA’s claims are based on ACE’s 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, EPA’s 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.

decision supports ACE’s 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.

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, 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 ~~next step in the~~ litigation ~~will be the~~is moving forward with certain “test case” defendants (not including ACE) filing of summary judgment motions regarding ~~liability for certain “test case” defendants, not including ACE.~~liability. The case has been stayed as to the remaining defendants pending rulings upon the test cases. Although ACE cannot at this time estimate an amount or range of reasonably possible losses to which it may be exposed, ACE does not believe that it 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.

PHI Service Company provides various administrative and professional services to PHI and its regulated and unregulated subsidiaries, including ACE. The cost of these services is allocated in accordance with cost allocation methodologies set forth in the service agreement using a variety of factors, including the subsidiaries’ share of employees, operating expenses, assets and other cost methods. These intercompany transactions are eliminated by PHI in consolidation and no profit results from these transactions at PHI. PHI Service Company costs directly charged or allocated to ACE for the three months ended ~~March 31,~~June 30, 2012 and 2011 were approximately $28 million and $24 million, respectively. PHI Service Company costs directly charged or allocated to ACE for the six months ended June 30, 2012 and 2011 were approximately $56 million and $48 million, respectively.

In addition to the PHI Service Company charges described above, ACE’s consolidated financial statements include the following related party transactions in the consolidated statements of income:


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
Income (Expenses)	2012			2011
Expenses							2012			2011			2012			2011
	*(millions of dollars)*						*(millions of dollars)*
Meter reading services provided by Millennium Account Services LLC (an ACE affiliate) (a)	$	(1	)	$	(1	)	$	(1	)	$	(1	)	$	(2	)	$	(2	)

As of ~~March 31,~~June 30, 2012 and December 31, 2011, ACE had the following balances on its consolidated balance sheets due to related parties:


Liability	March 31, 2012			December 31, 2011			June 30, 2012			December 31, 2011
	*(millions of dollars)*						*(millions of dollars)*
Payable to Related Party (current) (a)
PHI Service Company	$	(12	)	$	(12	)	$	(12	)	$	(12	)
Other		(2	)		(2	)		(1	)		(2	)

Total	$	(14	)	$	(14	)	$	(13	)	$	(14	)

~~Item 2~~.

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

Item 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pepco Holdings, a Delaware corporation incorporated in 2001, is a holding company that, through its regulated public utility subsidiaries, is engaged primarily in the transmission, distribution and default supply of electricity and the distribution and supply of natural gas (Power Delivery). Through Pepco Energy Services, Inc. and its subsidiaries (collectively, Pepco Energy Services), PHI provides energy ~~efficiency~~savings performance contracting services, primarily to ~~government~~commercial, industrial and ~~institutional~~government customers and is in the process of winding down its competitive electricity and natural gas retail supply business. Each of Power Delivery and Pepco Energy Services constitutes a separate segment for financial reporting purposes. A third segment, Other Non-Regulated, ~~owns~~consists of a portfolio of cross-border energy lease investments.

The following table sets forth the percentage contributions to consolidated operating revenue and consolidated operating income from continuing operations attributable to the Power Delivery, Pepco Energy Services and Other Non-Regulated segments.


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011			2012			2011
Percentage of Consolidated Operating Revenue
Power Delivery		82	%		76	%		83	%		77	%		83	%		77	%
Pepco Energy Services		18	%		23	%		16	%		22	%		17	%		22	%
Other Non-Regulated		—			1	%		1	%		1	%		—			1	%
Percentage of Consolidated Operating Income
Power Delivery		73	%		79	%		82	%		67	%		77	%		72	%
Pepco Energy Services		12	%		11	%		9	%		6	%		11	%		8	%
Other Non-Regulated		15	%		10	%		9	%		27	%		12	%		20	%
Percentage of Power Delivery Operating Revenue
Power Delivery Electric		93	%		92	%		98	%		96	%		95	%		94	%
Power Delivery Gas		7	%		8	%		2	%		4	%		5	%		6	%

Power Delivery Electric consists primarily of the transmission, distribution and default supply of electricity, and Power Delivery Gas consists of the delivery and supply of natural gas. Power Delivery represents a single operating segment for financial reporting purposes.

Each utility comprising Power Delivery is a regulated public utility in the jurisdictions that ~~encompass~~comprise its 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 commission in each jurisdiction. 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 (SOS) in Delaware, the District of Columbia and Maryland, and Basic Generation Service (BGS) in New Jersey. In this quarterly report, these supply service obligations are referred to generally as Default Electricity Supply.

Each of Pepco, DPL and ACE ~~each~~ is responsible for the transmission of wholesale electricity into and across its service ~~territory.~~territory, and in the case of DPL, natural gas. The rates each utility is permitted to charge for the wholesale transmission of electricity are regulated by the Federal Energy Regulatory Commission (FERC). Transmission rates are updated annually based on a FERC-approved formula methodology.

The profitability of Power Delivery depends on its ability to recover costs and earn a reasonable return on its capital investments through the rates it is permitted to charge. Operating results also can be affected by economic conditions, energy prices, the impact of energy efficiency measures on customer usage of electricity, and in some jurisdictions, weather.

Power Delivery’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco and DPL in Maryland and of Pepco in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer rather than a charge based upon energy usage. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from retail customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware has been approved in concept by the Delaware Public Service Commission (DPSC) and is pending development of an implementation plan and a customer education plan.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from retail distribution sales falls short of the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco and DPL are entitled to earn based on the approved distribution charge per customer.

On July 20, 2012, the Maryland Public Service Commission (MPSC) issued orders in response to Pepco’s and DPL’s applications with the MPSC seeking to increase their electric distribution base rates. See Note (7), “Regulatory Matters – Rate Proceedings” to the consolidated financial statements of PHI included herein and “Regulatory Lag” in this section below for a discussion of these rate cases. Pepco and DPL are ~~developments~~currently reviewing the orders to determine what further actions, if any, they may seek to pursue.

As a result of these base rate cases, each of Pepco and DPL are rigorously reviewing their operating expenses and will take actions to reduce such expenses where necessary or appropriate. In this regard, a PHI-wide hiring freeze implemented in ~~some~~the second quarter of 2012 will be extended for the ~~key initiatives~~foreseeable future. Decisions by the MPSC in future rate cases which do not permit Pepco and DPL to recover their prudently incurred expenses on a timely basis could negatively impact their ability to earn reasonable rates of ~~Power Delivery as~~return on their investments in Maryland. Further, Pepco and DPL believe that their ability to maintain the current level of ~~March 31, 2012:~~their reliability-related investments requires adequate recovery of expenditures for such investments in future base rate cases.

In 2010, PHI announced that Pepco had adopted and begun to implement comprehensive reliability enhancement plans in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

In 2011, ~~prior to the start of the summer storm season,~~ PHI also initiated a program to improve Pepco’s emergency restoration efforts that included, among other initiatives, an expansion and enhancement of customer service capabilities. PHI has extended its reliability enhancement efforts to DPL and ACE.

In 2012, PHI has continued to focus on its reliability enhancement and emergency restoration improvement plans in all of its service territories.

Each of PHI’s three utilities is participating in a PHI initiative referred to as “Blueprint for the Future.” The installation of smart meters (also known as advanced metering infrastructure (AMI)), is a key initiative of Blueprint for the ~~Future, is almost~~Future. As of June 30, 2012, installation and activation of smart meters was complete for DPL electric customers in ~~Delaware, with meter activation expected to be completed in 2012.~~Delaware. Meter installation ~~is still underway~~remains in progress for Pepco customers in

both the District of Columbia and Maryland, with installation of residential meters expected to be complete in the ~~second~~third and fourth quarters of 2012, respectively. The respective public service commissions have approved the creation of regulatory assets to defer AMI costs between rate cases, as well as the accrual of a return on the deferred costs. Thus, these costs will be recovered through base rates in the future. In addition to the replacement of existing meters, the AMI system involves the construction of a wireless network across the service territories of PHI’s utility subsidiaries and the implementation and integration of new and existing information technology systems to collect and manage data made available by the advanced meters. The implementation of the AMI system involves a combination of technologies provided by multiple vendors.

On May 8, 2012, the MPSC issued an order permitting DPL to proceed with its deployment of an AMI system in Maryland and establish a regulatory asset for AMI system incremental costs. DPL intends to implement a customer education and communications plan in advance of its Maryland AMI deployment. Approval of AMI ~~is still pending for electric customers in DPL’s Maryland jurisdiction, and such approval~~ has been deferred for ACE in New Jersey.

In 2011, the DPSC approved DPL’s request to implement dynamic pricing for its Delaware customers. Dynamic pricing will reward SOS customers with lower rates for decreasing their energy use during those times when energy demand and, consequently, the cost of supplying electricity, are higher. Implementation for customers will be phased in between 2012 and 2014. For DPL’s Maryland customers, dynamic pricing has been approved in concept, ~~pending~~with implementation to begin once AMI ~~deployment authorization.~~has been installed. In Pepco’s Maryland service territory, dynamic pricing has been approved in concept, with phase-in for residential customers beginning in 2012. In Pepco’s District of Columbia jurisdiction, proposals are pending with proposed phase-in for residential customers anticipated to begin in 2012. Dynamic pricing has been deferred for ACE’s customers in New Jersey.

An important factor in the ability of each of Pepco, DPL and ACE to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in the utility’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Each of Pepco, DPL and ACE is currently experiencing significant regulatory lag because their investment in the rate base and their operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s and DPL’s most recent Maryland base rate case filings included a request for MPSC approval of (i) a reliability investment recovery mechanism (RIM) to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by Pepco and DPL of fully forecasted test years in future base rate cases. See Note (7), “Regulatory Matters – Rate Proceedings” to the consolidated financial statements of PHI for a discussion of each of these mechanisms. In both the Pepco and DPL base rate case orders, the MPSC did not approve Pepco’s and DPL’s requests to implement the RIM and did not endorse the use by Pepco and DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of Pepco and DPL to reflect the actual cost of reliability plant additions outside the test year.

Each of PHI’s utility subsidiaries ~~is continuing~~will continue to seek cost recovery and tracking mechanisms from applicable public service commissions to reduce the effects of regulatory lag. For example, Pepco, DPL and ACE have proposed regulatory lag mitigation mechanisms which remain pending in various regulatory proceedings. See Note (7), “Regulatory Matters” to the consolidated financial statements of PHI included herein. There can be no assurance that these proposals or any other attempts by PHI’s utility subsidiaries to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or ~~any~~ base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms or any alternative mechanisms are approved, PHI’s utility subsidiaries plan to file rate cases at least annually in an effort to align more closely ~~PHI’s utility subsidiaries~~the revenue and related cash flow levels of PHI’s utility subsidiaries with other operation and maintenance spending and capital investments. In ~~future~~light of the MPSC’s decisions in the most recent Pepco and DPL base rate cases, each of Pepco and DPL intends to file its next electric distribution base rate case with the MPSC in the fourth quarter of 2012.

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. 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 costs in Maryland and New Jersey. PHI’s utility subsidiaries ~~would also continue to seek cost~~will be pursuing recovery ~~and tracking mechanisms from applicable regulatory commissions to reduce~~of the ~~effects~~incremental storm restoration costs in their respective jurisdictions during the next cycle of ~~regulatory lag.~~distribution base rate cases.

Pepco Energy Services has been focused since 2010 on growing its energy efficiency services business in the federal, state and local government sectors. Market activity in the state and local government markets, which are Pepco Energy Services’ largest market segments, has slowed in 2012, driven by, among other factors, lower energy prices that have lessened the economic benefits of energy efficiency projects and the reluctance of state and local governments to incur new debt associated with energy efficiency projects. Given the slowdown in the state and local government markets, Pepco Energy Services believes that new business in this sector will remain challenged in the near-term and, consequently, Pepco Energy Services is slowing resource growth and geographic expansion in the energy efficiency services business, while focusing its existing resources on developing business in the federal government sector and continuing to pursue combined heat and power projects.

Most of Pepco Energy Services’ contracts with federal, state and local governments, as well as independent agencies such as housing and water authorities, contain provisions authorizing the governmental authority or independent agency to terminate the contract at any time. Those provisions include explicit mechanisms that, if exercised, would require the other party to pay Pepco Energy Services for work performed through the date of termination and for additional costs incurred as a result of the termination. In addition, Pepco Energy Services provides energy services guarantees in connection with its energy services performance contracts.

From time to time, PHI is required to guarantee the obligations of Pepco Energy Services under certain of its ~~construction contracts. In addition, Pepco Energy Services provides~~ energy ~~services guarantees in connection with its energy services performance~~efficiency and combined heat and power contracts. At ~~March 31,~~June 30, 2012, PHI’s guarantees of Pepco Energy Services’ ~~projects~~obligations under these contracts totaled ~~$143~~$147 million. See Note (15), “Commitments and Contingencies – Energy Savings Performance and Construction Contracts,” to the consolidated financial statements of PHI.

Pepco Energy Services also has historically been engaged in the business of providing retail energy supply services, consisting of the sale of electricity, including electricity from renewable resources, primarily to commercial, industrial and government customers located primarily in the mid-Atlantic and northeastern regions of the United States, as well as Texas and Illinois, and the sale of natural gas to customers located primarily in the mid-Atlantic region. In December 2009, PHI announced that it will wind down the retail energy supply component of the Pepco Energy Services business.

Pepco Energy Services’ retail natural gas sales volumes and revenues are seasonally dependent. Colder weather from November through March of each year generally translates into increased sales volumes, which, when coupled with higher natural gas prices during these months, allows Pepco Energy Services to recognize generally higher revenues as compared to other months of the year. Retail electricity sales volumes are also seasonally dependent, with sales in the summer and winter months being generally higher than other months of the year, which, when coupled with higher electricity prices during these periods, allows Pepco Energy Services to recognize generally higher revenues as compared to other periods during the year. However, as Pepco Energy Services is in the process of winding down its retail energy supply business, this effect of seasonality will likely decrease as such wind-down is completed. The energy services business is not seasonal.

To effectuate the wind-down, Pepco Energy Services is continuing to fulfill all of its commercial and regulatory obligations and perform its customer service functions to ensure that it meets the needs of its existing customers, but is not entering into any new retail energy supply contracts. Operating revenues related to the retail energy supply business for the three months ended ~~March 31,~~June 30, 2012 and 2011 were ~~$160~~$112 million and ~~$305~~$233 million, respectively, and operating income for the same periods was ~~$15~~$16 million and ~~$12~~$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, and operating income for the same periods was $31 million and $16 million, respectively.

PHI expects the operating results of the retail energy supply business, excluding the effects of unrealized mark-to-market gains or losses on derivatives contracts, to be profitable in 2012, based on its existing retail contracts and its corresponding portfolio of wholesale hedges, with immaterial losses beyond that date. Substantially all of Pepco Energy Services’ retail customer obligations will be fully performed by June 1, 2014.

In connection with the operation of the retail energy supply business, as of ~~March 31,~~June 30, 2012 and December 31, 2011, Pepco Energy Services had collateral pledged to counterparties primarily for the instruments it uses to hedge commodity price risk of approximately ~~$93~~$62 million and $113 million, respectively. The collateral pledged as of ~~March 31,~~June 30, 2012 included less than $1 million in the form of letters of credit and ~~$92~~$61 million posted in cash. Pepco Energy Services ~~estimates that at current market prices, with the wind-down of the retail energy supply business, an aggregate of 80% of the~~does not expect to have any such collateral ~~will no longer need to be pledged by December 31, 2012, and all collateral will no longer need to be pledged by~~obligations beyond June 1, 2014.

Pepco Energy Services’ remaining businesses will not be affected by the wind-down of the retail energy supply business.

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.

Through its subsidiary Potomac Capital Investment Corporation and its subsidiaries, PHI maintains a portfolio of cross-border energy lease investments with a book value at ~~March 31,~~June 30, 2012 of approximately $1.4 billion. This activity constitutes a third operating segment, which is designated as “Other Non-Regulated,” for financial reporting purposes. For a discussion of PHI’s cross-border energy lease investments, see Note (8), “Leasing Activities – Investment in Finance Leases Held in Trust,” and Note (15), “Commitments and Contingencies – PHI’s Cross-Border Energy Lease Investments,” to the consolidated financial statements of PHI.

OnIn April ~~20,~~ 2010, the Board of Directors ~~of PHI~~ approved a plan for the disposition of PHI’s 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 Energy’s wholesale power generation business to Calpine Corporation (Calpine) for $1.64 billion.

The disposition of all of Conectiv Energy’s remaining assets and businesses not included in the Calpine sale, including its load service supply contracts, energy hedging portfolio and certain tolling agreements, ~~has been completed.~~is complete. The former operations of Conectiv Energy, which previously comprised a separate segment for financial reporting purposes, have been classified as a discontinued operation in PHI’s consolidated financial statements, and the business is no longer treated as a separate segment for financial reporting purposes. Accordingly, in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, all references to continuing operations exclude the operations of the former Conectiv Energy segment.

Three Months Ended ~~March 31,~~June 30, 2012 Compared to Three Months Ended ~~March 31,~~June 30, 2011

Net income from continuing operations for the three months ended ~~March 31,~~June 30, 2012 was ~~$68~~$62 million, or ~~$0.30~~$0.27 per share, compared to ~~$62~~$95 million, or ~~$0.27~~$0.42 per share, for the three months ended ~~March 31,~~June 30, 2011.

Net ~~income~~loss from discontinued operations for the three months ended ~~March 31,~~June 30, 2011 was $2$1 million, or ~~$0.01~~less than one cent per share.

Net income for the three months ended ~~March 31,~~June 30, 2012 and 2011, by operating segment, is set forth in the table below (in millions of dollars):


	2012		2011			Change			2012			2011			Change
Power Delivery	$	47	$	47		$	—		$	54		$	72		$	(18	)
Pepco Energy Services		10		10			—			8			8			—
Other Non-Regulated		10		6			4			7			19			(12	)
Corporate and Other		1		(1	)		2			(7	)		(4	)		(3	)

Net Income from Continuing Operations		68		62			6			62			95			(33	)
Discontinued Operations		—		2			(2	)		—			(1	)		1

Total PHI Net Income	$	68	$	64		$	4		$	62		$	94		$	(32	)

Power Delivery’s $18 million decrease in earnings ~~were unchanged~~was primarily due to the following:

Pepco Energy Services’ earnings were unchanged primarily due to the on-going wind-down of the retail energy supply business and lower Energy Services project activity, offset by higher mark-to-market losses on derivative contracts in 2011.

Other Non-Regulated’s $12 million decrease in earnings was primarily due to favorable income tax adjustments related to uncertain and effectively settled income tax positions in 2011 and the gain on the early termination of certain cross-border energy leases in 2011.

Corporate and Other’s $3 million increase in net loss was primarily due to unfavorable 2012 income tax adjustments related to the New Jersey Corporation Business Tax audit for tax years 2004 through 2009.

Net income from continuing operations for the six months ended June 30, 2012 was $130 million, or $0.57 per share, compared to $157 million, or $0.69 per share, for the six months ended June 30, 2011.

Net income from discontinued operations for the six months ended June 30, 2011 was $1 million, or $0.01 per share.

Net income for the six months ended June 30, 2012 and 2011, by operating segment, is set forth in the table below (in millions of dollars):

Power Delivery’s $18 million decrease in earnings is primarily due to the following:

Pepco Energy Services’ earnings were unchanged primarily due to the on-going wind-down of the retail energy supply business and lower Energy Services project activity, ~~which were~~ offset by higher mark-to-market losses on derivative contracts in 2011.

Other Non-Regulated’s $4$8 million ~~increase~~decrease in earnings was primarily due to favorable income tax adjustments ~~in 2012~~ related to uncertain and effectively settled income tax ~~positions.~~positions in 2011 and the gain on the early termination of certain cross-border energy leases in 2011.

Corporate and Other’s $2$1 million increase in ~~earnings was~~net loss is primarily due ~~lower postemployment~~to unfavorable income tax adjustments in 2012 related to the New Jersey Corporation Business Tax audit for tax years 2004 through 2009, partially offset by pension and other postretirement benefits ~~expenses.~~actuarial true-up adjustments.

Net income from discontinued operations of $2$1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2011 was primarily related to adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine. These adjustments were made to reflect the actual amounts paid to Calpine during the first quarter of 2011.

Net income from discontinued operations also includes an after-tax gain of $1 million arising from the sale of a tolling agreement in May 2011.

The following results of operations discussion compares the three months ended ~~March 31,~~June 30, 2012, to the three months ended ~~March 31,~~June 30, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.

A detail of the components of PHI’s consolidated operating revenue is as follows:


	2012			2011			Change			2012			2011			Change
Power Delivery	$	1,055		$	1,249		$	(194	)	$	984		$	1,093		$	(109	)
Pepco Energy Services		228			373			(145	)		185			311			(126	)
Other Non-Regulated		13			14			(1	)		14			14			—
Corporate and Other		(4	)		(2	)		(2	)		(4	)		(6	)		2

Total Operating Revenue	$	1,292		$	1,634		$	(342	)	$	1,179		$	1,412		$	(233	)

The following table categorizes Power Delivery’s operating revenue by type of revenue.


	2012		2011		Change			2012		2011		Change
Regulated T&D Electric Revenue	$	452	$	452	$	—		$	472	$	455	$	17
Default Electricity Supply Revenue		512		679		(167	)		474		582		(108	)
Other Electric Revenue		17		16		1			14		17		(3	)

Total Electric Operating Revenue		981		1,147		(166	)		960		1,054		(94	)

Regulated Gas Revenue		65		91		(26	)		19		26		(7	)
Other Gas Revenue		9		11		(2	)		5		13		(8	)

Total Gas Operating Revenue		74		102		(28	)		24		39		(15	)

Total Power Delivery Operating Revenue	$	1,055	$	1,249	$	(194	)	$	984	$	1,093	$	(109	)

Regulated Transmission and Distribution (T&D) Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, by PHI’s utility subsidiaries to customers within their service territories at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that PHI’s utility subsidiaries receive as transmission owners from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Default Electricity Supply Revenue is the revenue received from the supply of electricity by PHI’s utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive energy supplier. The costs related to Default Electricity Supply are included in Fuel and Purchased Energy. Default Electricity Supply Revenue also includes revenue from non-bypassable transition bond charges (Transition Bond Charges) that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits that PHI utility subsidiaries receive as transmission owners from PJM for approved regional transmission expansion plan costs.

Other Electric Revenue includes work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services include mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates.

Other Gas Revenue consists of DPL’s off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Revenue*
Residential	$	162	$	168	$	(6	)	$	154	$	154	$	—
Commercial and industrial		201		202		(1	)		230		223		7
Transmission and other		89		82		7			88		78		10

Total Regulated T&D Electric Revenue	$	452	$	452	$	—		$	472	$	455	$	17


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Sales (Gigawatt hours (GWh))*
Residential		4,195		4,775		(580	)		3,571		3,855		(284	)
Commercial and industrial		7,081		7,305		(224	)		7,807		7,913		(106	)
Transmission and other		68		68		—			57		55		2

Total Regulated T&D Electric Sales		11,344		12,148		(804	)		11,435		11,823		(388	)


	2012		2011		Change		2012		2011		Change
*Regulated T&D Electric Customers (in thousands)*
Residential		1,640		1,638		2		1,638		1,635		3
Commercial and industrial		198		198		—		199		198		1
Transmission and other		2		2		—		2		2		—

Total Regulated T&D Electric Customers		1,840		1,838		2		1,839		1,835		4

The Pepco, DPL and ACE service territories are located within a corridor extending from the District of Columbia to southern New Jersey. These service territories are economically diverse and include key industries that contribute to the regional economic base, as follows:

Regulated T&D Electric Revenue ~~was unchanged~~increased by $17 million primarily due to:


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Revenue*
Residential	$	358	$	469	$	(111	)	$	314	$	376	$	(62	)
Commercial and industrial		130		168		(38	)		135		165		(30	)
Other		24		42		(18	)		25		41		(16	)

Total Default Electricity Supply Revenue	$	512	$	679	$	(167	)	$	474	$	582	$	(108	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM regional transmission organization (PJM RTO) market of energy and capacity purchased under contracts with unaffiliated non-utility generators (NUGs), and (ii) revenue from transmission enhancement credits.


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Sales (GWh)*
Residential		3,578		4,298		(720	)		2,982		3,401		(419	)
Commercial and industrial		1,393		1,558		(165	)		1,402		1,495		(93	)
Other		15		19		(4	)		14		18		(4	)

Total Default Electricity Supply Sales		4,986		5,875		(889	)		4,398		4,914		(516	)


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Customers (in thousands)*
Residential		1,426		1,495		(69	)		1,399		1,475		(76	)
Commercial and industrial		135		144		(9	)		133		141		(8	)
Other		—		1		(1	)		—		1		(1	)

Total Default Electricity Supply Customers		1,561		1,640		(79	)		1,532		1,617		(85	)

Default Electricity Supply Revenue decreased by ~~$167~~$108 million primarily due to:

Total Default Electricity Supply Revenue for the three months ended ~~March 31,~~June 30, 2012 includes ~~a decrease~~an increase of $2$3 million in unbilled revenue attributable to ACE’s BGS ($12 million ~~decrease~~increase in net income), primarily due to ~~lower~~higher non-weather related average customer usage and higher Default Electricity Supply rates during the unbilled revenue period at ~~March 31,~~June 30, 2012 as compared to the corresponding period in 2011. Under the BGS terms approved by the New Jersey Board of Public Utilities (NJBPU), ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers, and therefore has an impact on the results of operations in the period during which it is accrued.


	2012		2011		Change			2012		2011		Change
*Regulated Gas Revenue*
Residential	$	43	$	57	$	(14	)	$	10	$	16	$	(6	)
Commercial and industrial		19		31		(12	)		7		8		(1	)
Transportation and other		3		3		—			2		2		—

Total Regulated Gas Revenue	$	65	$	91	$	(26	)	$	19	$	26	$	(7	)


	2012		2011		Change			2012		2011		Change
*Regulated Gas Sales (billion cubic feet)*
Residential		3		4		(1	)		1		1		—
Commercial and industrial		2		2		—			—		1		(1	)
Transportation and other		2		3		(1	)		1		1		—

Total Regulated Gas Sales		7		9		(2	)		2		3		(1	)


	2012		2011		Change		2012		2011		Change
*Regulated Gas Customers (in thousands)*
Residential		114		114		—		114		114		—
Commercial and industrial		10		10		—		9		9		—
Transportation and other		—		—		—		—		—		—

Total Regulated Gas Customers		124		124		—		123		123		—

DPL’s natural gas service territory is located in New Castle County, Delaware. Several key industries contribute to the economic base as well as to growth, as follows:

~~The aggregate amount of these decreases was partially offset by an increase of $2 million due to a distribution rate increase effective July 2011.~~

Other Gas Revenue decreased by $2$8 million primarily due to lower average prices, ~~partially offset by higher~~and lower volumes, offor off-system sales to electric generators and gas marketers.

Pepco Energy Services’ operating revenue decreased by ~~$145~~$126 million primarily due to:

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:


	2012			2011		Change			2012		2011			Change
Power Delivery	$	543		$	706	$	(163	)	$	458	$	584		$	(126	)
Pepco Energy Services		187			331		(144	)		144		272			(128	)
Corporate and Other		(1	)		1		(2	)		2		(1	)		3

Total	$	729		$	1,038	$	(309	)	$	604	$	855		$	(251	)

Power Delivery’s Fuel and Purchased Energy consists of the cost of electricity and natural gas purchased by its utility subsidiaries to fulfill their respective Default Electricity Supply and Regulated Gas obligations and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of natural gas purchased for off-system sales. Fuel and Purchased Energy expense decreased by ~~$163~~$126 million primarily due to:

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased ~~$144~~$128 million primarily due to lower volumes of electricity and gas purchased to serve decreased retail supply sales volume as a result of the ongoing ~~wind down~~wind-down of the retail energy supply business.


	2012			2011			Change			2012			2011			Change
Power Delivery	$	224		$	222		$	2		$	219		$	197		$	22
Pepco Energy Services		18			21			(3	)		19			21			(2	)
Other Non-Regulated											2			—			2
Corporate and Other		(17	)		(9	)		(8	)		(16	)		(9	)		(7	)

Total	$	225		$	234		$	(9	)	$	224		$	209		$	15

Other Operation and Maintenance expense for Power Delivery increased by $2$22 million primarily due to:

In the third quarter of 2012, as a result of the MPSC’s order in Pepco’s most recent electric distribution base rate case, $8.8 million of incremental storm restoration costs incurred by Pepco in ~~January 2011.~~the first quarter of 2011 and previously expensed through Other Operation and Maintenance expense in 2011 will be reversed and deferred as a regulatory asset. This regulatory asset is to be recovered in electric distribution rates over five years.

Depreciation and Amortization expenses increased by $5$6 million to ~~$110~~$111 million in 2012 from $105 million in 2011 primarily due to:

The aggregate amount of these increases was partially offset by a decrease of $6$5 million in amortization of stranded costs as the result of lower revenue due to rate decreases effective October 2011 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

The MPSC reduced the depreciationrates for Pepco and DPL in the most recent electric distribution base rate cases for Pepco and DPL, which is expected to result in lower annual Depreciation and Amortization expense of approximately $31.4 million beginning on July 20, 2012.

Other Taxes decreased by $7$4 million to ~~$104~~$105 million in 2012 from ~~$111~~$109 million in 2011. The decrease was primarily due to lower sales that resulted in a decrease in utility taxes ~~primarily the result of lower sales,~~ that are collected and passed through by Power Delivery (substantially offset by a corresponding ~~increase~~decrease in Regulated T&D Electric Revenue).

PHI’s operating expenses include a $39 million pre-tax gain for the three months ended June 30, 2011 associated with the early termination of several leases included in its cross-border energy lease portfolio.

Deferred Electric Service Costs, which relate only to ACE, represent (i) the ~~over-~~over or ~~under-recovery~~under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the ~~over-~~over or ~~under-recovery~~under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance expense and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs increased by $9 million, to an expense reduction of $20 million in 2012 as compared to an expense reduction of $29 million in 2011, primarily as a result of higher Default Electricity Supply revenue rates, partially offset by higher electricity supply costs.

PHI’s operating expenses include impairment losses of $3 million for the three months ended June 30, 2012, associated primarily with its investment in a landfill gas-fired electric generation facility owned and operated by Pepco Energy Services. During the second quarter, Pepco Energy Services performed a long-lived asset impairment test on the facility as a result of a sustained decline in energy prices, and the facility was written down to its estimated fair value because the future expected cash flows of the facility were not sufficient to provide recovery of the facility’s carrying value.

PHI’s income tax expense decreased by $19 million to $35 million in 2012 from $54 million in 2011. PHI’s 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.

In the second quarter of 2011, PHI reached a settlement with the 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.

The following results of operations discussion compares the six months ended June 30, 2012, to the six months ended June 30, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.

A detail of the components of PHI’s consolidated operating revenue is as follows:

The following table categorizes Power Delivery’s operating revenue by type of revenue.

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale by ACE in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.

Other Gas Revenue decreased by $10 million primarily due to lower average prices and lower volumes for off-system sales to electric generators and gas marketers.

Pepco Energy Services’ operating revenue decreased by $275 million primarily due to:

A detail of PHI’s consolidated Fuel and Purchased Energy and Other Services Cost of Sales is as follows:

Pepco Energy Services’ Fuel and Purchased Energy and Other Services Cost of Sales decreased $276 million primarily due to lower volumes of electricity and gas purchased to serve decreased retail supply sales volume as a result of the ongoing wind-down of the retail energy supply business.

Other Operation and Maintenance expense for Power Delivery increased by $24 million primarily due to:

In the third quarter of 2012, as a result of the MPSC’s order in Pepco’s most recent electric distribution base rate case, $8.8 million of incremental storm restoration costs incurred by Pepco in the first quarter of 2011 and previously expensed through Other Operation and Maintenance expense in 2011 will be reversed and deferred as a regulatory asset. This regulatory asset is to be recovered in electric distribution rates over five years.

Depreciation and Amortization expenses increased by $11 million to $221 million in 2012 from $210 million in 2011 primarily due to:

The aggregate amount of these increases was partially offset by a decrease of $10 million in amortization of stranded costs as the result of lower revenue due to rate decreases effective October 2011 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue).

Other Taxes decreased by $11 million to $209 million in 2012 from $220 million in 2011. The decrease was primarily due to:

PHI’s operating expenses include a $39 million pre-tax gain for the six months ended June 30, 2011 associated with the early termination of several leases included in its cross-border energy lease portfolio.

Deferred Electric Service Costs, which relate only to ACE, represent (i) the over or under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the over or under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Fuel and Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Deferred Electric Service Costs decreased by ~~$12~~$3 million, to an expense reduction of ~~$15~~$35 million in 2012 as compared to an expense reduction of $3$32 million in 2011, primarily ~~due to~~as a result of higher electricity supply costs, partially offset by higher Default Electricity Supply revenue rates.

PHI’s operating expenses include impairment losses of $3 million for the six months ended June 30, 2012, associated primarily with its investment in a landfill gas-fired electric generation facility owned and operated by Pepco Energy Services. During the second quarter, Pepco Energy Services performed a long-lived asset impairment test on the facility as a result of a sustained decline in energy prices, and the facility was written down to its estimated fair value because the future expected cash flows of the facility were not sufficient to provide recovery of the facility’s carrying value.

Other Expenses (which are net of Other Income) increased by $4$6 million to a net expense of ~~$57~~$112 million in 2012 from a net expense of ~~$53~~$106 million in 2011. The increase was primarily due to:

PHI’s income tax expense decreased by ~~$20~~$39 million to $49 million in ~~the three months ended March 31, 2012.~~2012 from $88 million in 2011. PHI’s consolidated effective tax rates for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 were ~~17.1%~~27.4% and ~~35.4%~~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. 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 ~~primarily resulted from changes~~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 inas 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 ~~Internal Revenue Service (IRS)~~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. ~~The effective rate was further decreased as~~In contrast, during the six months ended June 30, 2011, PHI recorded a ~~result of~~$17 million benefit, primarily resulting from the ~~increase in asset removal costs in Pepco in 2012 primarily~~settlement with the IRS on interest due on its 1996 through 2002 tax years, and the $4 million state tax benefit related to ~~a higher level of~~prior years’ asset ~~retirements.~~

~~For the three months ended March 31, 2012, the income from discontinued operations, net of income taxes, was zero.~~

For the three months ended March 31, 2011, the $2 million income from discontinued operations, net of income taxes, includes after-tax income of $4 million arising from adjustments to certain accrued expenses for obligations associated with the sale of the wholesale power generation business to Calpine.dispositions.

This section discusses PHI’s working capital, cash flow activity, capital requirements and other uses and sources of capital.

At ~~March 31,~~June 30, 2012, PHI’s current assets on a consolidated basis totaled $1.3 billion and its consolidated current liabilities totaled ~~$2.1~~$1.9 billion, resulting in a working capital deficit of ~~$747~~$587 million. PHI expects the working capital deficit at ~~March 31,~~June 30, 2012 to be funded during the remainder of 2012 through the ~~issuance of long-term debt by the utilities and~~ physical settlement of the equity forward transaction, as well as from cash flows from operations. Additional working capital will be provided by anticipated reductions in collateral requirements due to the ongoing wind-down of the Pepco Energy Services retail energy supply business. At December 31, 2011, PHI’s current assets on a consolidated basis totaled $1.4 billion and its current liabilities totaled $1.9 ~~billion.~~billion, for a working capital deficit of $422 million. The increase of $165 million in the working capital deficit from December 31, 2011 to ~~March 31,~~June 30, 2012 was primarily due to an increase in short-term debt for PHI, Pepco and ~~DPL,~~ACE, and the use of cash and cash equivalents, ~~in ACE~~ to temporarily support higher spending by the utilities on infrastructure investments and reliability ~~initiatives until long-term financing for these initiatives is obtained.~~initiatives.

At ~~March 31,~~June 30, 2012, PHI’s consolidated cash and cash equivalents totaled ~~$64~~$39 million, of which ~~$44~~$22 million was invested in money market funds, and the balance was held as cash and uncollected funds. Current restricted cash equivalents (cash that is available to be used only for designated purposes) totaled ~~$10~~$9 million. At December 31, 2011, PHI’s consolidated cash and cash equivalents totaled $109 million, of which $87 million was invested in money market funds, and the balance was held as cash and uncollected funds. ~~Its~~At December 31, 2011, PHI’s current restricted cash equivalents totaled $11 million.

A detail of PHI’s short-term debt balance and current ~~maturities~~portion of long-term debt and project funding balance is as follows:


	As of December 31, 2011														As of June 30, 2012
	*(millions of dollars)*														*(millions of dollars)*
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated		PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146	$	—	$	—	$	105	$	23	$	—	$	—	$	128
Commercial Paper		465		74		47		—		—		—		586		365		108		—		74		—		—		547
Term Loan Agreement																200		—		—		—		—		—		200

Total Short-Term Debt	$	465	$	74	$	152	$	23	$	—	$	18	$	732	$	565	$	108	$	105	$	97	$	—	$	—	$	875

Current Maturities of Long-Term Debt and Project Funding	$	—	$	—	$	66	$	—	$	37	$	9	$	112
Current Portion of Long-Term Debt and Project Funding															$	—	$	—	$	—	$	—	$	38	$	11	$	49

PHI, Pepco, DPL and ACE maintain commercial paper programs to address short-term liquidity needs. As of ~~March 31,~~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. ~~In January 2012, the~~Although PHI’s Board of Directors had approved in January 2012 an increase in PHI’s ~~maximum~~commercial paper program limit to ~~$1.25 billion, which has not been put into effect as of March 31, 2012.~~align it with PHI’s borrowing limits under the credit facility, PHI intends to maintain this limit at its current level.

~~In January 2012, ACE Funding made principal payments of $7 million on its Series 2002-1 Bonds, Class A-3, and $2 million on its Series 2003-1 Bonds, Class A-2.~~

Pursuant to the terms of this transaction, a forward counterparty borrowed 17,922,077 shares of PHI’s 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 ~~has~~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~~Accounting Standards Codification (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.~~settlement during the fourth quarter of 2012.

For the three and six months ended ~~March 31,~~June 30, 2012, the equity forward transaction did not have a material dilutive effect on PHI’s earnings per share.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and one month 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 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 March 31, 2012.

~~Cash and Credit Facility Available as of March 31,~~Three Months Ended June 30, 2012

In the ordinary course of its energy supply business which is in the process of winding 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 March 31, 2012, Pepco Energy Services posted net cash collateral of $92 million and letters of credit of $1 million. At December 31, 2011, Pepco Energy Services posted net cash collateral of $112 million and letters of credit of $1 million.

At March 31, 2012 and December 31, 2011, the amount of cash, plus borrowing capacity under the primary credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $227 million and $283 million, respectively.

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 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 DPL’s 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 DPL’s 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 DPL’s benefit and (iii) for general corporate purposes.

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~~the London Interbank Offered Rate (LIBOR) with respect to the relevant interest period, all as defined in the loan agreement, plus a margin of 0.875%. PHI’s 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 ~~April 24,~~June 30, 2012, outstanding borrowings under the loan agreement bore interest at an annual ~~interest~~ rate of ~~1.115%~~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 ~~intends to use~~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 ~~be in~~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.

PHI, Pepco, DPL and ACE maintain an on-going 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 the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, The Royal Bank of Scotland plc and Citicorp USA, Inc. (now Citibank, N.A.), as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith, Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities Inc. as passive joint lead arrangers and joint book runners, with respect to the facility, which among other changes, extended the expiration date of the facility to August 1, 2016. On August 2, 2012, each Reporting Company entered into an amendment of the amended and restated credit agreement with each of the other parties thereto 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. Some or all of the parties to the amended and restated credit agreement, or their affiliates, have in the past provided investment or commercial banking services to each Reporting Company and its affiliates, including as an underwriter of their securities, for which they received customary fees, underwriting discounts and commissions, and they are likely to provide similar services in the future.

The interest rate payable by each company on utilized funds is, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one month 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.

In the ordinary course of its retail energy supply business which is in the process of winding 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 posted net cash collateral of $61 million and letters of credit of less than $1 million. At December 31, 2011, Pepco Energy Services 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 the primary credit facility available to meet the future liquidity needs of Pepco Energy Services, totaled $383 million and $283 million, respectively.

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.

Pension benefits are provided under PHI’s non-contributory retirement plan (the PHI Retirement Plan), a defined benefit pension plan that covers substantially all employees of Pepco, DPL and ACE and certain employees of other PHI subsidiaries. PHI’s funding policy with regard to 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.

PHI satisfied the minimum required contribution rules under the Pension Protection Act in 2011, 2010 and 2009. On January 31, 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 ~~at least~~ the funding target level for 2012 under the Pension Protection Act.

Based on the results of the 2011 actuarial valuation, PHI’s net periodic pension and other postretirement benefit costs were approximately $94 million in 2011 versus $116 million in 2010. The current estimate of benefit cost for 2012 is ~~$103~~$111 million. The utility subsidiaries are responsible for substantially all of the

total PHI net periodic pension and other postretirement benefit costs. Approximately 30% of net periodic pension and other postretirement benefit costs are capitalized. PHI estimates that its net periodic pension and other postretirement benefit expense will be approximately ~~$72~~$78 million in 2012, as compared to $66 million in 2011 and $81 million in 2010.

PHI’s cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are summarized below:


	Cash Source (Use)									Cash Source (Use)
	2012			2011			Change			2012			2011			Change
	*(millions of dollars)*									*(millions of dollars)*
Operating Activities	$	23		$	197		$	(174	)	$	124		$	334		$	(210	)
Investing Activities		(281	)		(164	)		(117	)		(560	)		(220	)		(340	)
Financing Activities		213			(36	)		249			366			(77	)		443

Net decrease in cash and cash equivalents	$	(45	)	$	(3	)	$	(42	)
Net (decrease) increase in cash and cash equivalents										$	(70	)	$	37		$	(107	)

Cash flows from operating activities during the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are summarized below:


	Cash Source (Use)									Cash Source (Use)
	2012			2011			Change			2012			2011			Change
	*(millions of dollars)*									*(millions of dollars)*
Net income from continuing operations	$	68		$	62		$	6		$	130		$	157		$	(27	)
Non-cash adjustments to net income		93			87			6			190			172			18
Gain on early termination of finance leases held in trust											—			(39	)		39
Pension contributions		(200	)		(110	)		(90	)		(200	)		(110	)		(90	)
Changes in cash collateral related to derivative activities		20			31			(11	)		53			44			9
Changes in other assets and liabilities		42			96			(54	)		(49	)		68			(117	)
Changes in Conectiv Energy net assets held for sale		—			31			(31	)		—			42			(42	)

Net cash from operating activities	$	23		$	197		$	(174	)	$	124		$	334		$	(210	)

Net cash from operating activities decreased ~~$174~~$210 million for the ~~three~~six months ended ~~March 31,~~June 30, 2012, compared to the same period in 2011. The decrease was due primarily to ~~the disposition of all of Conectiv Energy’s remaining assets,~~ a $90 million increase in pension contributions compared to 2011, the disposition of all of Conectiv Energy’s remaining assets of $42 million in 2011, and a ~~decrease~~$27 million decline in ~~regulatory liabilities in 2012 that was the result of a lower rate of recovery by ACE of costs associated with energy and capacity purchases under the NUG contracts.~~net income from continuing operations compared to 2011.

Cash flows from investing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are summarized below:

Net cash used by investing activities increased ~~$117~~$340 million for the ~~three~~six months ended ~~March 31,~~June 30, 2012, compared to the same period in 2011. The increase was due primarily to a ~~$120~~$202 million increase in capital expenditures associated with new customer services, distribution reliability and ~~transmission.~~transmission, as well as $161 million in proceeds received in 2011 from the early termination of certain cross-border energy leases.

Cash flows from financing activities during the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 are summarized below:


	Cash (Use) Source									Cash Source (Use)
	2012			2011			Change			2012			2011			Change
	*(millions of dollars)*									*(millions of dollars)*
Dividends paid on common stock	$	(61	)	$	(61	)	$	—		$	(123	)	$	(122	)	$	(1	)
Common stock issued for the Dividend Reinvestment Plan and employee-related compensation		17			14			3			28			25			3
Redemption of preferred stock of subsidiaries		—			(6	)		6			—			(6	)		6
Issuances of long-term debt											450			235			215
Reacquisitions of long-term debt		(9	)		(9	)		—			(122	)		(52	)		(70	)
Issuances of short-term debt, net		253			33			220
Issuances (Repayments) of short-term debt, net											143			(139	)		282
Cost of issuances		(3	)		—			(3	)		(7	)		(2	)		(5	)
Net other financing activities		16			(7	)		23			(3	)		(16	)		13

Net cash from (used by) financing activities	$	213		$	(36	)	$	249		$	366		$	(77	)	$	443

Net cash from financing activities increased ~~$249~~$443 million for the ~~three~~six months ended ~~March 31,~~June 30, 2012 compared to the same period in 2011. The increase was due primarily ~~due~~ to a ~~$220~~$282 million increase in net short-term debt issuances to temporarily support higher spending by the utilities on infrastructure investments and reliability initiatives, ~~until~~and a $145 million net increase in long-term ~~financing is obtained.~~debt.

On February 25, 2011, ACE redeemed all of its outstanding cumulative preferred stock for approximately $6 million.

~~Cash flows from the reacquisition~~The issuances and reacquisitions of long-term debt for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 isare summarized ~~in the chart~~ below:

As of ~~March 31,~~June 30, 2012, PHI had a total of ~~$858~~$547 million of commercial paper outstanding as compared to $586 million of commercial paper outstanding as of December 31, 2011.

On April 24, 2012, PHI entered into a $200 million term loan agreement that must be repaid in full on or before April 23, 2013. See “Capital Resources and Liquidity – Financing Activity During the Three Months Ended June 30, 2012 – Term Loan Agreement” in this item for additional information regarding this term loan agreement.

Pepco Holdings’ capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2012 were ~~$291~~$589 million, of which ~~$158~~$306 million was incurred by Pepco, ~~$69~~$145 million was incurred by DPL, ~~$53~~$114 million was incurred by ACE, $5$10 million was incurred by Pepco Energy Services and $6$14 million was incurred for Corporate and Other. The Power Delivery expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. Corporate and Other capital expenditures primarily consisted of hardware and software expenditures that will be allocated to Power Delivery when the assets are placed in service.

In its 2011 Form 10-K, PHI presented its projected capital expenditures for the five-year period 2012 through 2016. There have been no changes in PHI’s projected capital expenditures from those presented in the 2011 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by each of PHI’s utility subsidiaries to install smart meters, further automate their electric distribution systems and enhance their communications infrastructure, which is referred to as the Blueprint for the Future.

In 2007, PJM ~~has~~ approved the construction of the Mid-Atlantic Power Pathway (MAPP),. Currently, MAPP is a ~~new~~ 152-mile, interstate transmission line proposed as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. In light of ~~the~~this delayed in-service date, ~~for MAPP,~~ substantially all of ~~the~~PHI’s remaining anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on management’s current projections. ~~The exact revised~~As of June 30, 2012, the total expenditures for MAPP were $101 million, which management believes are fully recoverable, including prudently incurred abandoned plant costs.

PJM is currently reviewing its 2012 regional transmission expansion plan, which review includes an evaluation of the region’s overall transmission needs. This review is anticipated to take into account the results of PJM’s demand forecast and the May 2012 annual capacity market auction which secured additional capacity resources. PHI expects that PJM will release the results of its annual review process, including the further impact on the MAPP in-service date, ~~of MAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process.~~in August 2012.

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain inwithout the ~~capital markets.~~guarantee. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is ~~not an~~no approval deadline under the loan guarantee program, ~~but~~and this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

In 2009, the DOE announced awards under the American Recovery and Reinvestment Act of 2009 of:

In April 2010, Pepco, ACE and the DOE signed agreements formalizing the $168 million in awards. Of the $168 million, $130 million is ~~expected to offset incurred and projected~~being used for Blueprint for the Future and other capital expenditures of Pepco and ACE. The remaining $38 million ~~will be~~is being used to offset incremental expenses associated with direct load control and other Pepco and ACE programs. During the ~~first quarter of~~six months ended June 30, 2012, Pepco and ACE received award payments of $9$26 million and $1$3 million, respectively. ~~Cumulative~~The cumulative award payments received by Pepco and ACE ~~since April 2010,~~as of June 30, 2012, were ~~$76~~$93 million and ~~$10~~$11 million, respectively.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

Third Party Guarantees, Indemnifications, Obligations and Off-Balance Sheet Arrangements

For a discussion of PHI’s third party guarantees, indemnifications, obligations and off-balance sheet arrangements, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

On ~~April~~July 26, 2012, Pepco Holdings’ Board of Directors declared a dividend on common stock of 27 cents per share payable ~~June 29,~~September 28, 2012 to stockholders of record on ~~June 11,~~September 10, 2012. PHI had approximately $1,079 million and $1,072 million of retained earnings free of restrictions at ~~March 31,~~June 30, 2012 and December 31, 2011, respectively.

The following table provides detail on changes in the net asset or liability positions of the Pepco Energy Services segment with respect to energy commodity contracts for the ~~three~~six months ended ~~March 31,~~June 30, 2012. The balances in the table are pre-tax and the derivative assets and liabilities reflect netting by the counterparty before the impact of collateral.


	Energy Commodity Activities (a)			Energy Commodity Activities (a)
	*(millions of dollars)*			*(millions of dollars)*
Total Fair Value of Energy Contract Net Liabilities at December 31, 2011	$	(83	)	$	(83	)
Current period unrealized mark-to-market losses		(10	)		(5	)
Effective portion of changes in fair value – recorded in Accumulated Other Comprehensive Loss		—			—
Cash flow hedge ineffectiveness – recorded in income		—			—
Reclassification to realized on settlement of contracts		23			41

Total Fair Value of Energy Contract Net Liabilities at March 31, 2012	$	(70	)
Total Fair Value of Energy Contract Net Liabilities at June 30, 2012				$	(47	)

Detail of Fair Value of Energy Contract Net Liabilities at March 31, 2012 (see above)
Detail of Fair Value of Energy Contract Net Liabilities at June 30, 2012 (see above)
Derivative assets (current assets)	$	3		$	3
Derivative assets (non-current assets)		—			—

Total Fair Value of Energy Contract Assets		3			3

Derivative liabilities (current liabilities)		(71	)		(49	)
Derivative liabilities (non-current liabilities)		(2	)		(1	)

Total Fair Value of Energy Contract Liabilities		(73	)		(50	)

Total Fair Value of Energy Contract Net Liabilities	$	(70	)	$	(47	)

The ~~$70~~$47 million net liability on energy contracts at ~~March 31,~~June 30, 2012 was primarily attributable to losses on power swaps and natural gas futures held by Pepco Energy Services. Pepco Energy Services’ net liability decreased to ~~$70~~$47 million at ~~March 31,~~June 30, 2012 from $83 million at December 31, 2011 primarily due to settlements of the derivatives. PHI expects that future revenues from existing customer sales obligations that are accounted for on an accrual basis will largely offset expected realized net losses on Pepco Energy Services’ energy contracts.

PHI uses its best estimates to determine the fair value of the commodity derivative contracts that are entered into by Pepco Energy Services. The fair values in each category presented below reflect forward prices and volatility factors as of ~~March 31,~~June 30, 2012, and the fair values are subject to change as a result of changes in these prices and factors. ~~As of March 31, 2012, all of these contracts were entered into by Pepco Energy Services.~~


	Fair Value of Contracts at March 31, 2012 Maturities														Fair Value of Contracts at June 30, 2012 Maturities
Source of Fair Value	2012			2013			2014			2015 and Beyond		Total Fair Value			2012			2013			2014			2015 and Beyond		Total Fair Value
	*(millions of dollars)*														*(millions of dollars)*
Energy Commodity Activities, net(a)
Actively Quoted (i.e., exchange-traded) prices	$	(29	)	$	(10	)	$	(2	)	$	—	$	(41	)	$	(16	)	$	(10	)	$	(2	)	$	—	$	(28	)
Prices provided by other external sources (b)		(19	)		(8	)		—			—		(27	)		(10	)		(8	)		—			—		(18	)
Modeled (c)		(2	)		—			—			—		(2	)		(1	)		—			—			—		(1	)

Total	$	(50	)	$	(18	)	$	(2	)	$	—	$	(70	)	$	(27	)	$	(18	)	$	(2	)	$	—	$	(47	)

Under certain contractual arrangements entered into by PHI’s subsidiaries, the subsidiary may be required to provide cash collateral or letters of credit as security for its contractual obligations if the credit ratings of PHI or the subsidiary are downgraded. In the event of a downgrade, the amount required to be posted would depend on the amount of the underlying contractual obligation existing at the time of the downgrade. Based on contractual provisions in effect at ~~March 31,~~June 30, 2012, a downgrade in the unsecured debt credit ratings of PHI and each of its rated subsidiaries to below “investment grade” would increase the collateral obligation of PHI and its subsidiaries by up to ~~$221~~$180 million, none of which is related to discontinued operations of Conectiv Energy, and ~~$111~~$72 million of which is the net settlement amount attributable to derivatives, normal purchase and normal sale contracts, collateral, and other contracts under master netting agreements as described in Note (13), “Derivative Instruments and Hedging ~~Activities”~~Activities,” to the consolidated financial statements of PHI set forth in Part I, Item 1 of this Form 10-Q. The remaining ~~$110~~$108 million of the collateral obligation that would be incurred in the event PHI were downgraded to below “investment grade” is attributable primarily to energy services contracts and accounts payable to independent system operators and distribution companies on full requirements contracts entered into by Pepco Energy Services. PHI believes that it and its subsidiaries currently have sufficient liquidity to fund their operations and meet their financial obligations.

Many of the contractual arrangements entered into by PHI’s subsidiaries in connection with competitive energy and Default Electricity Supply activities include margining rights pursuant to which the PHI subsidiary or a counterparty may request collateral if the market value of the contractual obligations reaches levels in excess of the credit thresholds established in the applicable arrangements. Pursuant to these margining rights, the affected PHI subsidiary may receive, or be required to post, collateral due to energy price movements. As of ~~March 31,~~June 30, 2012, Pepco Energy Services provided net cash collateral in the amount of ~~$92~~$61 million in connection with these activities.

On September 29, 2009, the ~~Maryland Public Service Commission (MPSC)~~MPSC initiated an investigation into whether the ~~regulated~~ electric distribution companies (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.

~~The~~On April 12, 2012, the MPSC issued an order ~~on April 12, 2012, in which it determined~~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 SOS loads. 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 PHI’s, Pepco’s and DPL’s 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 Pepco’s and DPL’s 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 MPSC’s order on the grounds that ~~that~~ such order violated the commerce clause and the supremacy clause of the U.S. Constitution. ~~PHI continues to evaluate whether to seek~~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 MPSC’s order.

For a discussion of other regulatory matters, see Note (7), “Regulatory Matters,” to the consolidated financial statements of PHI.

For a discussion of legal proceedings, see Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI.

For a discussion of Pepco Holdings’ critical accounting policies, please refer to Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in Pepco Holdings’ 2011 Form 10-K. There have been no material changes to PHI’s critical accounting policies as disclosed in ~~the~~Pepco Holdings’ 2011 Form 10-K.

For information concerning new accounting standards and pronouncements that have recently been adopted by PHI and its subsidiaries or that one or more of the companies will be required to adopt on or before a specified date in the future, see Note (3), “Newly Adopted Accounting Standards,” and Note (4), “Recently Issued Accounting Standards, Not Yet Adopted,” to the consolidated financial statements of PHI.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Pepco meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

Pepco is engaged in the transmission and distribution of electricity in the District of Columbia and major portions of Prince George’s County and Montgomery County in suburban Maryland. Pepco also provides Default Electricity Supply. Pepco’s service territory covers approximately 640 square miles and has a population of approximately 2.2 million. As of ~~March 31,~~June 30, 2012, approximately ~~58%~~57% of delivered electricity sales were to Maryland customers and approximately ~~42%~~43% were to District of Columbia customers.

Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenue is not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that ~~recognizes distribution revenue based on an approved~~provides for a fixed distribution charge per ~~customer. Consequently,~~customer rather than a charge based on energy usage. The BSA has the effect of decoupling the distribution revenue recognized ~~is decoupled~~ in a reporting period from the amount of power delivered during the ~~period and~~period. As a result, the only factors that will cause distribution revenue ~~recognized~~from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Pepco is a wholly owned subsidiary of PHI. Because PHI is a public utility holding company subject to the Public Utility Holding Company Act of 2005 (PUHCA 2005), the relationship between each of PHI, PHI Service Company (a subsidiary service company of PHI, which provides a variety of support services, including legal, accounting, treasury, tax, purchasing and information technology services to PHI and its operating subsidiaries) and Pepco, as well as certain activities of Pepco, are subject to FERC’s regulatory oversight under PUHCA 2005.

On July 20, 2012, the MPSC issued an order in response to Pepco’s application with the MPSC seeking to increase its electric distribution base rates. See Note (6), “Regulatory Matters – Rate Proceedings” to the financial statements of Pepco included herein and “Regulatory Lag” in this section below for a discussion of the rate case. Pepco is currently reviewing the order to determine what further actions, if any, it may seek to pursue.

As a result of the base rate case, Pepco is rigorously reviewing its operating expenses and will take actions to reduce such expenses where necessary or appropriate. In this regard, a PHI-wide hiring freeze implemented in the second quarter of 2012 will be extended for the foreseeable future. Decisions by the MPSC in future rate cases which do not permit Pepco to recover its prudently incurred expenses on a timely basis could negatively impact its ability to earn reasonable rates of return on its investments in Maryland. Further, Pepco believes that its ability to maintain the current level of its reliability-related investments requires adequate recovery of expenditures for such investments in future base rate cases.

In 2010, Pepco announced that it had adopted and begun to implement comprehensive reliability enhancement plans in Maryland and the District of Columbia. These reliability enhancement plans include various initiatives to improve electrical system reliability, such as:

In 2011, ~~prior to the start of the summer storm season,~~ Pepco also initiated a program to improve its emergency restoration efforts that included, among other initiatives, an expansion and enhancement of customer service capabilities.

In 2012, Pepco has continued to focus on its reliability enhancement and emergency restoration improvement plans in each of its service territories.

Pepco is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Blueprint for the Future.”

An important factor in ~~Pepco’s~~the ability of Pepco to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in ~~Pepco’s~~its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” Pepco is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, Pepco’s most recent Maryland base rate case filing included a request for MPSC approval of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by Pepco of fully forecasted test years in future base rate cases. See Note (6), “Regulatory Matters – Rate Proceedings” to the financial statements of Pepco for a discussion of each of these mechanisms. In its ~~most recent~~Pepco base rate ~~cases,~~case order, the MPSC did not approve Pepco’s request to implement the RIM and did not endorse the use by Pepco ~~(in~~of fully forecasted test years in future rate cases. However, the ~~District~~MPSC did permit an adjustment to the rate base of ~~Columbia~~Pepco to reflect the actual cost of reliability plant additions outside the test year.

Pepco will continue to seek cost recovery and ~~Maryland) has proposed~~tracking mechanisms ~~that would track reliability~~from the MPSC and ~~other expenses and permit Pepco between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking~~the DCPSC to reduce the effects of regulatory lag. For example, Pepco has proposed regulatory lag mitigation mechanisms in its pending electric distribution base rate case at the DCPSC. See Note (6), “Regulatory Matters” to the financial statements of Pepco included herein. There can be no assurance that these proposals or any other attempts by Pepco to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or ~~any~~ base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms or any alternative mechanisms are approved, Pepco plans to file rate cases at least annually in an effort to align more closely ~~its~~the revenue and related cash flow levels of Pepco with its other operation and maintenance spending and capital investments. In ~~future~~light of the MPSC’s decision in the most recent Pepco base rate ~~cases,~~case, Pepco ~~would also continue~~intends to ~~seek cost~~file its next electric distribution base rate case with the MPSC in the fourth quarter of 2012.

On June 29, 2012, the respective service territories of Pepco 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 Pepco’s electric transmission and distribution systems. 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. The total incremental storm restoration costs of Pepco associated with the derecho are currently estimated to range between $39 million and $47 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 a regulatory asset to reflect the probable recovery ~~and tracking mechanisms from applicable regulatory commissions to reduce~~of these storm costs in Maryland. Pepco will be pursuing recovery of the ~~effects~~incremental storm restoration costs during the next cycle of ~~regulatory lag.~~distribution base rate cases.

The following results of operations discussion compares the three months ended March 31, 2012 to the three months ended March 31, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.

The table above shows the amount of Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to Pepco’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that Pepco receives as a transmission owner from PJM for approved regional transmission expansion plan costs.

The aggregate amount of these increases was partially offset by a decrease of $4 million due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of lower sales that resulted in a decrease in Montgomery County, Maryland utility taxes that are collected by Pepco on behalf of the county.

~~Default Electricity Supply Revenue decreased by $75 million primarily due to:~~

The following table shows the percentages of Pepco’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from Pepco. Amounts are for the three months ended March 31:

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $70 million to $185 million in 2012 from $255 million in 2011 primarily due to:

~~Other Operation and Maintenance increased by $1 million to $103 million in 2012 from $102 million in 2011 primarily due to:~~

The aggregate amount of these increases was partially offset by a decrease of $15 million in emergency restoration costs, which were higher in 2011 largely due to the severe winter storm in January 2011.

~~Depreciation and Amortization expense increased by $5 million to $47 million in 2012 from $42 million in 2011 primarily due to:~~

Other Taxes decreased by $2 million to $90 million in 2012 from $92 million in 2011. The decrease was primarily the result of lower sales that resulted in a decrease in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding increase in Regulated T&D Electric Revenue).

Other Expenses (which are net of Other Income) increased by $3 million to a net expense of $21 million in 2012 from a net expense of $18 million in 2011. The increase was primarily due to a decrease in other income due to March 2011 net proceeds from a company owned life insurance policy.

Pepco’s income tax expense decreased by $12 million in the three months ended March 31, 2012. Pepco’s effective tax rates for the three months ended March 31, 2012 and 2011were (26.3)% and 28.0%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions in the first quarter of 2012, 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. The effective rate was further decreased as a result of the increase in asset removal costs in 2012 primarily related to a higher level of asset retirements.

Pepco’s capital expenditures for the three months ended March 31, 2012 were $158 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.

In its 2011 Form 10-K, Pepco presented its projected capital expenditures for the five-year period 2012 through 2016. There have been no changes in Pepco’s projected capital expenditures from those presented in the 2011 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by Pepco to install smart meters, further automate electric distribution systems and enhance Pepco’s communications infrastructure, which is referred to as the Blueprint for the Future.

PJM has approved PHI’s proposal to construct MAPP, a new 152-mile, interstate transmission line as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified PHI that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. In light of the delayed in-service date for MAPP, substantially all of the anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on current projections. The exact revised in-service date of MAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process.

To assist in the funding of the MAPP project, PHI has applied for a $684 million loan guarantee from the DOE for a substantial portion of the MAPP project, primarily the Calvert Cliffs to Indian River segment. The application has been made under a federal loan guarantee program for projects that employ innovative energy efficiency, renewable energy and advanced transmission and distribution technologies. If granted, PHI believes the guarantee could allow PHI to acquire financing at a lower cost than it would otherwise be able to obtain in the capital markets. Whether PHI’s application will be granted and, if so, the amount of debt guaranteed is subject to the discretion of the DOE and the negotiation of terms that will satisfy the conditions of the guarantee program. On February 28, 2011, the DOE issued a Notice of Intent to prepare an Environmental Impact Statement to assist the DOE in assessing the environmental impact of constructing the portion of the MAPP project to be supported by the loan guarantee. Since February 2011, the DOE has conducted field inspections of the entire route and has held public meetings to obtain input from the communities along the route.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is not an approval deadline under the loan guarantee program, but this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

In 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation and communications infrastructure. Pepco was awarded $149 million with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

In April 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is expected to offset incurred and projected Blueprint for the Future and other capital expenditures of Pepco. The remaining $31 million will be used to offset incremental expenses associated with direct load control and other programs. During the first quarter of 2012, Pepco received award payments of $9 million. Cumulative award payments received by Pepco since April 2010, were $76 million.

~~The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

DPL meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of March 31, 2012, approximately 66% of delivered electricity sales were to Delaware customers and approximately 34% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that recognizes distribution revenue based on an approved distribution charge per customer. Consequently, distribution revenue recognized is decoupled in a reporting period from the amount of power delivered during the period and the only factors that will cause distribution revenue recognized in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. Changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

DPL is a wholly owned subsidiary of Conectiv, LLC (Conectiv) which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and DPL, as well as certain activities of DPL, are subject to FERC’s regulatory oversight under PUHCA 2005.

DPL is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Blueprint for the Future.”

An important factor in DPL’s ability to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in DPL’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth. In its most recent rate cases, DPL (in Delaware and Maryland) has proposed mechanisms that would track reliability and other expenses and permit DPL between rate cases to make adjustments in its rates for prudent investments as made, thereby seeking to reduce the effects of regulatory lag. There can be no assurance that these proposals or any other attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms are approved, DPL plans to file rate cases at least annually in an effort to align more closely its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, DPL would also continue to seek cost recovery and tracking mechanisms from applicable regulatory commissions to reduce the effects of regulatory lag.

The following results of operations discussion compares the ~~three~~six months ended ~~March 31,~~June 30, 2012 to the ~~three~~six months ended June 30, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.

The aggregate amount of these increases was partially offset by a decrease of $7 million due to lower pass-through revenue (which is substantially offset by a corresponding decrease in Other Taxes) primarily the result of lower sales that resulted in decreases in Montgomery County, Maryland and District of Columbia utility taxes collected by Pepco on behalf of the jurisdictions.

Purchased Energy consists of the cost of electricity purchased by Pepco to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by $128 million to $345 million in 2012 from $473 million in 2011 primarily due to:

Other Operation and Maintenance expense increased by $2 million to $204 million in 2012 from $202 million in 2011 primarily due to:

In the third quarter of 2012, as a result of the MPSC’s order in Pepco’s most recent electric distribution base rate case, $8.8 million of incremental storm restoration costs incurred by Pepco in the first quarter of 2011 and previously expensed through Other Operation and Maintenance expense in 2011 will be reversed and deferred as a regulatory asset. This regulatory asset is to be recovered in electric distribution rates over five years.

Depreciation and Amortization expense increased by $ 11 million to $95 million in 2012 from $84 million in 2011 primarily due to:

The MPSC reduced Pepco’s depreciationrates in Pepco’s most recent electric distribution base rate case, which is expected to result in lower annual Depreciation and Amortization expense of approximately $27.3 million beginning on July 20, 2012.

Other Taxes decreased by $4 million to $182 million in 2012 from $186 million in 2011. The decrease was primarily due to lower sales that resulted in a decrease in the Montgomery County, Maryland utility taxes that are collected and passed through by Pepco (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Other Expenses (which are net of Other Income) increased by $5 million to a net expense of $41 million in 2012 from a net expense of $36 million in 2011. The increase was primarily due to:

Pepco’s income tax expense decreased by $6 million to $3 million in 2012 from $9 million in 2011. Pepco’s effective tax rates for the six months ended June 30, 2012 and 2011 were 5.6% and 15.3%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, partially offset by the state tax benefit recorded in 2011 related to prior years’ asset dispositions. The effective rate was further decreased as a result of the increase in asset removal costs in 2012 primarily related to a higher level of asset retirements.

In the first quarter of 2012, Pepco 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 the second quarter of 2011, Pepco recorded a $5 million interest benefit from a settlement reached with the IRS with respect to interest due on its federal tax liabilities related to the tax years 1996 through 2002 and a $4 million tax benefit related to the filing of amended state tax returns. The amended returns reduced state taxable income due to an increase in tax basis on certain prior years’ asset dispositions.

Further, in March of 2011, Pepco accrued $3 million related to net proceeds from life insurance policies on a former executive. This income is not taxable and is included in the permanent differences related to deferred compensation funding.

Pepco’s capital expenditures for the six months ended June 30, 2012 were $306 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to Pepco when the assets are placed in service.

In its 2011 Form 10-K, Pepco presented its projected capital expenditures for the five-year period 2012 through 2016. There have been no changes in Pepco’s projected capital expenditures from those presented in Pepco’s 2011 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by Pepco to install smart meters, further automate electric distribution systems and enhance Pepco’s communications infrastructure, which is referred to as the Blueprint for the Future.

In 2007, PJM approved the construction of MAPP. Currently, MAPP is a 152-mile, interstate transmission line proposed as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified Pepco that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. In light of this delayed in-service date, substantially all of Pepco’s remaining anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on management’s current projections. As of June 30, 2012, the total expenditures for MAPP were $64 million, which management believes are fully recoverable, including prudently incurred abandoned plant costs.

PJM is currently reviewing its 2012 regional transmission expansion plan, which review includes an evaluation of the region’s overall transmission needs. This review is anticipated to take into account the results of PJM’s demand forecast and the May 2012 annual capacity market auction which secured additional capacity resources. Pepco expects that PJM will release the results of its annual review process, including the further impact on the MAPP in-service date, in August 2012.

The DOE’s review of the loan guarantee program has delayed the DOE’s review of PHI’s loan guarantee application. There is no approval deadline under the loan guarantee program, and this program could change or be terminated in the future. PHI continues to coordinate environmental activities with the DOE.

In 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation and communications infrastructure. Pepco was awarded $149 million, with $105 million to be used in the Maryland service territory and $44 million to be used in the District of Columbia service territory.

In April 2010, Pepco and the DOE signed agreements formalizing Pepco’s $149 million share of the $168 million award. Of the $149 million, $118 million is being used for Blueprint for the Future and other capital expenditures of Pepco. The remaining $31 million is being used to offset incremental expenses associated with direct load control and other programs. During the six months ended June 30, 2012, Pepco received award payments of $26 million. The cumulative award payments received by Pepco as of June 30, 2012, were $93 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

DPL is engaged in the transmission and distribution of electricity in Delaware and portions of Maryland. DPL also provides Default Electricity Supply. DPL’s electricity distribution service territory covers approximately 5,000 square miles and has a population of approximately 1.4 million. As of June 30, 2012, approximately 67% of delivered electricity sales were to Delaware customers and approximately 33% were to Maryland customers. In northern Delaware, DPL also supplies and distributes natural gas to retail customers and provides transportation-only services to retail customers who purchase natural gas from other suppliers. DPL’s natural gas distribution service territory covers approximately 275 square miles and has a population of approximately 500,000.

DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a BSA for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A comparable revenue decoupling mechanism for DPL electricity and natural gas customers in Delaware is under consideration by the DPSC. Changes in customer usage (such as due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

On July 20, 2012, the MPSC issued an order in response to DPL’s application with the MPSC seeking to increase its electric distribution base rates. See Note (7), “Regulatory Matters – Rate Proceedings” to the financial statements of DPL included herein and “Regulatory Lag” in this section below for a discussion of the rate case. DPL is currently reviewing the order to determine what further actions, if any, it may seek to pursue.

As a result of the base rate case, DPL is rigorously reviewing its operating expenses and will take actions to reduce such expenses where necessary or appropriate. In this regard, a PHI-wide hiring freeze implemented in the second quarter of 2012 will be extended for the foreseeable future. Decisions by the MPSC in future rate cases which do not permit DPL to recover its prudently incurred expenses on a timely basis could negatively impact its ability to earn reasonable rates of return on its investments in Maryland. Further, DPL believes that its ability to maintain the current level of its reliability-related investments requires adequate recovery of expenditures for such investments in future base rate cases.

An important factor in the ability of DPL to earn its authorized rate of return is the willingness of applicable public service commissions to adequately recognize forward-looking costs in its rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” DPL is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth.

In an effort to minimize the effects of regulatory lag, DPL’s most recent Maryland base rate case filing included a request for MPSC approval of (i) a RIM to recover reliability-related capital expenditures incurred between base rate cases and (ii) the use by DPL of fully forecasted test years in future base rate cases. See Note (7), “Regulatory Matters – Rate Proceedings” to the financial statements of DPL for a discussion of each of these mechanisms. In its DPL base rate case order, the MPSC did not approve DPL’s request to implement the RIM and did not endorse the use by DPL of fully forecasted test years in future rate cases. However, the MPSC did permit an adjustment to the rate base of DPL to reflect the actual cost of reliability plant additions outside the test year.

DPL will continue to seek cost recovery and tracking mechanisms from the MPSC and the DPSC to reduce the effects of regulatory lag. For example, DPL has proposed regulatory lag mitigation mechanisms in its pending electric distribution base rate case at the DPSC. See Note (7), “Regulatory Matters” to the financial statements of DPL included herein. There can be no assurance that these proposals or any other attempts by DPL to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or base rate cases will fully ameliorate the effects of regulatory lag. Until such time as these proposed mechanisms or any alternative mechanisms are approved, DPL plans to file rate cases at least annually in an effort to align more closely the revenue and related cash flow levels of DPL with its other operation and maintenance spending and capital investments. In light of the MPSC’s decision in the most recent DPL base rate case, DPL intends to file its next electric distribution base rate case with the MPSC in the fourth quarter of 2012.

On June 29, 2012, the respective service territories of DPL 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 damage to DPL’s electric transmission and distribution systems. 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. The total incremental storm restoration costs of DPL associated with the derecho are currently estimated to range between $2 million and $3 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 a regulatory asset to reflect the probable recovery of these storm costs in Maryland. DPL will be pursuing recovery of the incremental storm restoration costs during the next cycle of distribution base rate cases.

The following results of operations discussion compares the six months ended June 30, 2012 to the six months ended June 30, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.


	2012		2011		Change			2012		2011		Change
Regulated T&D Electric Revenue	$	106	$	104	$	2		$	208	$	194	$	14
Default Electricity Supply Revenue		149		190		(41	)		279		342		(63	)
Other Electric Revenue		4		4		—			7		7		—

Total Electric Operating Revenue	$	259	$	298	$	(39	)	$	494	$	543	$	(49	)

The table above shows the amount of Electric Operating Revenue earned that is subject to price regulation (Regulated T&D Electric Revenue and Default Electricity Supply Revenue) and that which is not subject to price regulation (Other Electric Revenue).

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to DPL’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes transmission enhancement credits that DPL receives as a transmission owner from PJM for approved regional transmission expansion plan costs.


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Revenue*
Residential	$	52	$	52	$	—		$	95	$	92	$	3
Commercial and industrial		27		27		—			59		55		4
Transmission and other		27		25		2			54		47		7

Total Regulated T&D Electric Revenue	$	106	$	104	$	2		$	208	$	194	$	14


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Sales (GWh)*
Residential		1,293		1,520		(227	)		2,308		2,608		(300	)
Commercial and industrial		1,740		1,744		(4	)		3,627		3,596		31
Transmission and other		12		12		—			25		24		1

Total Regulated T&D Electric Sales		3,045		3,276		(231	)		5,960		6,228		(268	)


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Customers (in thousands)*
Residential		442		441		1			441		441		—
Commercial and industrial		59		59		—			60		59		1
Transmission and other		1		1		—			1		1		—

Total Regulated T&D Electric Customers		502		501		1			502		501		1

The aggregate amount of these increases was partially offset by a decrease of $3 million due to lower sales as a result of milder weather during the 2012 winter and spring months, as compared to 2011.


								2012		2011		Change
*Default Electricity Supply Revenue*
Residential								$	211	$	259	$	(48	)
Commercial and industrial									63		77		(14	)
Other									5		6		(1	)

Total Default Electricity Supply Revenue								$	279	$	342	$	(63	)


								2012		2011		Change
*Default Electricity Supply Sales (GWh)*
Residential									2,128		2,450		(322	)
Commercial and industrial									891		899		(8	)
Other									15		15		—

Total Default Electricity Supply Sales									3,034		3,364		(330	)


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Customers (in thousands)*
Residential		415		419		(4	)		409		419		(10	)
Commercial and industrial		42		44		(2	)		41		44		(3	)
Other		—		1		(1	)		—		1		(1	)

Total Default Electricity Supply Customers		457		464		(7	)		450		464		(14	)

Default Electricity Supply Revenue decreased by ~~$41~~$63 million primarily due to:

The following table shows the percentages of DPL’s total distribution sales by jurisdiction that are derived from customers receiving Default Electricity Supply from DPL. Amounts are for the ~~three~~six months ended ~~March 31:~~June 30:


	2012			2011			2012			2011
Sales to Delaware customers		52	%		55	%		49	%		51	%
Sales to Maryland customers		59	%		64	%		55	%		60	%


	2012		2011		Change			2012		2011		Change
Regulated Gas Revenue	$	65	$	91	$	(26	)	$	84	$	117	$	(33	)
Other Gas Revenue		9		11		(2	)		14		24		(10	)

Total Natural Gas Operating Revenue	$	74	$	102	$	(28	)	$	98	$	141	$	(43	)

The table above shows the amounts of Natural Gas Operating Revenue from sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated Gas Revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other Gas Revenue ~~includes~~consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.


								2012		2011		Change
*Regulated Gas Revenue*
Residential								$	53	$	73	$	(20	)
Commercial and industrial									26		39		(13	)
Transportation and other									5		5		—

Total Regulated Gas Revenue								$	84	$	117	$	(33	)


	2012		2011		Change			2012		2011		Change
*Regulated Gas Sales (billion cubic feet)*
Residential		3		4		(1	)		4		5		(1	)
Commercial and industrial		2		2		—			2		3		(1	)
Transportation and other		2		3		(1	)		3		4		(1	)

Total Regulated Gas Sales		7		9		(2	)		9		12		(3	)


	2012		2011		Change			2012		2011		Change
*Regulated Gas Customers (in thousands)*
Residential		114		114		—			114		114		—
Commercial and industrial		10		10		—			9		9		—
Transportation and other		—		—		—			—		—		—

Total Regulated Gas Customers		124		124		—			123		123		—

~~The aggregate amount of these decreases was partially offset by an increase of $2 million due to a distribution rate increase effective July 2011.~~

Other Gas Revenue decreased by $2$10 million primarily due to lower average prices ~~partially offset by higher~~and lower volumes offor off-system sales to electric generators and gas marketers.

Purchased Energy consists of the cost of electricity purchased by DPL to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by ~~$39~~$62 million to ~~$143~~$265 million in 2012 from ~~$182~~$327 million in 2011 primarily due to:

Gas Purchased consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales. Total Gas Purchased decreased by ~~$22~~$34 million to ~~$49~~$62 million in 2012 from ~~$71~~$96 million in 2011 primarily due to:

Other Operation and Maintenance increased by $15 million to $127 million in 2012 from $112 million in 2011 primarily due to:

The aggregate amount of these increases was partially offset by a decrease of $2 million in emergency restoration costs, which were higher in 2011 largely due to the ~~cost of gas purchases for off-system sales as a result of lower average gas prices, partially offset by higher volumes purchased.~~severe winter storm in January 2011.

Depreciation and Amortization expense increased by $2$5 million to ~~$24~~$49 million in 2012 from ~~$22~~$44 million in 2011 primarily due to:

The MPSC reduced DPL’s depreciationrates in DPL’s most recent electric distribution base rate case, which is expected to result in lower annual Depreciation and Amortization expense by approximately $4.1 million beginning on July 20, 2012.

Other Taxes decreased by $2$4 million to $9$16 million in 2012 from ~~$11~~$20 million in 2011. The decrease was primarily due to rate decreases in Delaware public utility taxes (substantially offset by a corresponding decrease in Regulated T&D Electric Revenue).

DPL’s income tax expense ~~decreased~~increased by $3$1 million to $23 million in ~~the three months ended March 31, 2012.~~2012 from $22 million in 2011. DPL’s effective tax rates for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 were ~~40.0%~~40.4% and ~~42.5%~~32.8%, respectively. The ~~decrease~~increase in the effective tax rate ~~primarily~~ resulted from changes in estimates and interest related to uncertain and effectively settled tax positions, primarily related to a $4 million interest benefit recorded by DPL in the ~~first~~second quarter of ~~2011.~~2011 from a settlement reached with the IRS with respect to interest due on its federal tax liabilities related to the tax years 1996 through 2002. Also during the second quarter of 2011, DPL completed a reconciliation of its deferred taxes on certain regulatory assets and, as a result, recorded a $1 million decrease to income tax expense.

DPL’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2012 were ~~$69~~$145 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to DPL when the assets are placed in service.

In its 2011 Form 10-K, DPL presented the projected capital expenditures for the five-year period 2012 through 2016. There have been no changes in DPL’s projected capital expenditures from those presented in ~~the~~DPL’s 2011 Form 10-K. Projected capital expenditures include expenditures for distribution, transmission, and gas delivery which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by DPL to install smart meters, further automate electric distribution systems and enhance DPL’s communications infrastructure, which is referred to as the Blueprint for the Future.

In 2007, PJM ~~has~~ approved ~~PHI’s proposal to construct~~the construction of MAPP. Currently, MAPP is a ~~new~~ 152-mile, interstate transmission line proposed as part of PJM’s regional transmission expansion plan. In August 2011, PJM notified ~~PHI~~DPL that the scheduled in-service date for MAPP has been delayed from June 1, 2015 to the 2019 to 2021 time period. In light of ~~the~~this delayed in-service date, ~~for MAPP,~~ substantially all of ~~the~~DPL’s remaining anticipated capital expenditures associated with MAPP have been delayed until at least 2016 based on management’s current projections. ~~The exact revised~~As of June 30, 2012, the total expenditures for MAPP were $37 million, which management believes are fully recoverable, including prudently incurred abandoned plant costs.

PJM is currently reviewing its 2012 regional transmission expansion plan, which review includes an evaluation of the region’s overall transmission needs. This review is anticipated to take into account the results of PJM’s demand forecast and the May 2012 annual capacity market auction which secured additional capacity resources. DPL expects that PJM will release the results of its annual review process, including the further impact on the MAPP in-service date, ~~of MAPP will be evaluated as part of PJM’s 2012 Regional Transmission Expansion Plan review process.~~in August 2012.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

ACE meets the conditions set forth in General Instruction H(1)(a) and (b) to the Form 10-Q, and accordingly information otherwise required under this Item has been omitted in accordance with General Instruction H(2) to Form 10-Q.

ACE is engaged in the transmission and distribution of electricity in southern New Jersey. ACE also provides Default Electricity Supply. ACE’s service territory covers approximately 2,700 square miles and has a population of approximately 1.1 million.

ACE is a wholly owned subsidiary of Conectiv, which is wholly owned by PHI. Because each of PHI and Conectiv is a public utility holding company subject to PUHCA 2005, the relationship between each of PHI, Conectiv, PHI Service Company and ACE, as well as certain activities of ACE, are subject to FERC’s regulatory oversight under PUHCA 2005.

ACE is participating in a PHI initiative referred to as “Blueprint for the Future,” which is designed to meet the challenges of rising energy costs, concerns about the environment, improved reliability and government energy reduction goals. For a discussion of the Blueprint for the Future initiative, see PHI’s “Management’s Discussion and Analysis of Financial Condition and Results of Operations – General Overview – Blueprint for the Future.”

An important factor in ACE’s ability to earn its authorized rate of return is the willingness of the NJBPU to adequately recognize forward-looking costs in ACE’s rate structure in order to address the shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. This delay is commonly known as “regulatory lag.” ACE is currently experiencing significant regulatory lag because its investment in the rate base and its operating expenses are outpacing revenue growth. The NJBPU has approved certain rate recovery mechanisms in connection with ACE’s Infrastructure Investment Program, ~~(IIP),~~ which ACE has proposed to extend and expand. There can be no assurance that this proposal or any other attempts by ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms or any base rate cases will fully ameliorate the effects of regulatory lag. Until such time as this proposed mechanism is approved, ACE plans to file rate cases at least annually in an effort to align more closely its revenue and related cash flow levels with other operation and maintenance spending and capital investments. In future rate cases, ACE would also continue to seek cost recovery and tracking mechanisms from ~~applicable regulatory commissions~~the NJBPU to reduce the effects of regulatory lag.

The total incremental storm restoration costs of ACE associated with the derecho are currently estimated to range between $29 million and $35 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. The costs expensed will be deferred as a regulatory asset to reflect the probable recovery of these storm costs in New Jersey. ACE will be pursuing recovery of the incremental storm restoration costs in its next distribution base rate case.

The following results of operations discussion compares the ~~three~~six months ended ~~March 31,~~June 30, 2012 to the ~~three~~six months ended ~~March 31,~~June 30, 2011. All amounts in the tables (except sales and customers) are in millions of dollars.


	2012		2011		Change			2012		2011		Change
Regulated T&D Electric Revenue	$	82	$	90	$	(8	)	$	171	$	183	$	(12	)
Default Electricity Supply Revenue		170		221		(51	)		347		426		(79	)
Other Electric Revenue		4		4		—			8		10		(2	)

Total Operating Revenue	$	256	$	315	$	(59	)	$	526	$	619	$	(93	)

Regulated T&D Electric Revenue includes revenue from the distribution of electricity, including the distribution of Default Electricity Supply, to ACE’s customers within its service territory at regulated rates. Regulated T&D Electric Revenue also includes transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

The costs related to Default Electricity Supply are included in Purchased Energy. Default Electricity Supply Revenue also includes revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds issued by ACE Funding, and revenue in the form of transmission enhancement credits.


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Revenue*
Residential	$	33	$	38	$	(5	)	$	67	$	75	$	(8	)
Commercial and industrial		26		28		(2	)		58		59		(1	)
Transmission and other		23		24		(1	)		46		49		(3	)

Total Regulated T&D Electric Revenue	$	82	$	90	$	(8	)	$	171	$	183	$	(12	)


	2012		2011		Change
*Regulated T&D Electric Sales (GWh)*
Residential		944		1,078		(134	)
Commercial and industrial		1,132		1,177		(45	)
Transmission and other		12		12		—

Total Regulated T&D Electric Sales		2,088		2,267		(179	)


								2012		2011		Change
*Regulated T&D Electric Sales (GWh)*
Residential									1,860		2,057		(197	)
Commercial and industrial									2,457		2,513		(56	)
Transmission and other									22		22		—

Total Regulated T&D Electric Sales									4,339		4,592		(253	)


	2012		2011		Change			2012		2011		Change
*Regulated T&D Electric Customers (in thousands)*
Residential		481		482		(1	)		481		482		(1	)
Commercial and industrial		65		65		—			65		65		—
Transmission and other		1		1		—			1		1		—

Total Regulated T&D Electric Customers		547		548		(1	)		547		548		(1	)


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Revenue*
Residential	$	105	$	123	$	(18	)	$	209	$	231	$	(22	)
Commercial and industrial		46		61		(15	)		99		121		(22	)
Other		19		37		(18	)		39		74		(35	)

Total Default Electricity Supply Revenue	$	170	$	221	$	(51	)	$	347	$	426	$	(79	)

Other Default Electricity Supply Revenue consists primarily of (i) revenue from the resale in the PJM RTO market of energy and capacity purchased under contracts with unaffiliated NUGs, and (ii) revenue from transmission enhancement credits.


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Sales (GWh)*
Residential		800		977		(177	)		1,556		1,834		(278	)
Commercial and industrial		292		384		(92	)		610		743		(133	)
Other		6		10		(4	)		10		18		(8	)

Total Default Electricity Supply Sales		1,098		1,371		(273	)		2,176		2,595		(419	)


	2012		2011		Change			2012		2011		Change
*Default Electricity Supply Customers (in thousands)*
Residential		416		443		(27	)		407		431		(24	)
Commercial and industrial		48		53		(5	)		48		51		(3	)
Other		—		—		—			—		—		—

Total Default Electricity Supply Customers		464		496		(32	)		455		482		(27	)

Default Electricity Supply Revenue decreased by ~~$51~~$79 million primarily due to:

~~Total Default Electricity Supply Revenue for the three months ended March 31, 2012 includes~~The aggregate amount of these decreases was partially offset by an increase of $6 million as a ~~decrease~~result of ~~$2 million in unbilled revenue attributable to ACE’s BGS ($1 million decrease in net income), primarily due to lower~~higher Default Electricity Supply rates, ~~during the unbilled revenue period at March 31, 2012 as compared~~primarily due to ~~the corresponding period~~Basic Generation Charge rate increases that became effective in ~~2011. Under the BGS terms approved by the NJBPU, ACE’s BGS unbilled revenue is not included in the deferral calculation until it is billed to customers,~~June 2011 and ~~therefore has an impact on the results of operations in the period during which it is accrued.~~June 2012.

For the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011, the percentages of ACE’s total distribution sales that are derived from customers receiving Default Electricity Supply are ~~53%~~50% and ~~60%~~57%, respectively.

Purchased Energy consists of the cost of electricity purchased by ACE to fulfill its Default Electricity Supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased Energy decreased by ~~$32~~$65 million to ~~$166~~$329 million in 2012 from ~~$198~~$394 million in 2011 primarily due to:

Other Operation and Maintenance expense increased by $1$6 million to ~~$56~~$112 million in 2012 from ~~$55~~$106 million in 2011 primarily due ~~to an~~to:

Depreciation and Amortization expense decreased by $5$11 million to ~~$28~~$55 million in 2012 from ~~$33~~$66 million in 2011 primarily due to a decrease of $6$10 million in amortization of stranded costs primarily as the result of lower revenue due to rate decreases effective October 2011 for the ACE Transition Bond Charge and Market Transition Charge Tax (partially offset in Default Electricity Supply Revenue). The decrease was partially offset by an increase of $1$2 million due to utility plant additions.

Other Taxes decreased by $2$3 million to $4$8 million in 2012 from $6$11 million in 2011. The decrease was primarily due to decreased Transitional Energy Facility Assessment tax accruals due to a rate decrease effective January 2012 (partially offset by a corresponding decrease in Regulated T&D Electric Revenue).

Deferred Electric Service Costs represent (i) the ~~over-~~over or ~~under-recovery~~under recovery of electricity costs incurred by ACE to fulfill its Default Electricity Supply obligation and (ii) the ~~over-~~over or ~~under-recovery~~under recovery of New Jersey Societal Benefit Program costs incurred by ACE. The cost of electricity purchased is reported under Purchased Energy and the corresponding revenue is reported under Default Electricity Supply Revenue. The cost of New Jersey Societal Benefit Programs is reported under Other Operation and Maintenance and the corresponding revenue is reported under Regulated T&D Electric Revenue.

Other Expenses (which are net of Other Income) increased by $1 million to a net expense of $16 million in 2012 from a net expense of $15 million in 2011. The increase was primarily due to an increase of $2 million in long-term debt interest expense due to $200 million of First Mortgage Bonds issued April 2011.

ACE’s consolidated income tax expense decreased by $6$11 million to $8 million in ~~the three months ended March 31, 2012.~~2012 from $19 million in 2011. ACE’s consolidated effective tax rates for the ~~three~~six months ended ~~March 31,~~June 30, 2012 and 2011 were ~~(100)%~~33.3% and ~~45.5%~~44.2%, respectively. The decrease in the effective tax rate primarily resulted from changes in estimates and interest related to uncertain and effectively settled tax positions ~~in the first quarter of~~during 2012, primarily due to the effective settlement with the IRS with respect to the methodology used historically to calculate deductible mixed service costs.

ACE’s capital expenditures for the ~~three~~six months ended ~~March 31,~~June 30, 2012 were ~~$53~~$114 million. These expenditures were primarily related to capital costs associated with new customer services, distribution reliability and transmission. The expenditures also include an allocation by PHI of hardware and software expenditures that primarily benefit Power Delivery and are allocated to ACE when the assets are placed in service.

In its 2011 Form 10-K, ACE presented the projected capital expenditures for the five-year period 2012 through 2016. There have been no changes in ACE’s projected capital expenditures from those presented in ~~the~~ACE’s 2011 Form 10-K. Projected capital expenditures include expenditures for distribution and transmission, which primarily relate to facility replacements and upgrades to accommodate customer growth and service reliability, including capital expenditures for continuing reliability enhancement efforts. These projected capital expenditures also include expenditures for the programs undertaken by ACE to install smart meters (for which approval by the NJBPU has been deferred), further automate electric distribution systems and enhance ACE’s communications infrastructure, which is referred to as the Blueprint for the Future.

In 2009, the DOE announced a $168 million award to PHI under the American Recovery and Reinvestment Act of 2009 for the implementation of an AMI system, direct load control, distribution automation, and communications infrastructure, of which $19 million was for ACE’s service territory.

In April 2010, ACE and the DOE signed agreements formalizing ACE’s $19 million share of the $168 million award. Of the $19 million, $12 million is ~~expected to offset incurred and projected~~being used for Blueprint for the Future and other capital expenditures of ACE. The remaining $7 million ~~will be~~is being used to offset incremental expenses associated with direct load control and other programs. During the ~~first quarter of~~six months ended June 30, 2012, ACE received award payments of $1$3 million. ~~Cumulative~~The cumulative award payments received by ACE ~~since April 2010,~~as of June 30, 2012, were ~~$10~~$11 million.

The IRS has announced that, to the extent these grants are expended on capital items, they will not be considered taxable income.

~~Item 3.~~

~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

Risk management policies for PHI and its subsidiaries are determined by PHI’s Corporate Risk Management Committee (CRMC), the members of which are PHI’s Chief Risk Officer, Chief Operating Officer, Chief Financial Officer, General Counsel, Chief Information Officer and other senior executives. The CRMC monitors interest rate fluctuation, commodity price fluctuation, credit risk exposure, and sets risk management policies that establish limits on unhedged risk and determine risk reporting requirements. For information about PHI’s derivative activities, other than the information otherwise disclosed herein, refer to Note (2), “Significant Accounting Policies – Accounting For Derivatives,” Note (15), “Derivative Instruments and Hedging Activities,” and Note (20), “Discontinued Operations,” of the consolidated financial statements of PHI included in its 2011 Form 10-K, ~~, “Part~~Part I, Item 7A. Quantitative and Qualitative Disclosures About Market ~~Risk”~~Risk in PHI’s 2011 Form 10-K, and Note (13), “Derivative Instruments and Hedging Activities,” of the consolidated financial statements of PHI included herein.

The Pepco Energy Services segment engages in commodity risk management activities to reduce its financial exposure to changes in the value of its assets and obligations due to commodity price fluctuations. Certain of these risk management activities are conducted using instruments classified as derivatives based on Financial Accounting Standards Board (FASB) guidance on derivatives and hedging, (ASC 815). Pepco Energy Services also manages commodity risk with contracts that are not classified as derivatives.

PHI’s risk management policies place oversight at the senior management level through the CRMC, which has the responsibility for establishing corporate compliance requirements for energy market participation. PHI collectively refers to these energy market activities, including its commodity risk management activities, as “energy commodity” activities. PHI uses a value-at-risk (VaR) model to assess the market risk of the energy commodity activities of Pepco Energy Services. PHI also uses other measures to limit and monitor risk in its energy commodity activities, including limits on the nominal size of positions and periodic loss limits. VaR represents the potential fair value loss on energy contracts or portfolios due to changes in market prices for a specified time period and confidence level. PHI uses a delta-gamma VaR estimation model. The other parameters include a 95 percent, one-tailed confidence level and a one-day holding period. Since VaR is an estimate, it is not necessarily indicative of actual results that may occur.

The table below provides the VaR associated with energy contracts of the Pepco Energy Services segment for the ~~three~~six months ended ~~March 31,~~June 30, 2012 in millions of dollars:

Pepco Energy Services purchases electric and natural gas futures, swaps, options and forward contracts to hedge price risk in connection with the purchase of physical natural gas and electricity for distribution to customers. Pepco Energy Services accounts for its derivatives as either cash flow hedges of forecasted transactions or they are marked to market through current earnings. Forward contracts that meet the requirements for normal purchase and normal sale accounting under FASB guidance on derivatives and hedging are recorded on an accrual basis.

The following table provides information on the credit exposure on competitive wholesale energy contracts, net of collateral, to wholesale counterparties as of ~~March 31,~~June 30, 2012, in millions of dollars:

For information regarding “Interest Rate Risk,” please refer to Part I, Item ~~7A, “Quantitative~~7A. Quantitative and Qualitative Disclosures About Market Risk,” in Pepco Holdings’ 2011 Form 10-K.

INFORMATION FOR THIS ITEM IS NOT REQUIRED FOR PEPCO, DPL AND ACE AS THEY MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND THEREFORE ARE FILING THIS FORM WITH A REDUCED FILING FORMAT.

Each Reporting Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in such Reporting Company’s reports under the Securities Exchange Act of 1934, as amended (Exchange Act), is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to management of such Reporting Company, including the Reporting Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO), as appropriate, to allow timely decisions regarding required disclosure. This control system, no matter how well designed and operated, can provide only reasonable assurance that the objectives of the control system are met. Such Reporting Company’s disclosure controls and procedures were designed to provide reasonable assurance of achieving their stated objectives. Under the supervision, and with the participation of management, including the CEO and the CFO, each Reporting Company has evaluated the effectiveness of the design and operation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of ~~March 31,~~June 30, 2012, and, based upon this evaluation, the CEO and the CFO of such Reporting Company have concluded that these disclosure controls and procedures are effective to provide reasonable assurance that material information relating to such Reporting Company and its subsidiaries that is required to be disclosed in reports filed with, or submitted to, the SEC under the Exchange Act (i) is recorded, processed, summarized and reported within the time periods specified by the SEC rules and forms and (ii) is accumulated and communicated to management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the CEO and CFO of each Reporting Company, each such Reporting Company has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the three months ended ~~March 31,~~June 30, 2012, and has concluded there was no change in such Reporting Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, such Reporting Company’s internal control over financial reporting.

Other than ordinary routine litigation incidental to its and its subsidiaries’ business, PHI is not a party to, and its subsidiaries’ property is not subject to, any material pending legal proceedings except as described in Note (15), “Commitments and Contingencies,” to the consolidated financial statements of PHI included herein, which description is incorporated by reference herein.

Other than ordinary routine litigation incidental to its business, Pepco is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (11), “Commitments and Contingencies,” to the financial statements of Pepco included herein, which description is incorporated by reference herein.

Other than ordinary routine litigation incidental to its business, DPL is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note (13), “Commitments and Contingencies,” to the financial statements of DPL included herein, which description is incorporated by reference herein.

Other than ordinary routine litigation incidental to its business, ACE is not a party to, and its property is not subject to, any material pending legal proceedings except as described in Note ~~(11)~~(12), “Commitments and Contingencies,” to the consolidated financial statements of ACE included herein, which description is incorporated by reference herein.

For a discussion of the risk factors applicable to each Reporting Company, please refer to “Part I, Item 1A. Risk Factors” in each Reporting Company’s 2011 Form 10-K. There have been no material changes to any Reporting Company’s risk factors as disclosed in the 2011 Form 10-K, except as set forth below.

The provisions contained in certain forward sale agreements entered into by PHI in connection with its March 2012 equity offering subject PHI to risks if certain events occur. (PHI only)

In March 2012, PHI entered into forward sale agreements with a forward counterparty, relating to the issuance and sale by PHI, and the purchase by the forward counterparty, of an aggregate of up to 17.9 million shares of PHI common stock. Upon physical settlement of the forward sale agreements, PHI will receive from the forward counterparty a stated per share amount of cash, subject to certain adjustments pursuant to the terms of the forward sale agreements.

The forward counterparty may accelerate settlement of the forward sale agreements and require PHI to physically settle the forward sale agreements on a date of its choosing under certain circumstances set forth in the forward sale agreements. Such a decision could be made regardless of PHI’s interests, including its need for capital. In the case of such an acceleration, PHI could be required to issue and deliver shares of common stock under the physical settlement provisions of the forward sale agreements regardless of its capital needs or earlier than when PHI would otherwise have elected to settle the forward sale agreements. Moreover, PHI would no longer be permitted to elect that cash or net share settlement apply, which could result in dilution to PHI’s earnings per share and return on equity.

Except in certain circumstances, PHI has the right to elect physical, cash or net share settlement under the forward sale agreements. Delivery of any shares upon physical settlement or net share settlement could result in dilution to PHI’s earnings per share and return on equity. If PHI elects cash or net share settlement, the forward counterparty or one of its affiliates would likely purchase shares of common stock in open market transactions over a period of time in connection with such settlement and its related hedge position. If the price at which the forward counterparty or its affiliate makes these purchases exceeds the applicable forward sale price, then PHI would be required to deliver to the forward counterparty an amount equal to the difference in cash (in the case of cash settlement) or in a number of shares with a value equal to such difference (in the case of net share settlement). Accordingly, PHI may need to deliver a substantial amount of cash or a substantial number of shares of common stock, which could result in dilution to PHI’s earnings per share and return on equity. Furthermore, these purchases of common stock by the forward counterparty or its affiliate could increase the trading price of PHI’s common stock above the trading prices that would otherwise prevail. This, in turn, could increase the amount of cash, in the case of cash settlement, or the number of shares, in the case of net share settlement, PHI would owe, if any, to the forward counterparty upon settlement of the forward sale agreements.

PHI’s subsidiaries are subject to collective bargaining agreements that could impact their business and operations.

As of December 31, 2011, 55% of employees of PHI and its subsidiaries, collectively, were represented by various labor unions. PHI’s subsidiaries are parties to five collective bargaining agreements with four local unions that represent these employees. Collective bargaining agreements are generally renegotiated every three to five years, and the risk exists that there could be a work stoppage after expiration of an agreement until a new collective bargaining agreement has been reached. Labor negotiations typically involve bargaining over wages, benefits and working conditions, including management rights. PHI’s last work stoppage, a two-week strike by DPL’s employees, occurred in 2010. During that strike, DPL used management and contractor employees to maintain essential operations.

Four of the collective bargaining agreements to which PHI’s subsidiaries are a party will expire within the next four years, and the fifth agreement had been set to expire on June 1, 2012. However, prior to its expiration, the parties have amended this agreement to extend its expiration date, which is currently August 19, 2012. Further extensions may be possible as Pepco is currently negotiating with the labor union to enter into a new collective bargaining agreement. Although PHI believes that a protracted work stoppage is unlikely, if Pepco is unable to come to terms with the labor union on a new collective bargaining agreement, the labor union’s members may vote to terminate the agreement and cease working thereunder. Such an event could result in a disruption of Pepco’s operations, which could, in turn, have a material adverse effect upon the business, results of operations, cash flow and financial condition of Pepco and PHI.

The agreements that govern PHI’s primary credit facility and its term loan agreement contain a consolidated indebtedness covenant that may limit discretion of each borrower to incur indebtedness or reduce its equity.

Under the terms of PHI’s primary credit facility, of which each Reporting Company is a borrower, and of PHI’s term loan agreement entered into in April 2012, the consolidated indebtedness of a borrower cannot exceed 65% of its consolidated capitalization. If a borrower’s equity were to decline or its debt were to increase to a level that caused its debt to exceed this limit, lenders under the credit facility would be entitled to refuse any further extension of credit and to declare all of the outstanding debt under the credit facility immediately due and payable. To avoid such a default, a waiver or renegotiation of this covenant would be required, which would likely increase funding costs and could result in additional covenants that would restrict the affected Reporting Company’s operational and financing flexibility.

Each borrower’s ability to comply with this covenant is subject to various risks and uncertainties, including events beyond the borrower’s control. For example, events that could cause a reduction in PHI’s equity include, without limitation, a further write-down of PHI’s cross-border energy lease investments or a significant write-down of PHI’s goodwill. Even if each borrower is able to comply with this covenant, the restrictions on its ability to operate its business in its sole discretion could harm its and PHI’s business by, among other things, limiting the borrower’s ability to incur indebtedness or reduce equity in connection with financings or other corporate opportunities that it may believe would be in its best interests or the interests of PHI’s stockholders to complete.

PHI utility subsidiaries are subject to comprehensive regulation which may significantly affect their operations. PHI’s utility subsidiaries may be subject to fines, penalties and other sanctions for the inability to meet these requirements.

The regulated utilities that comprise Power Delivery are subject to extensive regulation by various federal, state and local regulatory agencies. Each of Pepco, DPL and ACE is regulated by the state agencies for each service territory in which it operates, with respect to, among other things, the manner in which utility service is provided to customers, as well as rates it can charge customers for the distribution and supply of electricity (and, additionally for DPL, the distribution and supply of natural gas). NERC has also established, and FERC has approved, reliability standards with regard to the bulk power system that impose certain operating, planning and cyber security requirements on Pepco, DPL, ACE and Pepco Energy Services. Further, FERC regulates the electricity transmission facilities of Pepco, DPL and ACE.

Approval of these regulators is required in connection with changes in rates and other aspects of the utilities’ operations. These regulatory authorities, and NERC with respect to electric reliability, are empowered to impose financial penalties, fines and other sanctions against the utilities for non-compliance with certain rules and regulations. In this regard, in December 2011, the MPSC sanctioned Pepco related to its reliability in connection with major storm events that occurred in July and August

2010. These sanctions included imposing a fine on Pepco and requiring Pepco to file a work plan detailing, among other things, its reliability improvement objectives and progress in meeting those objectives, while raising the possibility of additional fines or cost recovery disallowances for failing to meet those objectives. The MPSC also stated that it would consider in Pepco’s latest Maryland retail base rate case the potential disallowance of the recovery of costs which may be determined to have been imprudently incurred. In this base rate case, the MPSC set rates at a level that was not adequate to recover costs that Pepco will incur during the period the rates are in effect.

NERC’s eight regional oversight entities, including ReliabilityFirst Corporation (RFC), of which Pepco, DPL, ACE and Pepco Energy Services are members, and Northeast Power Coordinating Council (NPCC), of which Pepco Energy Services is a member, are charged with the day-to-day implementation and enforcement of NERC’s standards. RFC and NPCC perform compliance audits on entities registered with NERC based on reliability standards and criteria established by NERC. NERC, RFC and NPCC also conduct compliance investigations in response to a system disturbance, complaint, or possible violation of a reliability standard identified by other means. Pepco, DPL, ACE and Pepco Energy Services are subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards requested by FERC to increase the number of assets (including cyber security assets) subject to NERC cyber security standards that are designated as “critical assets.” From time to time, Pepco, DPL and ACE have entered into settlement agreements with RFC resolving alleged violations and resulting in fines. There can be no assurance that additional settlements resolving issues related to RFC or NPCC requirements will not occur in the future. The imposition of additional sanctions and civil fines by these enforcement entities could have a material adverse effect on a Reporting Company’s results of operations, cash flow and financial condition.

PHI’s utility subsidiaries, as well as Pepco Energy Services, are also required to have numerous permits, approvals and certificates from governmental agencies that regulate their businesses. Although PHI believes that each of its subsidiaries has, and each of Pepco, DPL and ACE believes it has, obtained or sought renewal of the material permits, approvals and certificates necessary for its existing operations and that its business is conducted in accordance with applicable laws, PHI is unable to predict the impact that future regulatory activities may have on its business. Changes in or reinterpretations of existing laws or regulations, or the imposition of new laws or regulations, may require any one or more of PHI’s subsidiaries to incur additional expenses or significant capital expenditures or to change the way it conducts its operations.

PHI’s profitability is largely dependent on its ability to recover costs of providing utility services to its customers and to earn an adequate return on its capital investments. The failure of PHI to obtain timely recognition of costs in its rates may have a negative effect on PHI’s results of operations and financial condition.

The public service commissions which regulate PHI’s utility subsidiaries establish utility rates and tariffs intended to provide the utility the opportunity to obtain revenues sufficient to recover its prudently incurred costs, together with a reasonable return on investor supplied capital. These regulatory authorities also determine how Pepco, ACE and DPL recover from their customers purchased power and natural gas and other operating costs, including transmission and other costs. The utilities cannot change their rates without approval by the applicable regulatory authority. There can be no assurance that the regulatory authorities will consider all costs to have been prudently incurred, nor can there be any assurance that the regulatory process by which rates are determined will always result in rates that achieve full and timely recovery of costs or a just and reasonable rate of return on investments. In addition, if the costs incurred by any of the utilities in operating its business exceed the amounts on which its approved rates are based, the financial results of that utility, and correspondingly PHI, may be adversely affected.

PHI’s utility subsidiaries are also exposed to “regulatory lag,” which refers to a shortfall in revenues due to the delay in time or “lag” between when costs are incurred and when they are reflected in rates. All of PHI’s utilities are currently experiencing significant regulatory lag because their investment in the rate base and their operating expenses are outpacing revenue growth. PHI anticipates that this trend will continue for the foreseeable future. The failure to timely recognize costs in rates could have a material adverse effect on PHI’s and each utility subsidiary’s business, results of operations, cash flow and financial condition.

In their most recent rate cases, Pepco (in the District of Columbia and Maryland), DPL (in Maryland and Delaware) and ACE (in New Jersey) have proposed mechanisms that would track reliability and other expenses and permit each utility to make adjustments in its approved rates to account for prudent investments as made, thereby seeking to reduce the magnitude of regulatory lag. However, in July 2012, the MPSC did not approve in substantial part requests by Pepco and DPL to implement regulatory lag mitigation mechanisms. In New Jersey, the NJBPU has previously approved a similar mechanism, and ACE currently has an update and expansion of that previously approved mechanism pending before the NJPBU. There can be no assurance that any of the outstanding proposals or any other attempts by Pepco, DPL and ACE to mitigate regulatory lag will be approved, or that even if approved, the rate recovery mechanisms will fully ameliorate the effects of regulatory lag. If necessary to address in whole or in part the problem of regulatory lag, each utility can file (and Pepco and DPL presently intend to file) base rate cases annually (or even more frequently) to seek to align its revenue and related cash flow levels allowed by the applicable public service commissions with operation and maintenance spending and capital investments. The inability of PHI’s utility subsidiaries to obtain relief from the impact of regulatory lag through base rate cases or otherwise may have an adverse effect on the business, results of operations, cash flow and financial condition of PHI and each utility subsidiary.

The documents listed below are being filed, furnished or submitted on behalf of PHI, Pepco, DPL and/or ACE, as indicated. The warranties, representations and covenants contained in any of the agreements included or incorporated by reference herein or which appear as exhibits hereto should not be relied upon by buyers, sellers or holders of PHI’s or its subsidiaries’ securities and are not intended as warranties, representations or covenants to any individual or entity except as specifically set forth in such agreement.


Exhibit No.	Registrant(s)	Description of Exhibit	Reference

10.8	PHI	Form of ~~2012 Restricted Stock Unit~~Note under $200,000,000 PHI Term Loan Agreement ~~(Performance Based/162(m)) under the PHI Long-Term Incentive Plan~~	Included in Exhibit ~~10.38 to PHI’s Form 10-K, February 24, 2012.~~10.7 hereto.

10.9	~~PHI~~DPL	~~Pepco Holdings,~~Purchase Agreement, dated June 19, 2012, among DPL, and J.P. Morgan Securities LLC, Credit Suisse Securities (USA) LLC, and SunTrust Robinson Humphrey Inc. ~~Long-Term Incentive Plan (as amended and restated)~~as representatives of the several Underwriters named therein	Exhibit ~~10.5~~1.1 to ~~PHI’s~~DPL’s Form ~~10-K, March 2, 2009.~~

~~10.9.1~~	~~PHI~~	~~Amendment to the Pepco Holdings, Inc. Long-Term Incentive Plan~~	~~Exhibit 10.2.1 to PHI’s Form 10-K, February 24, 2012.~~

~~10.10~~	~~PHI~~	~~Form of Election with Respect to Stock Tax Withholding~~	~~Exhibit 10.39 to PHI’s Form 10-K, February 24, 2012.~~

~~10.11~~	~~PHI~~	~~PHI Named Executive Officer 2012 Compensation Determinations~~	~~Exhibit 10.40 to PHI’s Form 10-K, February 24,~~8-K, June 20, 2012.

12.1	PHI	Statements Re: Computation of Ratios	Filed herewith.

12.2	Pepco	Statements Re: Computation of Ratios	Filed herewith.

12.3	DPL	Statements Re: Computation of Ratios	Filed herewith.

12.4	ACE	Statements Re: Computation of Ratios	Filed herewith.

31.1	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.

31.2	PHI	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

31.3	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.

31.4	Pepco	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

31.5	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.

31.6	DPL	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

31.7	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Executive Officer	Filed herewith.

31.8	ACE	Rule 13a-14(a)/15d-14(a) Certificate of Chief Financial Officer	Filed herewith.

32.1	PHI	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

32.2	Pepco	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

32.3	DPL	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

32.4	ACE	Certificate of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350	Furnished herewith.

~~101.INS~~101. INS	PHI Pepco DPL ACE	XBRL Instance Document	Submitted herewith.

~~101.SCH~~101. SCH	PHI Pepco DPL ACE	XBRL Taxonomy Extension Schema Document	Submitted herewith.

~~101.CAL~~101. CAL	PHI Pepco DPL ACE	XBRL Taxonomy Extension Calculation Linkbase Document	Submitted herewith.


~~Exhibit No.~~	~~Registrant(s)~~	~~Description of Exhibit~~	~~Reference~~

~~101.DEF~~101. DEF	PHI Pepco DPL ACE	XBRL Taxonomy Extension Definition Linkbase Document	Submitted herewith.

~~101.LAB~~101. LAB	PHI Pepco DPL ACE	XBRL Taxonomy Extension Label Linkbase Document	Submitted herewith.

~~101.PRE~~101. PRE	PHI Pepco DPL ACE	XBRL Taxonomy Extension Presentation Linkbase Document	Submitted herewith.

Regulation S-K Item 10(d) requires registrants to identify the physical location, by SEC file number reference, of all documents incorporated by reference that are not included in a registration statement and have been on file with the SEC for more than five years. The SEC file number references for ~~PHI, those of its subsidiaries that are currently registrants, Conectiv and ACE Funding~~each Reporting Company are provided below:

Certain instruments defining the rights of the holders of long-term debt of Pepco have not been filed as exhibits in accordance with Regulation S-K Item 601(b)(4)(iii) because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis. Pepco agrees to furnish to the SEC upon request a copy of any such instruments omitted by it.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, each of the registrants has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Commission File Number	Exact Name of Registrant as specified in its Charter, State or Other Jurisdiction of Incorporation, Address of Principal Executive Offices, Zip Code and Telephone Number (Including Area Code)	I.R.S. Employer Identification Number
001-31403	PEPCO HOLDINGS, INC. (Pepco Holdings or PHI), a Delaware corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	52-2297449

001-01072	POTOMAC ELECTRIC POWER COMPANY (Pepco), a District of Columbia and Virginia corporation 701 Ninth Street, N.W. Washington, D.C. 20068 Telephone: (202)872-2000	53-0127880

001-01405	DELMARVA POWER & LIGHT COMPANY (DPL), a Delaware and Virginia corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	51-0084283

001-03559	ATLANTIC CITY ELECTRIC COMPANY (ACE), a New Jersey corporation 500 North Wakefield Drive Newark, DE 19702 Telephone: (202)872-2000	21-0398280


	Large Accelerated Filer	Accelerated Filer	Non- Accelerated Filer	Smaller Reporting Company
Pepco Holdings	x	¨	¨	¨
Pepco	¨	¨	x	¨
DPL	¨	¨	x	¨
ACE	¨	¨	x	¨


				Page

	Glossary of Terms		i

		Forward-Looking Statements			1

PART I		FINANCIAL INFORMATION			3

	Item 1.	- Financial Statements			3

	Item 2.	- Management’s Discussion and Analysis of Financial Condition and Results of Operations			~~104~~117

	Item 3.	- Quantitative and Qualitative Disclosures About Market Risk			~~149~~178

	Item 4.	- Controls and Procedures			180

~~Item 4.~~ PART II		~~- Controls and Procedures~~OTHER INFORMATION			~~151~~180

~~PART II~~	Item 1.	~~OTHER INFORMATION~~- Legal Proceedings			~~151~~180

~~Item 1.~~	Item 1A	- ~~Legal Proceedings~~Risk Factors			~~151~~181

~~Item 1A~~			~~- Risk Factors~~			~~152~~

Item 2.	- Unregistered Sales of Equity Securities and Use of Proceeds		~~153~~184

	Item 3.	- Defaults Upon Senior Securities			~~153~~184

	Item 4.	- Mine Safety Disclosures			~~153~~184

	Item 5.	- Other Information			~~153~~185

	Item 6.	- Exhibits			~~154~~186

	Signatures				~~157~~189


Registrant		Number of Shares of Common Stock of the ~~the~~ Registrant Outstanding at ~~April~~July 25, 2012
Pepco Holdings		~~228,280,444~~228,885,730 ($.01 par value)

Pepco		100 ($.01 par value) (a)

DPL		1,000 ($2.25 par value) (b)

ACE		8,546,017 ($3.00 par value) (b)


Term	Definition
2011 Form 10-K	The Annual Report on Form 10-K for the year ended December 31, 2011, as amended, for each Reporting Company, as applicable
ACE	Atlantic City Electric Company
ACE Funding	Atlantic City Electric Transition Funding LLC
AMI	Advanced metering infrastructure
AOCL	Accumulated Other Comprehensive Loss
ASC	Accounting Standards Codification
BGS	Basic Generation Service (the supply of electricity by ACE to retail customers in New Jersey who have not elected to purchase electricity from a competitive supplier)
Bondable Transition Property	The principal and interest payments on the Transition Bonds and related taxes, expenses and fees
BSA	Bill Stabilization Adjustment
Calpine	Calpine Corporation
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
Conectiv	Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
CRMC	PHI’s Corporate Risk Management Committee
CSA	Credit Support Annex
DCPSC	District of Columbia Public Service Commission
DDOE	District of Columbia Department of the Environment
DEDA	Delaware Economic Development Authority
Default Electricity Supply	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue	Revenue primarily from Default Electricity Supply
DOE	U.S. Department of Energy
DPL	Delmarva Power & Light Company
DPSC	Delaware Public Service Commission
EDCs	Electric distribution companies
EmPower Maryland	A Maryland demand-side management program for Pepco and DPL
~~Energy Services~~	~~Energy savings performance contracting services provided principally to federal, state~~ ~~and local government customers, and designing, constructing and operating combined~~ ~~heat and power, and central energy plants by Pepco Energy Services~~
EPA	~~U.S~~U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
GCR	Gas Cost Rate
GWh	Gigawatt hour
IDA	Industrial Development Authority of the City of Alexandria, Virginia
IIP	ACE’s Infrastructure Investment Program
IRS	Internal Revenue Service
ISDA	International Swaps and Derivatives Association Master Agreement
ISRA	New Jersey’s Industrial Site Recovery Act
LIBOR	London Interbank Offered Rate
MAPP	Mid-Atlantic Power Pathway
Market Transition Charge Tax	Revenue ACE receives and pays to ACE Funding to recover income taxes associated with Transition Bond Charge revenue
~~MDC~~	~~MDC Industries, Inc.~~
MFVRD	Modified fixed variable rate design
~~Mirant~~		~~Mirant Corporation~~
MMBtu	One Million British Thermal Units
MPSC	Maryland Public Service Commission


Term		Definition
MWh		Megawatt hour
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
~~NPL~~NPCC		National Priorities List, which, 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 siteNortheast Power Coordinating Council
NUGs		Non-utility generators
NYMEX		New York Mercantile Exchange
PCI		Potomac Capital Investment Corporation and its subsidiaries
Pepco		Potomac Electric Power Company
Pepco Energy Services		Pepco Energy Services, Inc. and its subsidiaries
Pepco Holdings or PHI		Pepco Holdings, Inc.
PHI Retirement Plan		PHI’s noncontributory retirement plan
PJM		PJM Interconnection, LLC
PJM RTO		PJM regional transmission organization
Power Delivery		PHI’s Power Delivery Business
PPA		Power purchase agreement
PRP		Potentially responsible party
PUHCA 2005		Public Utility Holding Company Act of 2005
RECs		Renewable energy credits
Regulated T&D Electric Revenue		Revenue from the transmission and the distribution of electricity to PHI’s customers within its service territories at regulated rates
Reporting Company		PHI, Pepco, DPL or ACE
RFC		ReliabilityFirst Corporation
RI/FS		Remedial investigation and feasibility study
RIM		Reliability investment recovery mechanism
ROE		Return on equity
RPS		Renewable Energy Portfolio Standards
SEC		Securities and Exchange Commission
SOCAs		Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey

SOS		Standard Offer Service, how Default Electricity Supply is referred to in Delaware, the District of Columbia and Maryland
SRECs		Solar renewable energy credits
SPCC		Spill Prevention, Control, and Countermeasure plans, required pursuant to federal regulations requiring plans for facilities using oil-containing equipment in proximity to surface waters
Transition Bond Charge		Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds		Transition Bonds issued by ACE Funding
VADEQ		Virginia Department of Environmental Quality
VaR		Value at Risk


	Six Months Ended June 30, 2012
	*(millions of dollars)*
	Power Delivery		Pepco Energy Services			Other Non- Regulated		Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	2,039	$	413		$	27	$	(8	)	$	2,471
Operating Expenses (b)		1,814		382	(c)		3		(19	)		2,180
Operating Income		225		31			24		11			291
Interest Income		—		—			2		(2	)		—
Interest Expense		106		1			7		16			130
Other Income		16		—			1		1			18
Preferred Stock Dividends		—		—			1		(1	)		—
Income Tax Expense		34		12			2		1			49
Net Income (Loss) from Continuing Operations		101		18			17		(6	)		130
Total Assets		11,734		536			1,499		1,652			15,421
Construction Expenditures	$	565	$	10		$	—	$	14		$	589


	Six Months Ended June 30, 2011
	*(millions of dollars)*
	Power Delivery		Pepco Energy Services		Other Non- Regulated			Corporate and Other (a)			PHI Consolidated
Operating Revenue	$	2,342	$	688	$	28		$	(8	)	$	3,050
Operating Expenses (b)		2,088		659		(36	)(c)		(12	)		2,699
Operating Income		254		29		64			4			351
Interest Income		—		—		2			(2	)		—
Interest Expense		102		2		7			14			125
Other Income (Expenses)		16		2		(1	)		2			19
Preferred Stock Dividends		—		—		1			(1	)		—
Income Tax Expense (Benefit) (d)		49		11		32			(4	)		88
Net Income (Loss) from Continuing Operations		119		18		25	(c)		(5	)		157
Total Assets (excluding Assets Held For Sale)		10,803		615		1,461			1,354			14,233
Construction Expenditures	$	364	$	7	$	—		$	16		$	387


	Six Months Ended June 30,
	2012		2011
	(millions of dollars, except per share data)
Income (Numerator):
Net income from continuing operations	$	130	$	157
Net income from discontinued operations		—		1

Net income	$	130	$	158

Shares (Denominator) (in millions):
Weighted average shares outstanding for basic computation:
Average shares outstanding		228		226
Adjustment to shares outstanding		—		—

Weighted Average Shares Outstanding for Computation of Basic Earnings Per Share of Common Stock		228		226
Net effect of potentially dilutive shares (a)		1		—

Weighted Average Shares Outstanding for Computation of Diluted Earnings Per Share of Common Stock		229		226

Basic and Diluted Earnings per Share
Earnings per share of common stock from continuing operations	$	0.57	$	0.69
Earnings per share of common stock from discontinued operations		—		0.01

Basic and diluted earnings per share	$	0.57	$	0.70


	As of March 31, 2011
Contracts	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	*(millions of dollars)*
Energy commodity (a)	$	62	$	38		38 months
Interest rate		11		1		257 months

Total	$	73	$	39


	As of June 30, 2011
Contracts	Accumulated Other Comprehensive Loss After-tax		Portion Expected to be Reclassified to Income during the Next 12 Months		Maximum Term
	*(millions of dollars)*
Energy commodity (a)	$	49	$	35		35 months
Interest rate		11		1		254 months

Total	$	60	$	36


	Fair Value Measurements at December 31, 2011
Description	Total		Quoted Prices in Active Markets for Identical Instruments (Level 1) (a)		Significant Other Observable Inputs (Level 2) (a)		Significant Unobservable Inputs (Level 3)
	*(millions of dollars)*
ASSETS
Cash equivalents
Treasury fund	$	114	$	114	$	—	$	—
Executive deferred compensation plan assets
Money market funds		18		18		—		—
Life insurance contracts		60		—		43		17

	$	192	$	132	$	43	$	17

LIABILITIES
Derivative instruments (b)
Electricity (c)	$	32	$	—	$	32	$	—
Natural gas (d)		67		50		—		17
Capacity		1		—		1		—
Executive deferred compensation plan liabilities
Life insurance contracts		28		—		28		—

	$	128	$	50	$	61	$	17


	Six Months Ended June 30,
	2012		��	2011
	*(millions of dollars)*
Total net gains included in income for the period	$	2		$	5

Change in unrealized gains relating to assets still held at reporting date	$	2		$	2


	Commodity Derivatives (a)		Treasury Lock (b)		Prior Service Costs (b)		Total
	*(millions of dollars)*
For the three months ended March 31, 2012	$	5	$	—	$	1	$	6
For the three months ended March 31, 2011	$	11	$	—	$	—	$	11


	Commodity Derivatives		Treasury Lock (a)		Pension and Other Postretirement Benefit Plans (a)			Total
	*(millions of dollars)*
For the three months ended June 30, 2012 (b)	$	6	$	—	$	(4	)	$	2
For the three months ended June 30, 2011 (b)		9		—		(2	)		7
For the six months ended June 30, 2012 (c)	$	11	$	—	$	(3	)	$	8
For the six months ended June 30, 2011 (c)		19		—		(1	)		18


Registrants	Page No.

Pepco Holdings		~~105~~118

Pepco		~~130~~155

DPL		~~137~~163

ACE		~~144~~172


	As of December 31, 2011
	*(millions of dollars)*
Type	PHI Parent		Pepco		DPL		ACE		ACE Funding		Pepco Energy Services		PHI Consolidated
Variable Rate Demand Bonds	$	—	$	—	$	105	$	23	$	—	$	18	$	146
Commercial Paper		465		74		47		—		—		—		586

Total Short-Term Debt	$	465	$	74	$	152	$	23	$	—	$	18	$	732

Current Portion of Long-Term Debt and Project Funding	$	—	$	—	$	66	$	—	$	37	$	9	$	112


	Consolidated PHI		PHI Parent		Utility Subsidiaries
	*(millions of dollars)*
Credit Facility (Total Capacity)	$	1,500	$	750	$	750
Less: Letters of Credit issued		7		2		5
Commercial Paper outstanding		858		521		337

Remaining Credit Facility Available		635		227		408
Cash Invested in Money Market Funds (a)		44		—		44

Total Cash and Credit Facility Available	$	679	$	227	$	452


	Reacquisitions
	2012		2011
	*(millions of dollars)*
ACE securitization bonds due 2011-2012	$	9	$	9

	$	9	$	9


	2012			2011
Sales to District of Columbia customers		26	%		29	%
Sales to Maryland customers		43	%		47	%


	VaR (a)
95% confidence level, one-day holding period, one-tailed
Period end	$	1
Average for the period	$	1
High	$	1
Low	$	1


~~Rating~~	~~Exposure Before~~ ~~Credit~~ ~~Collateral (b)~~		~~Credit~~ ~~Collateral (c)~~		~~Net~~ ~~Exposure~~		~~Number of~~ ~~Counterparties~~ ~~Greater Than~~ ~~10% (d)~~		~~Net Exposure of~~ ~~Counterparties~~ ~~Greater~~ ~~Than 10%~~
~~Investment Grade (a)~~	$	—	$	—	$	—		2	$	—
~~Non-Investment Grade~~		—		—		—		—		—
~~No External Ratings~~		—		—		—		1		—
~~Credit reserves~~		—		—		—		—		—


Rating	Exposure Before Credit Collateral (b)		Credit Collateral (c)		Net Exposure		Number of Counterparties Greater Than 10% (d)		Net Exposure of Counterparties Greater Than 10%
Investment Grade (a)	$	1	$	—	$	1		2	$	1
Non-Investment Grade		—		—		—		—		—
No External Ratings		—		—		—		—		—
Credit reserves		—		—		—		—		—


			PEPCO HOLDINGS, INC. (PHI) POTOMAC ELECTRIC POWER COMPANY (Pepco) DELMARVA POWER & LIGHT COMPANY (DPL) ATLANTIC CITY ELECTRIC COMPANY (ACE) (Registrants)

~~May 3,~~August 6, 2012	By	/s/ FREDERICK J. BOYLE
		Frederick J. Boyle
		Senior Vice President and Chief Financial Officer, PHI, Pepco and DPL Chief Financial Officer, ACE